The Washington Report


When the ERQ started publishing almost 10 years ago, the first edition of every year was scheduled to review the highlights of the energy regulation year for both Canada and the United States. The American version was called the Washington Report. It was authored by Robert Fleishman, then the editor of the Energy Law Journal published by the Energy Bar Association in Washington. It appeared every year until last year when we ran into a difficulty known as Covid-19. This year the Washington Report is back. We thank Robert for his usual skill and dedication. We have learned over the last few years how interconnected the energy sector in Canada is with the American side of the industry. And we have also followed closely the cross-border disputes that seem to crop up every year. This year is no different.

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Energy regulatory developments in the United States influence numerous sectors of the energy industry and address a wide range of issues. We report on key federal and state energy and environmental regulatory and litigation developments in the United States from mid-2019 through early 2021, which we expect to be of interest to readers of the ERQ. This report does not address developments with respect to the Biden Administration.



On December 27, 2020, President Trump signed into law a massive omnibus appropriations and $900 billion COVID-19 relief bill.[1] Two key sections of the bill are significant for energy and infrastructure market participants and investors: (1) Division Z, the Energy Act of 2020 (Energy Act of 2020), a bipartisan energy package that represents the first substantial update to U.S. energy policy in 13 years; and (2) Division R, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (PIPES Act of 2020), which contains numerous regulatory changes impacting large-scale liquefied natural gas (LNG) facilities, gas gathering pipelines, and gas distribution facilities.

The Energy Act of 2020 is a bipartisan, bicameral law touted as the first comprehensive national energy policy update since the Energy Independence and Security Act of 2007. It includes numerous measures, but principally establishes or reauthorizes various programs intended to facilitate innovations and breakthroughs in renewable and clean energy technologies, authorizing $35 billion in spending on a range of a clean energy research, development, and related programs through 2025.

There are several key provisions in the Energy Act of 2020. Title I contains many technology-oriented and technology-neutral measures to improve energy efficiency, including directing the U.S. Secretary of Energy (Secretary of Energy) to establish rebate programs to encourage the replacement of energy inefficient electric motors and transformers. Title II contains a number of measures designed to accelerate the development of improved, clean, and scalable advanced nuclear reactors, such as the establishment of a program to support the availability of high-assay, low-enriched uranium for civilian domestic research, development, demonstration and commercial use. Title III includes measures designed to spur substantial investments in a wide spectrum of renewable energy resources, ranging from marine energy and hydropower to geothermal to wind and solar energy. Titles IV and V cover carbon management and carbon removal and include measures designed to foster innovation and breakthroughs needed to reduce the cost barriers to large-scale implementation and achieve economy-wide deployment of carbon capture, utilization, and storage. Title VIII contains a number of provisions designed to accelerate modernization of the electric grid. Finally, Title IX includes a number of reforms designed to improve the Department of Energy.

Title I of the PIPES Act of 2020 directs the U.S. Secretary of Transportation (Secretary of Transportation) to update or promulgate regulations that affect the safety of certain gas pipeline, gathering, distribution, and LNG facilities. For example, the Secretary of Transportation must update the minimum operating and maintenance standards applicable to large-scale LNG facilities (other than peak shaving facilities) within three years, must promulgate a final rule governing the safety of gas gathering pipelines, and a study must be conducted regarding operators’ ability to map such lines, and is required to promulgate additional regulations to address and reduce methane emissions from new and existing gas transmission and distribution pipelines and the applicability of the pipeline safety requirements to idled natural or other gas transmission and hazardous liquids pipelines. Title II of the PIPES Act of 2020 requires the Secretary of Transportation to promulgate regulations that ensure that each distribution integrity management plan developed by a distribution system operator includes an evaluation of certain risks.


The oil pipeline industry has witnessed several unprecedented events that have driven home the permitting challenges that pipelines may increasingly face going forward.

Dakota Access Pipeline

The Dakota Access Pipeline (DAPL), which has now been in service for over three years, experienced a series of unexpected legal defeats that have left the pipeline’s future uncertain.

One major blow came on July 6, 2020, when a federal district court (District Court) ordered that the line be shut down pending an environmental review and emptied within 30 days. The order arose from a challenge brought by the Standing Rock Sioux Tribe, the Cheyenne River Sioux Tribe, and other tribes (the Tribes) regarding the sufficiency of the U.S. Army Corps of Engineers’ (Corps) environmental analysis under the National Environmental Protection Act (NEPA) in connection with the granting of an easement for DAPL. Earlier in 2020, the District Court determined that the Corps violated NEPA by failing to produce an Environmental Impact Statement (EIS) despite conditions that triggered such a requirement.[2] The District Court remanded the case to the Corps to prepare an EIS, but asked for separate briefing on the appropriate interim remedy during the remand process.[3] In the opinion accompanying the July 6 order, the District Court found that the “[c]lear precedent favoring vacatur during such a remand coupled with the seriousness of the Corps’ deficiencies” dictated that “vacatur is the only appropriate remedy…”[4] Accordingly, the District Court ordered that Dakota Access, LLC (Dakota Access), the owner of DAPL, “shall shut down the pipeline and empty it of oil by August 5, 2020…”[5]

Dakota Access quickly filed an emergency motion for stay pending appeal with the United States Court of Appeals for the D.C. Circuit (D.C. Circuit), arguing that the July 6 order would incurably and irreparably infringe Dakota Access’ rights, including losses exceeding $1 billion, and would inflict $7.5 billion in losses on North Dakota companies, employees, and the state’s budget through 2021. On the day that initially had been set as the deadline to shut down DAPL, the D.C. Circuit issued an order that allowed DAPL to continue operating but denied Dakota Access’ request for a stay. In the order, the D.C. Circuit also stated that it expected the appellants “to clarify their positions before the district court as to whether the Corps intends to allow the continued operation of the pipeline notwithstanding vacatur of the easement and for the district court to consider additional relief if necessary.”[6]

The litigation has since proceeded before both the District Court and the D.C. Circuit. In August, the Corps provided a status update to the District Court in which the Corps indicated that under its regulations, because the easement was vacated, DAPL now constitutes an encroachment on federal property.[7] However, the Corps indicated that it did not intend to exercise its discretion to immediately recommend an enforcement in return for Dakota Access’ agreement to abide by the conditions of the vacated easement. In the D.C. Circuit, the parties briefed the issue of whether the District Court erred in determining that an EIS is required and that vacatur was the appropriate remedy on remand.

Keystone XL Pipeline

The beleaguered Keystone XL Pipeline (Keystone XL), now over a decade into the permitting process, has hit another regulatory wall. Under U.S. law, a party seeking to construct, operate, and maintain a cross-border liquid petroleum or petroleum products pipeline must obtain a Presidential permit.[8] TC Energy Corporation (TC Energy) first applied for a Presidential permit in 2008, which the U.S. Secretary of State (Secretary of State) denied in early 2012. TC Energy applied for another permit to build Keystone XL in 2012. The Secretary of State denied that application, too, determining that issuing a permit to build the pipeline would not serve the national interest. But on January 24, 2017, President Donald Trump issued a memorandum in which he invited TC Energy to reapply for a permit to build Keystone XL. On March 29, 2019, the Presidential permit for Keystone XL was finally issued. As is common with Presidential permits, however, Keystone XL’s Presidential permit was subject to express conditions, including a condition stating that the permit “may be terminated, revoked, or amended at any time at the sole discretion of the President.”[9]


In May 2020, FERC issued two key orders establishing new policies for determining the return on equity (ROE) component of the cost-of-service rates charged by FERC-jurisdictional electric utilities, natural gas pipelines and oil pipelines. First, with respect to electric utilities, FERC issued an order setting the ROE component of the rates charged by electric transmission owners in the Midcontinent Independent System Operator (MISO) region.[10] Second, FERC issued a policy statement on determining the ROE for natural gas and oil pipelines.[11] Both orders signal a departure from the ROE methodologies previously used by FERC for the respective industries and could significantly impact the earnings of FERC-jurisdictional entities, and the returns ultimately realized by their investors.

FERC generally utilizes cost-of-service ratemaking principles when establishing the rates of jurisdictional entities under which rates are designed based on the cost of providing service, including an opportunity to earn a reasonable rate of return on the entity’s investments. In setting the ROE component of the rates, FERC must comply with Supreme Court precedent holding that “the return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks. That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital.”[12] Since the 1980s, FERC has relied almost exclusively upon the discounted cash flow (DCF) methodology to determine ROE for jurisdictional entities.

However, in an October 2018 order addressing a complaint against transmission owners in New England, FERC proposed abandoning its exclusive reliance on the DCF methodology for public utilities, by considering the cost of equity results of three additional methodologies (1) Capital Asset Pricing Model (CAPM), (2) Risk Premium, and (3) Expected Earnings.[13]

Subsequently, FERC issued a March 2019 notice of inquiry[14] and a November 2019 order concerning the MISO transmission owners’ ROE.[15] In the latter order, FERC adopted an ROE policy for public utilities that gave equal weight to the results of the DCF and CAPM models, by averaging them, but rejected the use of the Risk Premium and Expected Earnings models.[16] FERC did not adopt or propose those reforms for natural gas or oil pipeline ROEs; instead, FERC requested comment in its March 2019 notice of inquiry regarding whether ROE policy changes would be appropriate for natural gas or oil pipelines.

FERC’s MISO Order and Pipeline ROE Policy Statement adopt new ROE policies for electric transmission and natural gas and oil pipeline rates, and those policies differ between the electric sector and the pipeline sector.

In the MISO Order, FERC granted rehearing with respect to various aspects of Opinion No. 569, establishing a new policy for determining public utilities’ ROE by averaging the results of three methodologies: (1) DCF, (2) CAPM, and (3) Risk Premium. FERC found that utilizing three methodologies would increase the reliability of ROE results. Although FERC previously rejected the Risk Premium methodology, it changed course and included it in its ROE analysis because averaging it with the other models would reduce ROE volatility.

In the Pipeline ROE Policy Statement, FERC outlined its new policy for determining ROEs for natural gas and oil pipelines, which partly follows the policy outlined in the MISO Order with some key changes to address differences in the respective industries.

The biggest divergence in the policies pertains to the methodologies FERC will use to calculate ROEs for natural gas and oil pipelines. Specifically, FERC adopted the DCF and the CAPM methodologies, but rejected the Risk Premium methodology for gas and oil pipelines. FERC justified this disparate treatment by noting there are very few FERC decisions or settlements providing a stated ROE for natural gas and oil pipelines due to the prevalence of “black box” settlements that do not enumerate specific ROEs. Accordingly, FERC rejected the Risk Premium methodology for natural gas and oil pipelines because FERC and interested parties simply do not have the requisite data needed to apply the methodology to gas and oil pipelines.

Although FERC’s application of the new ROE policies in individual proceedings will depend upon specific circumstances and market conditions at the time such proceedings arise, the new policies contain some potentially beneficial revisions for both public utilities and oil and natural gas pipeline companies that could result in higher ROE determinations than if FERC relied exclusively upon its traditional DCF methodology. Despite this, questions remain regarding whether the ROE policies will produce returns on investments in electric, oil and natural gas infrastructure sufficient to support federal and state energy policy goals. There is also some uncertainty how the recently adopted ROE policies will fare in the face of legal challenges. Accordingly, there is likely to be uncertainty until these proceedings reach a final resolution, which could take some time.


In recent years, the call for reforms to FERC’s Order No. 1000 transmission planning and cost allocation requirements has steadily increased. FERC-watchers across the electricity sector have been eagerly awaiting a sign of things to come, and 2020 saw even more challenges to regional transmission organizations’ (RTOs) and independent system operators’ (ISOs) implementation of Order No. 1000.[17] Although the details of those challenges differ from case to case, most of them share a common theme of seeking to expand competitive transmission planning by increasing the type and number of transmission projects subject to competitive solicitation. FERC largely rebuffed those challenges, but many of the FERC decisions were appealed to, and remain pending before, the D.C. Circuit. Thus, it remains possible that the recent efforts to expand competitive transmission planning still could bear fruit. Additionally, there have also been significant developments at the state level concerning transmission planning.

Readers may recall that, in Order No. 1000, FERC eliminated the federal right-of-first-refusal (ROFR) that allowed franchised public utilities the opportunity to develop any new transmission projects in their service territories. FERC’s goal in removing the federal ROFR was to create competition for transmission projects, by allowing non-incumbent transmission developers to compete with incumbent public utilities to develop certain transmission projects. However, in removing the federal ROFR, FERC declined to expressly preempt states from passing state ROFR laws that effectively reinstate the protections previously granted by the federal ROFR.

Three states — Minnesota, Texas, and Iowa — have now passed such laws, and all three laws have been challenged in court. The Minnesota and Texas laws have been challenged on the theory that the laws violate the dormant Commerce Clause of the U.S. Constitution. The Minnesota law survived that challenge at the U.S. District Court and at the United States Court of Appeals for the Eighth Circuit.[18] However, a petition for a writ of certiorari has been filed with the United States Supreme Court.[19] Similarly, the Texas state ROFR law, which was enacted in May 2019,[20] survived a challenge filed in the United States Court for the Western District of Texas, which granted a motion to dismiss the lawsuit.[21] That case was appealed to the United States Court of Appeals for the Fifth Circuit. The court heard oral argument in June 2020.[22] In October 2020, certain transmission developers filed a petition challenging Iowa’s ROFR law, which was enacted in June 2020.[23] Unlike the other challenges, this petition argues that the law violates the Iowa state constitution’s prohibition on logrolling, requirement that a bill’s title must contain the subject matter of the bill, and requirement that all laws must operate uniformly.

Although it remains to be seen how these state ROFR cases will play out, their resolution has the potential to significantly impact states’ authority to determine which entities may construct transmission infrastructure and the degree to which transmission infrastructure in the United States will be developed through competitive solicitations mandated at the federal level.


For decades, FERC has allowed interstate natural gas pipeline owners to commence construction activities while requests for rehearing of the pipeline’s Natural Gas Act (NGA) certificate were pending. FERC effectuated that practice by issuing orders, commonly referred to as “tolling orders,” to provide itself additional time — in some cases years — to consider arguments raised on rehearing, while permitting construction activities to proceed before FERC concluded its review by issuing an order addressing the merits of the rehearing requests. Although that practice repeatedly had been upheld by the courts, it increasingly has come under attack in recent years by parties concerned that it precludes meaningful judicial review of the FERC’s decision because, under the NGA, the agency’s decision cannot be appealed to court until FERC issues a rehearing order on the merits.

On June 30, 2020, the D.C. Circuit issued an opinion overturning its prior precedent and invalidating FERC’s use of tolling orders in this way.[24] The D.C. Circuit issued its opinion just weeks after FERC’s issuance of Order No. 871, which was intended to address landowner concerns about pipelines being constructed before FERC completed its rehearing process, by amending FERC’s regulations to limit authorizations to commence construction of LNG export and import facilities and interstate natural gas pipeline facilities certificated under Sections 3 and 7(c) of the NGA[25] while requests for rehearing are pending.[26] Both the D.C. Circuit’s opinion and FERC’s Order No. 871 represent marked changes in the law and FERC’s policy respectively.

Under the NGA, no party may seek judicial review of a FERC order until after requesting rehearing of FERC’s decision and the agency issues an order addressing the rehearing request. Under the statute, a request for rehearing is deemed to be denied by operation of law if FERC fails to act on it within 30 days, which then allows an aggrieved party to seek judicial review of FERC’s decision in a federal court of appeals.[27] However, in order to respond on the merits to the many issues raised in requests for rehearing, FERC’s long-time practice had been to issue tolling orders to provide itself additional time to consider the issues, while simultaneously allowing a certificate holder to proceed with construction. Over the years, various litigants alleged this practice is unfair to affected landowners and interested parties, but the D.C. Circuit (and other courts) upheld FERC’s ability to issue tolling orders in this manner in various proceedings since originally ruling on the question in 1969.[28] The recent opinion in Allegheny Defense Project v FERC overturns that precedent and invalidates FERC’s use of tolling orders to provide itself more than 30 days to address rehearing requests.

The opinion was issued following oral arguments before the en banc court in an appeal of a FERC certificate order authorizing the construction and operation of an interstate natural gas pipeline project. The en banc court granted rehearing of an earlier decision by a panel of three D.C. Circuit judges, which upheld FERC’s certificate order and tolling order in the proceeding. In conjunction with the original panel’s decision, D.C. Circuit Judge Patricia Millett filed a lengthy concurring opinion calling into question the fairness of FERC’s practice of issuing tolling orders and the continued viability of the D.C. Circuit’s precedent upholding FERC’s practice.[29]

In its opinion, the D.C. Circuit overturned more than 50 years of precedent and held that “tolling orders are not the kind of action on a rehearing application that can fend off a deemed denial and the opportunity for judicial review.”[30] The court found that FERC could not disregard the jurisdictional consequences of its inaction given the NGA’s explicit 30-day deadline for action upon requests for rehearing. In addition, the court found that Congress explicitly provided FERC with four options in the NGA for how it could act upon a request for rehearing: (1) grant rehearing, (2) deny rehearing, (3) abrogate its order without further hearing or (4) modify its order without further hearing. The court found that FERC’s use of tolling orders is not among those options, and it accordingly invalidated FERC’s use of tolling orders to extend the time to consider issues raised in requests for rehearing.

Just weeks before the D.C. Circuit’s decision, FERC issued Order No. 871 addressing some of the same issues raised in the court’s opinion. In Order No. 871, FERC revised its regulations to preclude the agency from authorizing the holder of an NGA certificate to proceed with construction of FERC-approved interstate natural gas pipeline and LNG facilities until: (i) FERC acts on the merits of timely filed requests for rehearing or (ii) the time to seek rehearing has passed without any requests for rehearing being submitted. FERC stated that the rule change is intended to balance the agency’s need to address the concerns raised on rehearing with the concerns related to proceeding with construction before the agency has completed its review, the latter of which were raised by Justice Millett in her concurring opinion discussed above.

FERC issued Order No. 871 as an instant final rule, meaning the rule change was finalized without notice or the opportunity for public comment under the Administrative Procedure Act because it concerns only matters of agency procedure. While certain members of the interstate natural gas pipeline industry, and their representative trade association, have filed appeals to seek judicial review of Order No. 871, it remains to be seen how other stakeholders, including potentially affected landowners and environmental groups, will view FERC’s rule change, nor is it clear whether historically aggrieved stakeholders will consider it sufficient, together with the opinion, to address their concerns.

It is likely that the opinion and FERC’s Order No. 871 will combine to delay construction and ultimately increase the cost of FERC-approved gas pipelines and LNG facilities, which could create uncertainty for project developers and investors. In addition to the implications for LNG and interstate natural gas pipeline proceedings, the opinion has had significant impacts in FERC proceedings under its Federal Power Act (FPA) jurisdiction. The relevant provisions of the FPA and NGA are identical.[31] In the wake of the D.C. Circuit decision discussed above, FERC has begun issuing rehearing orders on the merits within 30 days or it has issued notices denying rehearing in proceedings under both the NGA and FPA. For notices denying rehearing, FERC now issues either basic denials by operation of law or notices of denial of rehearing by operation of law and providing for further consideration, the latter of which indicates FERC’s intent to issue a substantive rehearing order by citing FERC’s authority under both the NGA and FPA to “modify or set aside” the underlying order.


In 2020, the Trump Administration continued its efforts to roll back environmental regulations on a myriad of topics ranging from methane emissions to environmental impact reviews under NEPA. Many of the regulatory changes remain under litigation or could be reversed by the new Biden Administration, leaving the regulatory landscape somewhat uncertain.


The Clean Power Plan (CPP) issued by the Environmental Protection Agency (EPA) in October 2015[32] under the Clean Air Act limited carbon dioxide (CO2) emissions from existing power generation facilities. Under the CPP, nationwide CO2 emissions would be reduced by approximately 30 per cent from 2005 levels by 2030 with a flexible interim goal. In July 2019, EPA repealed the CPP,[33] resulting in the D.C. Circuit’s dismissal of longstanding litigation challenging the CPP.[34] In September 2019, the D.C. Circuit dismissed the case as moot over the objection of a group of governmental and nonprofit litigants that supported the CPP, who collectively sought to obtain a ruling from the court on the scope of EPA’s authority to regulate carbon dioxide emissions under the Clean Air Act, even though the CPP was rescinded. Because the CPP never came into effect due to a stay issued by the Supreme Court, however, the dismissal of the litigation — and the repeal of the CPP itself — had little practical effect on regulated entities.

On the same day that EPA repealed the CPP, EPA replaced the CPP with the Affordable Clean Energy (ACE) Rule,[35] which takes a more limited view on EPA’s authority to regulate emissions from existing sources. The ACE rule provides more regulatory flexibility, shifting greater responsibility to the states to develop and implement performance standards for existing power generation facilities, and likely has a more limited impact on reduction of CO2 emissions than the CPP. Dozens of states, public health and environmental organizations, and industry groups have challenged the ACE Rule in the D.C. Circuit, and the ACE Rule currently remains under litigation.[36] While EPA announced that it would rollout revisions to its New Source Review (NSR) regulations for new power generation facilities at the same time it took steps to repeal and replace the CPP, the separate NSR rulemaking for new power generation facilities has been delayed and, as of the date of this writing, has not been finalized.[37] Certain litigants challenging the ACE Rule requested that the litigation be paused while awaiting issuance of the New Source Review regulations, but the D.C. Circuit rejected those requests.


Energy exploration and production activities on federal lands are typically subject to the environmental review requirements under NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the human environment. In July 2020, the White House Council on Environmental Quality (CEQ) issued the first significant substantive changes to NEPA’s implementing regulations in over 40 years.[38] The revised regulations streamline the environmental review process by, among other things, shortening the time for federal agencies to complete their NEPA reviews. The most controversial change eliminates the requirement for federal agencies to evaluate cumulative impacts, which is seen by environmental groups as a way for federal agencies to avoid considering the impact of government actions on greenhouse gas (GHG) emissions and climate change.

The rule was challenged by states and environmental and health advocacy groups in various federal district courts, and the litigation remains ongoing.[39] Litigants in the Wild Virginia case within the U.S. District Court for the Western District of Virginia sought a preliminary injunction to enjoin the NEPA streamlining regulations from taking effect. The court declined to enjoin the rule and allowed the regulations to go into effect, as scheduled, on September 14, 2020. The Wild Virginia litigants moved for summary judgment in November 2020; the motion remains pending before the court. Consistent with guidance from the Office of Management and Budget directing agencies to update their NEPA implementing regulations,[40] certain federal agencies — including the Department of the Interior and the U.S. Forest Service — began implementing the streamlining changes through new guidance and agency-specific regulations in 2020.


In September 2019, the National Highway Traffic Safety Administration (NHTSA) and EPA finalized a rulemaking known as the “Preemption Regulation,” the first part of the Safer Affordable Fuel Efficient Vehicles (SAFE) Rule.[41] The Preemption Regulation granted the U.S. Department of Transportation authority to set national fuel economy and emissions standards for motor vehicles and preempted similar state programs, resulting in the withdrawal of a January 2013 preemption waiver granted to California under the Clean Air Act for its own GHG and zero emissions requirements for motor vehicles. The rescission of the waiver significantly impacts California and the thirteen states that have adopted its standards. The agencies’ justification for the rescission is largely based on the auto industry’s need to develop and market vehicles in response to consumer demand rather than regulatory requirements. The withdrawal of the waiver has been heavily litigated in both federal district courts[42] and the D.C. Circuit[43] due to differing venue requirements for challenges to regulations promulgated by NHTSA and EPA.

In April 2020, NHTSA and EPA published new fuel economy GHG emission standards for passenger vehicles and light duty trucks for model years 2021 through 2026 as part two of the SAFE Rule.[44] Nevertheless, in the absence of clarity over the Preemption Regulation during the pendency of the litigation, certain auto manufacturers committed to continuing California’s efforts to reduce GHG emissions. California announced it had reached an agreement in August 2020 with BMW (including Rolls Royce), Ford, Honda, Volkswagen (including Audi), and Volvo to make voluntary commitments to annual reductions of vehicle GHG emissions through the 2026 model year and to accelerate the transition to electric vehicles.[45] In addition, GM and Nissan have withdrawn from the litigation, announcing their intention to work with the State of California to establish common-sense vehicle emission standards.[46]



As readers might recall, in 2018 FERC issued a final rule, Order No. 841[47] (Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators), addressing Storage resources in RTO/ISOs. The rule, which is intended to remove barriers for Storage resource participation in various wholesale markets, such as capacity, energy, and ancillary services, required the RTO/ISOs to amend their tariffs to develop a participation model that more fully incorporates Storage into the market, taking into consideration the physical and operational characteristics of Storage resources. Order No. 841 required that all RTO/ISOs file a compliance tariff no later than December 3, 2018, with an effective date of December 3, 2019, incorporating the mandated changes.[48]

Since our last report, there has been significant progress in maturation of the federal regulatory framework Order No. 841 established. Following FERC’s denial of the requests for rehearing in that proceeding, certain entities filed petitions for judicial review in the D.C. Circuit, seeking to challenge aspects of Order No. 841. Most importantly, those entities sought to overturn FERC’s decision not to allow states and other retail regulatory authorities the right to opt-out of the Order No. 841 framework by prohibiting energy storage resources within their jurisdictions from participating in the RTO/ISO markets. On July 10, 2020, the D.C. Circuit upheld Order No. 841 over those challenges, concluding, among other things, that FERC acted within its authority in prohibiting retail regulatory authorities from banning Storage resources from participating in the wholesale markets.[49] Although the court left open the possibility that states could bring as-applied challenges to the Order No. 841 regulatory framework in the future, to the extent a state identifies specific state regulations with which it believes Order No. 841 conflicts,[50] the court’s conclusion that Order No. 841, on its face, does not impermissibly intrude on retail regulatory authorities’ jurisdiction alleviated one of the more significant sources of lingering regulatory uncertainty associated with Order No. 841.

In parallel with that rehearing and judicial review process, the RTO/ISOs proceeded apace in developing their proposed rules to comply with Order No. 841. Starting in 2019 and continuing throughout much of 2020, all of the RTO/ISOs subject to FERC jurisdiction filed their proposed amended tariffs with FERC. FERC engaged in an iterative compliance process whereby the agency accepted in part the compliance proposals and directed further compliance filings to modify or refine aspects of each RTO/ISO’s proposed tariff amendments. FERC has accepted each RTO/ISO’s amended tariffs and, as a result, the rules governing energy storage resources’ wholesale market participation have taken effect in all RTO/ISOs except for Southwest Power Pool, Inc. and MISO, whose amended tariffs are slated to take effect in August 2021 and June 2022, respectively.[51]


In August 2020, FERC accepted a proposal from MISO to allow cost recovery for energy storage projects that address transmission-system needs.[52] MISO’s so-called “storage as a transmission-only asset” (SATOA) projects are eligible to compete with conventional, poles-and-wires transmission projects in the MISO Transmission Expansion Planning (MTEP) program, can recover costs through MISO’s tariff, and need not wait in MISO’s years-long interconnection queue.

Consistent with FERC precedent and policy,[53] SATOA projects are ineligible to receive revenues from energy sales in MISO’s markets, and any such revenues incidentally received during SATOA operations must be credited back to transmission customers. SATOA operators must ensure that their projects maintain adequate states of charge to fulfill their designated transmission stability functions when called upon.

Other markets are developing their own proposals to promote integration of energy-storage resources as solutions to transmission issues. Notably, PJM Interconnection, L.L.C. (PJM) has been working with stakeholders to develop a proposal for storage as a transmission asset. PJM’s Planning Committee is scheduled to address the matter in a special session on February 4, 2021.[54]

A separate proposal from PJM transmission owner Kentucky Power Company to secure cost recovery for its proposed Middle Creek energy-storage project through its transmission rates was rejected by FERC upon a finding that the project was “more analogous to a backup generator serving a subset of retail customers than that of a transmission facility…”[55] FERC affirmed that it would continue to consider whether storage facilities qualify as transmission on a case-by-case basis, and the Middle Creek project — which allowed islanding of retail loads during outages of a 46-kV line — did not serve a transmission function.[56]


Since our last report, the battle for the future of the PJM capacity market has continued. As readers may recall, in mid-2018, FERC issued an order acting on a complaint filed by several generators against PJM and a filing by PJM to amend its Open Access Transmission Tariff (Tariff).[57] In the order, FERC found that PJM’s Tariff was unjust and unreasonable because it failed to protect the integrity of competition in the PJM capacity market from unreasonable price distortions and cost shifts caused by out-of-market state support for certain generation resources.

Following a paper hearing in which dozens of parties participated, FERC issued an order in December 2019 determining a just and reasonable replacement rate and directing PJM to submit a compliance filing to implement the replacement rate (December 2019 Order).[58] The December 2019 Order found that any resource, new or existing, that receives a state subsidy and does not qualify for an exemption, should be subject to the Minimum Offer Price Rule (MOPR).[59] The December 2019 Order also defined state subsidy broadly to include any:

direct or indirect payment, concession, rebate, subsidy, non-bypassable consumer charge, or other financial benefit that is (1) a result of any action, mandated process, or sponsored process of a state government, a political subdivision or agency of a state, or an electric cooperative formed pursuant to state law, and that (2) is derived from or connected to the procurement of (a) electricity or electric generation capacity sold at wholesale in interstate commerce, or (b) an attribute of the generation process for electricity or electric generation capacity sold at wholesale in interstate commerce, or (3) will support the construction, development, or operation of a new or existing capacity resource, or (4) could have the effect of allowing a resource to clear in any PJM capacity auction.[60]

FERC clarified that the definition would apply to demand response, energy efficiency, and capacity storage resources that participate in the PJM capacity market, and refused to adopt a materiality threshold.[61] In March and June of 2020, PJM submitted proposed revisions to its Tariff to address the requirements of the December 2019 Order.

In October 2020, FERC accepted PJM’s compliance filings, in part, rejected PJM’s compliance filings, in part, granted waiver regarding certain capacity auction deadlines, and directed PJM to submit a further compliance filing.[62] In particular, FERC accepted certain proposals by PJM that would narrow the applicability of the MOPR. For example, FERC accepted that “sellers involved in bilateral transactions should be allowed to elect the Competitive Exemption where the rights and obligations among multiple off-takers are in equal shares (similar to the pari passu arrangements for jointly-owned resources) and where the capacity resource is only entitled to the State Subsidies[63] that are assignable.”[64] FERC also accepted PJM’s suggestion to exclude “independently evaluated, non-discriminatory, fuel-neutral, competitive state-directed default service auctions” and certain bilateral contracts with self-supply entities from the MOPR.[65] Subject to some modifications, FERC accepted PJM’s self-supply exemption, renewable portfolio standard exemption, demand response and energy efficiency resource exemption, competitive exemption, and resource-specific exception.[66] On the issue of PJM’s proposed default offer price floors for generation-backed demand response, FERC accepted some parts of the compliance filing while rejecting others.[67]



Since our last report, many states have continued their march toward a cleaner generation fleet, with several states recently accelerating their pace. According to the U.S. Energy Information Administration, as of December 2020, 30 states and the District of Columbia have adopted renewable portfolio standards (RPS) or other policies that require electricity to be procured from certain types of renewable resources.[68] Several states increased their RPS targets in 2020, with several seeking to procure 100 per cent of their power from renewable resources. Those updated RPS targets, in chronological order, are as follows:

  • Virginia: 100 per cent by 2045.[69]
  • New Jersey: 100 per cent clean energy by 2050.[70]
  • Louisiana: 100 per cent by 2050.[71]
  • Michigan: 100 per cent carbon-neutral by 2050.[72]
  • Connecticut: 100 per cent carbon-free electricity by 2050.[73]
  • Arizona: utilities must provide 100 per cent carbon-free energy by 2050.[74]
  • There are now 15 jurisdictions that have adopted mandates to procure 100 per cent of their power from carbon-free or renewable resources by mid-century: California; Colorado; Connecticut; District of Columbia; Hawaii; Louisiana; Maine; Michigan; Nevada; New Jersey; New Mexico; New York; Puerto Rico; Virginia; and Washington.[75]


On April 11, 2020, Virginia Governor Ralph Northam signed the Virginia Clean Economy Act (VCEA) into law, which seeks to decarbonize Virginia’s power grid by, among other things, adopting a RPS program that will require the investor-owned utilities in the state to acquire 100 per cent of their power supply from renewable generation resources by 2050. Meeting this renewable energy procurement mandate will require significant investment in new renewable energy projects, energy storage systems, and the necessary transmission and distribution infrastructure to bring such resources online.

The VCEA includes a new, mandatory RPS program that requires all electric utilities and retail electric suppliers to satisfy their load obligations utilizing 100 per cent renewable sources by 2045 for the Dominion Energy Virginia (Dominion) service territory and by 2050 for the service territory of Appalachian Power Company, a subsidiary of American Electric Power (AEP). The VCEA’s definition of “renewable energy” explicitly excludes resources that generate electricity using coal, oil, natural gas or nuclear fuel, as well as waste heat from fossil fuel-fired generation facilities. Any entity failing to meet the RPS requirements will be required to make deficiency payments, the proceeds of which will offset administrative costs and fund training programs and renewable energy programs.

The VCEA also establishes a schedule by which Dominion and AEP must seek all necessary approvals to construct, acquire or enter into power purchase agreements for specified amounts of generating capacity from solar and onshore wind resources, as well as energy storage capacity. The VCEA also requires Dominion and AEP to achieve incremental annual energy efficiency savings.

Recognizing that the cost of developments and investments to comply with the new RPS requirements will be passed through by the investor-owned utilities to their ratepayers, the VCEA includes some provisions designed to protect ratepayers within Virginia, including provisions that give the Virginia State Corporation Commission additional oversight over utilities’ renewable energy project costs. The VCEA also requires Dominion and AEP to conduct competitive solicitations for energy, capacity and environmental attributes to procure at least 35 per cent of their new RPS requirements from third parties. Consequently, the legislation likely will facilitate competition in the development of new renewables projects by requiring that a significant amount of those projects be developed by entities other than Virginia’s existing, incumbent investor-owned utilities, Dominion and AEP.

While its ultimate impact remains to be seen, the VCEA likely will have significant implications for energy infrastructure investments in Virginia and in nearby states, including ancillary infrastructure. As the state’s reliance on intermittent renewable generation increases, Virginia — and the interstate power system of which it is an integral part — likely will need to rely on energy storage resources, as well as upgraded or expanded transmission and distribution system infrastructure, to maintain reliability.

Implementation of the VCEA remains ongoing, but the Virginia State Corporation Commission has begun acting in accordance with the VCEA, as evidenced by a recent final rule on energy storage issued in December 2020.[76] The rule seeks to implement the VCEA’s energy storage target of 3100 MW by 2035. To that end, the rule sets interim targets of 275 MW by 2025 and 1,075 MW by 2030 for the state’s largest utilities and sets a requirement that 35 per cent of the procurement capacity must come from third parties.


Massachusetts’ Advance Clean Energy Act of 2018[77] created the Clean Peak Energy Portfolio Standard (Clean Peak Standard), a first-of-its kind policy designed to provide incentives to clean energy technologies that can either supply electricity or reduce demand during peak demand periods. The final regulations for the Clean Peak Standard took effect on August 7, 2020.

The Clean Peak Standard requires a percentage of electricity delivered during peak hours to come from certain eligible resources (Clean Peak Resources). To that end, the Clean Peak Standard requires retail electric suppliers in Massachusetts to procure a minimum percentage of their total annual electricity sales to Massachusetts end-use customers from Clean Peak Resources by purchasing Clean Peak Energy Certificates (CPECs). The Act provides the qualification requirements for Clean Peak Resources, valuation of CPECs and purchasing requirements for CPECs by retail electric suppliers.

The Department of Energy Resources (DOER) created four categories of Clean Peak Resources, each of which must generate, dispatch, or discharge electricity to the electric distribution system in Massachusetts: (1) new renewable energy generation resources that come online after January 1, 2019; (2) existing renewable energy generation resources that add new energy storage capacity of at least 25 per cent of the renewable energy generation resources nameplate capacity, with a nominal useful energy capacity of at least four hours at the nominal rated power; (3 new energy storage that charges from renewables; and (4) demand response resources (e.g., behind-the-meter energy storage that reduces energy consumption).[78]

Resources participating in the program will earn CPECs for every megawatt hour (MWh) of electricity they produce, or reduce, coincident with Seasonal Peak Periods,[79] with certain resources potentially qualifying for multipliers that boost the number of CPECs they receive.[80] Energy storage systems that are not co-located with renewable energy systems may generally be required to charge during specific hours, depending on whether they are charged from solar resources or wind resources. The timing of the Seasonal Peak Periods and charging windows is designed to send a price signal to pair renewables and energy storage and shift the use of renewable production to peak demand periods.

Under the program, all retail electric suppliers in Massachusetts will be required to procure a minimum percentage of their total annual electricity sales to Massachusetts end-use customers from Clean Peak Resources by either purchasing CPECs or retiring earned CPECs. The minimum requirement increases over time. The minimum Clean Peak Standard started at 1.5 per cent of retail electricity sales in 2020, and rose to 3 per cent for 2021. The minimum increases at least 1.5 per cent each year thereafter, to at least 16.5 per cent by 2030 and 46.5 per cent by 2050.[81] Unless extended by law, the program will expire in 2050.[82]

Each distribution company must competitively procure 30 per cent of the total market obligation of retail electric suppliers in a given compliance year through long-term contracting, subject to adjustment upward or downward depending on the market response — i.e., if market supply is below 50 per cent of the Clean Peak Standard’s minimum requirement, DOER may increase the next year’s long-term contract procurement requirement by up to 5 per cent, and where market supply is greater than 70 per cent of the Clean Peak Standard’s minimum requirement, DOER may decrease the following year’s long-term contract procurement by up to 15 per cent.[83] To keep consumer costs down, each retail electric supplier may satisfy the remainder of the Clean Peak Standard’s minimum requirement via an alternative compliance payment by the retail electric supplier.[84]


On September 17, 2020, FERC issued its long-awaited, landmark final rule (Order No. 2222) concerning the participation of distributed energy resource (DER) aggregations in the wholesale energy, capacity, and ancillary services markets administered by RTO/ISOs.[85] FERC found that the existing RTO/ISO market rules are unjust and unreasonable because they present barriers to DER aggregations’ participation in those markets, which thereby reduces competition and fails to ensure that the markets produce just and reasonable rates.[86] Accordingly, Order No. 2222 required each RTO/ISO to revise its tariff to ensure that the market rules set forth therein facilitate the participation of DER aggregations.[87]

More specifically, in order to remove barriers to DER aggregations’ market participation, FERC directed each RTO/ISO to “establish [DER] aggregators as a type of market participant that can register [DER] aggregations under one or more participation models in the RTO/ISO tariff that accommodate the physical and operational characteristics of each [DER] aggregation.”[88] At nearly 300 pages in length, Order No. 2222 is a lengthy and highly technical rule. Among other things, the rule requires each RTO/ISO’s DER aggregation rules to establish certain minimum size requirements and address locational requirements, distribution factors and bidding parameters, information and data requirements, metering and telemetry requirements, modifications to a DER aggregation, and requirements for coordination among various entities.[89]

In one of the more controversial aspects of Order No. 2222, FERC declined to include an “opt-out” mechanism, i.e. a mechanism for states and other relevant electric retail authorities to prohibit DERs from participating in an RTO/ISO market through a DER aggregation.[90] However, FERC did choose to establish an “opt-in” mechanism for utilities that distributed 4 million MWh or less in the previous fiscal year.[91] Pursuant to that mechanism, customers of such utilities may not participate in DER aggregations unless the relevant electric retail regulatory authority opts-in, by affirmatively allowing such customers to participate in DER aggregations.[92] Further, FERC expressly stated that Order No. 2222 does not “preclude or limit state or local regulation of: retail rates; distribution system planning, distribution system operations, or distribution system reliability; [DER] facility siting; and interconnection of resources to the distribution system that are not subject to [FERC] jurisdiction.”[93]

Several entities have requested rehearing of Order No. 2222, raising a broad range of issues, from requests for clarification of certain technical implementation requirements to whether FERC misapprehended its jurisdiction under the FPA. It remains possible that FERC could choose to alter Order No. 2222 on rehearing, and/or that one or more entity could seek judicial review of Order No. 2222.

Aside from the regulatory uncertainty associated with the requests for rehearing and potential petitions for judicial appeal, there is significant uncertainty concerning how each RTO/ISO will implement Order No. 2222. Developing the RTO/ISOs’ compliance proposals will entail a significant undertaking with robust stakeholder involvement and debate. Further, FERC gave each RTO/ISO discretion to tailor its compliance approach based on its specific regional needs. Thus, the RTO/ISOs’ stakeholder processes could produce a wide range of potential market rules. FERC required each RTO/ISO to submit its compliance proposal within 270 days of Order No. 2222’s publication date in the Federal Register, which makes them due by July 19, 2021.[94] Depending on whether, or to what extent, FERC requires additional, subsequent compliance filings to remedy perceived shortcomings in the initial filings, the compliance process for Order No. 2222 could take the remainder of 2021, and potentially could stretch into 2022.



Northern California utility Pacific Gas & Electric (PG&E) filed for bankruptcy protection in January 2019,[95] in part due to billions of dollars in liability from catastrophic wildfires in the State of California alleged to have been started by faulty PG&E equipment during dry seasons. As part of the proposed bankruptcy plan, PG&E attempted to shed billions in losses under power purchase agreements (PPA) for renewable energy that were executed at a time when renewable energy was priced significantly higher. In January 2019, FERC issued orders that PG&E could not back out of PPAs without the regulator’s consent.[96] In June 2019, the bankruptcy court issued a declaratory judgment that the bankruptcy court — not FERC — could determine the fate of the PPAs under its less stringent standard for determining whether a contract can be broken.[97] Allowing rejection of the PPAs could have left renewable companies with significantly less than the full value of their contracts, creating uncertainty for future viability, given PG&E’s position as the largest offtaker of renewable energy in California. FERC appealed the bankruptcy court’s decision to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). Ultimately, PG&E assumed the PPAs through its reorganization plan, and PG&E emerged from bankruptcy in July 2020.[98] In October 2020, the Ninth Circuit vacated FERC’s January 2019 orders, given the underlying dispute over the contracts was moot, as well as the bankruptcy court’s June 2019 declaratory judgment, teeing up the possibility of future litigation regarding the tension between FERC and bankruptcy court authority with respect to wholesale power contracts.[99]


In an effort to roll back Obama-era methane regulations known as the 2016 Waste Prevention Rule, the U.S. Department of the Interior’s Bureau of Land Management (BLM) finalized a replacement “Revision Rule” in September 2018.[100] The Revision Rule rolled back certain requirements of the 2016 Waste Prevention Rule seeking to reduce regulatory requirements and reduce the cost of compliance for oil and gas operators. On July 15, 2020 the Revision Rule was vacated by the U.S. District Court for the Northern District of California.[101] BLM has appealed this decision, which remains pending before the Ninth Circuit.[102] Further, on October 8, 2020, the U.S. District Court for the District of Wyoming vacated the 2016 Waste Prevention Rule, which BLM has not appealed.[103]

In addition, in September 2020, EPA finalized two rules — the “Review Rule” and “Reconsideration Rule” — that amend to New Source Performance Standards under the Clean Air Act known as Subpart OOOOa for new oil and gas operations on private lands. Combined, the Review Rule and Reconsideration Rule reconsider and roll back Obama-era limitations on methane and volatile organic compounds.[104] In response to industry pushback, EPA granted revised requirements for fugitive emissions, standards for well site pneumatic pumps, and certifications for closed vent systems, and also incorporated provisions to streamline implementation of the rule. A number of states and municipalities and a coalition of environmental groups challenged the rules, which remain in effect during the pending litigation.[105]


Federal tax incentives for carbon capture and sequestration (CCS) along with California’s Low Carbon Fuel Standards (LCFS) CCS protocol have sparked increased interest in CCS projects over the past year. Potential tax-equity investors had been awaiting guidance around key aspects of the federal income tax credit for CCS projects under section 45Q of the Internal Revenue Code (45Q tax credit) before committing significant capital to CCS. That guidance has now been released. The Department of the Treasury and the Internal Revenue Service issued two sets of initial guidance covering tax-equity structuring and 45Q tax credit qualification in February 2020.[106] Proposed regulations covering many of the other areas in which the CCS industry had asked for guidance were issued in May 2020,[107] and a final set of regulations was issued in January 2021.[108] Section 45Q provides a dollar-for-dollar reduction in federal income tax liability for each metric ton of “qualified carbon oxide” captured at a qualifying plant and then permanently buried, used as a tertiary injectant in an enhanced oil or natural gas recovery project, or used in another process that would result in the permanent sequestration of the carbon oxide. The LCFS program is a market-based policy that sets annual carbon intensity benchmarks on transport fuels sold, supplied or offered for sale in California. LCFS credits are available to projects that capture and sequester CO2 and that have the requisite nexus to the California transportation fuels market. The 45Q tax credits can be stacked with California’s LCFS credits, thereby increasing the incentives for projects eligible for both programs. The incentives are increasingly being seen as an important tool in reducing GHG emissions and achieving the Paris Agreement goals (i.e. to limit global warming to below 2°C, compared to pre-industrial levels). Interest in CCS projects is expected to increase as other states consider implementing low carbon fuel standard programs similar to the California LCFS (e.g., Oregon) and incorporate CCS projects into statewide action plans to meet carbon emission reduction targets (e.g., Wyoming, Colorado, Louisiana).


The 2020 fiscal year was a somewhat down year for FERC enforcement activities. According to FERC’s 2020 Report on Enforcement (2020 Annual Report), issued in November 2020, Enforcement Staff opened six new investigations — a decrease from the twelve investigations opened in 2019.[109] Similarly, FERC’s penalty and disgorgement totals of $437,500 and $115,876,[110] respectively, were significantly less than the $7.4 million and $7 million assessed in 2019.[111] According to the 2020 Annual Report, while the Office of Enforcement “continued its typical investigations, audits, and surveillance activities” in fiscal year 2020, “it also took steps to help regulated entities manage their potential enforcement and compliance-related obligations in response to the unprecedented COVID-19 pandemic.”[112] The accommodations to regulated entities included:

[w]orking with the subjects of continuing non-public investigations and audits, and entities with continuing compliance obligations associated with completed enforcement cases, to provide flexibility with discovery-related or other deadlines through July 31, 2020; [s]uspending the initiation of new audits until July 31, 2020; and [p]ostponing contacting entities regarding surveillance inquiries, except those involving market behavior that could result in significant risk of harm to the market.[113]

In 2020, FERC also was engaged in federal court litigation stemming from enforcement actions commenced in prior years. For example, on October 25, 2019, FERC approved a penalty order against Vitol, Inc. (Vitol) and Federico Corteggiano (Corteggiano), who traded energy-related products for the company.[114] The order imposed a civil penalty of $1,515,738 and disgorgement of $1,227,143, plus interest, against Vitol and a $1,000,000 civil penalty against Corteggiano.[115] When the parties failed to pay the penalties and disgorgement within the 60-day payment period prescribed in the FPA,[116] FERC brought an action in the United States District Court for the Eastern District of California seeking an order affirming and enforcing its October 25 order.[117] In March 2020, Vitol and Corteggiano filed motions to dismiss, arguing that FERC’s complaint was time-barred by the five-year statute of limitations set forth in Section 2462 of Title 28 of the U.S. Code and that FERC failed to state a claim for a manipulation violation.[118] According to Vitol and Corteggiano, because the trading underlying the allegations occurred between October 28, 2013 and November 1, 2013 and the parties entered into a one-year tolling agreement, FERC was required to file the complaint on or before October 28, 2019.[119] Their motions to dismiss came less than a month after the U.S. Court of Appeals for the Fourth Circuit ruled that the five-year statute of limitations to enforce manipulation penalties commences when the enforcement target fails to pay the penalties, as that is the date when all the FPA’s statutory prerequisites to filing suit in district court have been satisfied,[120] a decision the defendants attempted to characterize as “poorly reasoned.”[121]

In contrast to FERC’s relatively down year in terms of enforcement actions, the Commodity Futures Trading Commission (CFTC) filed the most enforcement actions in the CFTC’s history in fiscal year 2020. According to the CFTC Division of Enforcement’s annual report for fiscal year 2020, the CFTC’s Division of Enforcement filed 113 enforcement actions, the most of any year in the CFTC’s history.[122] And the monetary relief ordered during that period, exceeding $1.3 billion, was the fourth largest in CFTC history.[123]

While many of these proceedings involved non-energy commodities, one notable proceeding settled in December 2020 involved Vitol, which was charged with manipulative and deceptive conduct. The CFTC found that, among other things, Vitol attempted to manipulate certain U.S. price assessment benchmarks published by S&P Global Platts relating to physical fuel oil products in order to benefit its related physical and derivatives positions.[124] The Department of Justice also brought charges against Vitol, alleging conspiracy to violate the Foreign Corrupt Practices Act. Vitol settled with the CFTC, neither admitting nor denying the CFTC’s findings, except to the extent that Vitol admits those findings in any related action against Vitol by, or any agreement with, the Department of Justice or any other governmental agency or office.[125] The Vitol proceeding serves as a stark reminder of the potential for multi-agency investigations for efforts to rig or otherwise manipulate energy markets.


Numerous challenges, including decreased demand resulting from the onset of the COVID-19 pandemic, prompted high numbers of independent oil and natural gas producers to file for bankruptcy in 2020. Parties to several of these cases, (including the bankruptcies of Ultra Petroleum Corporation (Ultra), Chesapeake Energy Corporation (Chesapeake), Gulfport Energy Corporation (Gulfport), and Extraction Oil & Gas, Inc. (Extraction) raised a significant jurisdictional question — whether debtors in bankruptcy should be compelled to obtain FERC authorization, in addition to authorization from a bankruptcy court, in order to reject a FERC-jurisdictional agreement for interstate natural gas or oil pipeline transportation service.[126] In these proceedings, FERC, joined by numerous pipelines companies, strongly advocated its view that debtors seeking to reject FERC-jurisdictional transportation agreements must obtain FERC approval under the NGA or Interstate Commerce Act (ICA), as applicable. Conversely, the bankruptcy courts hearing these arguments ruled that debtors need not obtain FERC authorization to reject FERC-jurisdictional agreements in bankruptcy.[127]

While this jurisdictional issue has been litigated in the past in the context of FERC-jurisdictional agreements under the FPA, there had been little litigation regarding FERC-jurisdictional agreements under the NGA and ICA prior to 2020. This changed with a proceeding involving Ultra and Rockies Express Pipeline LLC (REX). Prior to Ultra’s bankruptcy filing, REX filed a petition with FERC seeking a declaratory ruling that Ultra could not reject its FERC-jurisdictional agreement with REX without FERC approval under the NGA and the Mobile-Sierra doctrine.[128] However, prior to FERC acting on REX’s petition, Ultra filed for bankruptcy protection in the United States Bankruptcy Court for the Southern District of Texas. After the bankruptcy court informed REX that continuing to pursue its petition at FERC would violate the bankruptcy code’s automatic stay provision, REX withdrew its FERC petition. Following extensive discovery and a multi-day hearing, the bankruptcy court granted Ultra’s motion to reject and found, among other things, that Ultra did not need to obtain authorization from FERC to reject its FERC-jurisdictional agreement with REX in bankruptcy.[129] The bankruptcy court followed controlling Fifth Circuit precedent in In re Mirant Corp.[130] for its holding that rejection in bankruptcy does not equate to a modification or abrogation of a FERC-jurisdictional agreement and that, therefore, the Mobile-Sierra doctrine is not implicated.

Later in 2020, FERC had an opportunity to issue an order addressing the jurisdictional question in response to a petition for declaratory order filed by ETC Tiger Pipeline, LLC (ETC Tiger) in anticipation of a bankruptcy filing that ETC Tiger anticipated Chesapeake would make.[131] In its order granting ETC Tiger’s petition, FERC found that it has concurrent jurisdiction with the bankruptcy courts under NGA sections 4 and 5 with respect to ETC Tiger’s transportation agreements with Chesapeake and that the approval of the bankruptcy court and FERC would be necessary if Chesapeake were to seek to reject the agreements in bankruptcy.[132] Chesapeake subsequently filed for bankruptcy, and filed a motion to reject certain of its agreements with ETC Tiger.

FERC later reiterated its holdings from the ETC Tiger proceeding in four proceedings involving Gulfport and various interstate natural gas pipeline companies.[133] However, in the Gulfport proceedings, FERC went a step further and established proceedings under the NGA and the Mobile-Sierra doctrine to determine if the contracts at issue in each proceeding could be modified or abrogated, including by rejection in bankruptcy. In each of these proceedings, FERC found that there had been no demonstration under the Mobile-Sierra doctrine that modification or abrogation of the agreements at issue was necessitated by the public interest.[134] Gulfport subsequently filed for bankruptcy, and filed motions to reject some of the agreements at issue in the FERC proceedings described above. Many of Gulfport’s motions to reject remain pending.

In addition, a bankruptcy court addressed this jurisdictional challenge for the first time in the context of FERC-jurisdictional interstate oil transportation service agreements under the ICA. In the Extraction bankruptcy proceeding, Extraction sought to reject FERC-jurisdictional transportation agreements with multiple interstate oil pipeline companies, while the oil pipeline companies and FERC argued that FERC approval must be obtained under the ICA and the Mobile-Sierra doctrine. Ultimately, relying on reasoning similar to what was seen in the Ultra and Chesapeake cases, the Bankruptcy Court for the District of Delaware found that FERC authorization was not necessary for Extraction to reject its FERC-jurisdictional agreements with interstate oil pipelines in bankruptcy.[135]


On October 15, 2020, FERC issued a Notice of Proposed Policy Statement (Proposed Policy Statement) on Carbon Pricing in Organized Wholesale Electricity Markets.[136] The Proposed Policy Statement clarified FERC’s jurisdiction over rules that incorporate a state-determined carbon price in markets administered by RTO/ISOs, and encouraged RTO/ISO efforts to explore the establishment of such rules pursuant to section 205 of the FPA.[137] FERC acknowledged that numerous states have commenced decarbonization initiatives,[138] and that carbon pricing has emerged as a key market-based tool in states’ efforts to reduce GHG emissions in the electricity sector.[139]

The Proposed Policy Statement clarified that FERC has jurisdiction over certain “RTO/ISO market rules that incorporate a state-determined carbon price in those markets.”[140] FERC did not categorically assert jurisdiction over such market rules in all instances, but rather explained that such rules “can fall within [FERC’s] jurisdiction as a practice affecting wholesale rates.”[141] FERC explained that, in EPSA, the Supreme Court set forth a two-pronged test for evaluating whether FERC action is within its jurisdiction to regulate practices affecting wholesale rates: (1) the regulated activity must “directly affect” wholesale rates; and (2) the regulated activity must not be a matter that FPA section 201(b) reserves exclusively to the states.[142] FERC reasoned that wholesale market rules that incorporate a state-determined carbon price can meet the first prong because such rules, like the rules at issue in EPSA, “could, depending on the particular circumstances, govern how resources participate in the RTO/ISO market, how market operators dispatch those resources, and how those resources are ultimately compensated.”[143] FERC explained that such rules can satisfy the second prong because rules incorporating state-determined carbon prices in the wholesale markets do not diminish the authority that the FPA reserves to the states, or “otherwise displace state authority, including state authority over generation facilities.”[144] Thus, under the Proposed Policy Statement, states retain the authority to enact and oversee carbon prices.[145]

Through the Proposed Policy Statement, FERC expressly encouraged RTO/ISOs and their stakeholders to consider market rules that incorporate state carbon prices. FERC believes that state carbon pricing rules could help increase the efficiency of wholesale markets.[146] FERC made clear certain important limitations of the Proposed Policy Statement. FERC explained that the Proposed Policy Statement addresses only filings made pursuant to FPA section 205, and not proceedings initiated pursuant to FPA section 206.[147] In other words, FERC declined to take a position on whether it could, or would, require the RTO/ISOs to change their market rules to incorporate carbon prices pursuant to FPA section 206. FERC further made clear that it is “not an environmental regulator,” but instead is tasked with regulating the rules by which generating resources recover the costs of complying with federal and state environmental regulations.[148] FERC sought comments on the Proposed Policy Statement and on five specific considerations to take into account with carbon prices. Numerous entities timely filed comments and reply comments.[149]


In July 2020, FERC finalized a significant reform of regulations and policies that implement the Public Utility Regulatory Policies Act of 1978 (PURPA),[150] a statute enacted in the midst of domestic energy crises in order to promote new generation from independent and unconventional sources.

PURPA aimed to overcome barriers to entry in vertically integrated utility markets by (i) guaranteeing owners and operators of so-called “qualifying facilities” (QFs, which include certain cogeneration and renewable generators, as well as those utilizing certain fuel wastes) the ability to interconnect to an electric utility’s system, (ii) requiring electric utilities to purchase their output at up to an “avoided cost” rate (the cost the electric utility would have incurred to acquire the next unit of generating capacity; avoided cost is established by state regulators), (iii) providing that an electric utility could incur a legally enforceable obligation (LEO) to purchase from a QF even if the utility refused to enter into a formal contract, (iv) mandating that electric utilities must supply backup power to QFs on a non-discriminatory basis, and (v) providing QFs exemptions from aspects of the FPA, the Public Utility Holding Company Act (PUHCA), and certain state laws and regulations that govern utility rates and financial matters, among other protections.

Since PURPA was first enacted, modest changes have been made to the statute, including that FERC gained the flexibility to determine that QFs in certain markets have non-discriminatory market access, and therefore electric utilities need not be required to purchase their outputs. But most of PURPA’s statutory requirements have remained in place. Accordingly, FERC’s new rule preserves many of the basic protections set forth in PURPA, while attempting to respond to concerns from electric utilities, non-QF independent power producers, and some state utilities regulators that PURPA’s provisions are outdated and unreasonably favourable to QFs.

The rule, which became effective December 31, 2020, revises FERC’s PURPA-implementation regulations in five main areas:

  • New flexibility for states in setting the avoided-cost rates for QFs. Under the new rule, the energy rates under a contract or other LEO may change over the course of the term or may be based on project rates over the course of the term (rather than based on avoided cost at time the contract or LEO is established). Sales at as-available rates (an alternative to fixed-rate sales under PURPA) may use locational marginal prices established in certain restructured markets. States may also set as-available energy avoided costs at competitive market hubs or use natural-gas-price indices and specified heat rates. States also gain the flexibility to set energy and capacity rates through competitive solicitations.
  • New “same-site” presumptions. Previously, owners or operators of renewable and waste-fueled QFs reported the capacity of affiliated QFs within one mile using the same generating technology (the one-mile rule) for purposes of determining whether they were at the same site and therefore subject to aggregation for purposes of PURPA’s 80-MW size limit. FERC’s new rule replaced the one-mile rule with a series of presumptions: (1) within one mile, the facilities are irrebuttably presumed to be at the same site; (2) from one mile to ten miles, FERC rebuttably presumes that the facilities are not at the same site, but allows interested parties to rebut this presumption; and (3) beyond ten miles, FERC irrebuttably presumes that the QFs are not at the same site. FERC set forth a series of characteristics that it may use to determine whether affiliated QFs from one to ten miles apart are at the same site, but stated that no single characteristic or set of characteristics would be dispositive.
  • Reduced barriers for challenges. The new rule allows interested parties to challenge QF filings within 30 days of the filing date. QFs that certified before the new rule became effective will receive “legacy” treatment until the first substantive self-recertification filing.[151]
  • Non-discriminatory market access threshold reduction. The new rule reduces the size at which QFs are rebuttably presumed to have non-discriminatory market access, from 20 MW to 5 MW, while establishing certain exceptions.
  • Minimum LEO requirements. The new rule establishes that QFs must demonstrate commercial viability and a financial commitment pursuant to objective standards established by each state. States may also require that a QF has applied for all permits and paid all applicable fees.

FERC also clarified that existing PURPA regulations require states to account for load reductions resulting from retail competition in setting rates for QF capacity sales.

The full impact of the new rule remains to be seen, both because little time has elapsed since the rule became effective and because several changes will have an effect only when states elect to use newly granted flexibilities. In addition, the new rule may be further modified or set aside, as it is currently subject to review by the Ninth Circuit.[152]

Broadview Solar

FERC’s new PURPA rule introduced significant uncertainty in the QF sector. FERC added to this uncertainty for solar photovoltaic (PV) QF interests in September 2020, when it issued its order in Broadview Solar, LLC (Broadview),[153] in which it announced a new framework for determining whether QFs exceed the 80-MW ceiling imposed by PURPA.[154] In a significant break with precedent, FERC determined that its nearly 40-year-old approach emphasizing a QF’s “send-out” or “output” capability, first set forth in Occidental Geothermal, Inc. (Occidental),[155] is inconsistent with PURPA’s focus on “power production capacity.”[156] As part of its revised approach, FERC expressly eliminated the ability to include “adjustments for inverters or other output-limiting devices,”[157] a determination that uniquely affects solar PV QFs, which often utilize arrays with direct current (DC) capacities that are significantly larger (typically 1.3 to 1.5 times) than the facilities’ inverter-dependent alternating current (AC) output for a variety of operational and electrical reasons. Such a facility’s power production capability, under FERC’s new policy, is its DC capacity, rather than the post-inverter AC capacity.

Given the new policy’s potential to create significant disruptions for existing solar PV QFs that would fail to be QFs under the new policy (many of which have offtake agreements that require QF status), FERC expressly limited the application of Broadview to those QFs that self-certify or apply for certification on or after the date of the order.[158]

This ruling has had a focused, but significant, effect on the portion of the solar PV industry that has projects in the development pipeline that approach the 80-MW limit on an AC basis (and exceed it on a DC basis), or that are already QFs, but anticipate near-term recertifications.[159] Entities have requested rehearing and clarification in the case, but FERC has yet to respond. Broadview is subject to review by the D.C. Circuit.[160]


On May 1, 2020, President Trump invoked the International Emergency Economic Powers Act[161] and the National Emergencies Act[162] to issue Executive Order 13920 (E.O. 13920) upon his finding that “foreign adversaries” create and exploit vulnerabilities in the U.S. bulk-power system (BPS).[163]

E.O. 13920 directed the Secretary of Energy to prohibit “any acquisition, importation, transfer, or installation of any [BPS] electric equipment…where the transaction involves any property in which any foreign country or a national thereof has any interest…” whenever the Secretary of Energy has determined, in consultation with heads of other agencies, that (a) the transaction involves BPS electric equipment “designed, developed, manufactured, or supplied, by persons owned by, controlled by, or subject to the jurisdiction or direction of a foreign adversary…” and (b) the equipment poses undue or unacceptable risks (1) of “sabotage to or subversion of the design, integrity, manufacturing, production, distribution, installation, operation, or maintenance of the bulk-power system”; (2) of “catastrophic effects” to critical infrastructure resilience or security, or to the U.S. economy; or (3) to U.S. national security or the safety and security of “U.S. persons.”[164]

E.O. 13920 authorized the Secretary of Energy to: establish criteria for use in pre-qualifying equipment and vendors; identify existing electric equipment that poses undue risks and recommend how to address them; and establish a task force in order to provide for interagency cooperation and information-sharing. Moreover, it required the Secretary of Energy, in consultation with heads of other relevant agencies, to publish rules and regulations in accordance with E.O. 13920 within 150 days, or by September 28, 2020.

In response, the Department of Energy (DOE) issued a Request for Information (RFI) in July 2020 to better “understand the energy industry’s current practices to identify and mitigate vulnerabilities in the supply chain for components of the [BPS].”[165] The RFI posed a series of questions related to foreign ownership, control and influence, as well as cybersecurity and vendor and supply-chain risk management matters, with respect to transformers, reactive-power equipment, circuit breakers, and generation — including hardware and electronics — as a first step in a “phased process.”[166] The DOE also sought information on projected compliance costs across the full scope of E.O. 13920 equipment.

The DOE accepted comments in response to the RFI through August 24, 2020.[167] The nearly 100 commenters included traditional electric utilities, manufacturers and vendors, trade associations and other industry groups. To date, however, DOE has neither issued regulations nor proposed a rulemaking.

Despite the absence of rulemaking activity, DOE Secretary Dan Brouillette issued the Prohibition Order Securing Critical Defense Facilities (Prohibition Order) on December 17, 2020,[168] pursuant to authority granted by E.O. 13920. The Prohibition Order stated that DOE “has reason to believe…that the government of People’s Republic of China…is equipped and actively planning to undermine the BPS,” and so prohibited any “acquisition, importation, transfer, or subsequent installation of” such equipment and components[169] by any “Responsible Utility” that owns or operates “Defense Critical Electric Infrastructure.”[170]


The energy sector in the United States is undergoing a foundational shift as industry participants and state and federal policymakers seek to balance environmental and climate considerations and the need for reliable and reasonably priced energy resources. The many regulatory developments covered in this report show how those changes continue apace, and may have even quickened, over the past 18 months. As the Trump Administration gained momentum on various energy policies mid-term, many states enacted their own measures, sometimes in support of — and other times running counter to — the federal initiatives. These at times conflicting federal and state initiatives have created a complicated and challenging regulatory environment, with various risks and opportunities.

*Robert S. Fleishman is a Partner at Kirkland & Ellis LLP in Washington, D.C., where he represents a range of clients on energy regulatory, enforcement, compliance, transactional, commercial, legislative and public policy matters. He served for close to 15 years as Editor-in-Chief of the Energy Law Journal (published by the Energy Bar Association) and is a former General Counsel and Vice-President for Legislative and Regulatory Policy at Constellation Energy. The author would like to thank the following members of Kirkland’s energy, environment, and tax practices for their assistance: Brooksany Barrowes, Tyler Burgess, Scott Cockerham, Jim Dolphin, Alexandra Famer, Nicholas Gladd, Cassidy Hall, Marcia Hook, Ammaar Joya, Michael Saretsky, Drew Stuyvenberg, and Paul Tanaka. The views, opinions, statements, analysis, and information contained in this report are those of the author and do not necessarily reflect the views of Kirkland & Ellis or any of its past, present, and future clients. This report does not constitute legal advice, does not form the basis for the creation of an attorney-client relationship, and should not be relied on without seeking legal advice with respect to the particular facts and current state of the law applicable to any situation requiring legal advice.

  1. US, Bill HR 133, Consolidated Appropriations Act, 2021, 116th Cong, 2020 (enacted), online (pdf): <>.
  2. See Standing Rock Sioux Tribe v U.S. Army Corps of Engineers, 440 F Supp (3d) 1 (DDC 2020).
  3. Ibid at 29–30.
  4. Standing Rock Sioux Tribe v U.S. Army Corps of Engineers, 471 F Supp (3d) 71 at 75, 87 (DDC 2020).
  5. Standing Rock Sioux Tribe v U.S. Army Corps of Engineers, No. 16-cv-01534-JEB, at 2 (DDC 6 July 2020).
  6. Standing Rock Sioux Tribe v U.S. Army Corps of Engineers, Order, 1:16-cv-01534-JEB (DDC 5 August 2020).
  7. Standing Rock Sioux Tribe, et al. v U.S. Army Corps of Engineers, United States Army Corps of Engineers’ Status Report, Case No. 1:16-cv-01534 (JEB), at 2 (31 August 2020).
  8. The Secretary of State has been designated to receive all applications for the issuance or amendment of Presidential permits for the construction, connection, operation, or maintenance of certain cross-border facilities, including products pipelines. See Issuance of Permits with Respect to Facilities and Land Transportation Crossings at the International Boundaries of the United States, Exec. Order 13867, 84 Fed Reg 15491 (10 April 2019); Issuance of Permits With Respect to Certain Energy-Related Facilities and Land Transportation Crossings on the International Boundaries of the United States, Exec. Order No. 13337, 69 Fed Reg 25299 (30 April 2004); Providing for the Performance of Certain Functions Heretofore Performed by the President with Respect to Certain Facilities Constructed and Maintained on the Borders of the United States, Exec. Order 11423, 33 Fed Reg 11741 (20 August 1968).
  9. Authorizing TransCanada Keystone Pipeline, L.P., to Construct, Connect, Operate, and Maintain Pipeline Facilities at the International Boundary between the United States and Canada, 84 Fed Reg 13101, Article 1(1) (3 April 2019).
  10. Ass’n of Bus. Advocating Tariff Equity v Midcontinent Indep. Sys. Operator, Inc., 171 FERC ¶ 61,154 (2020) (MISO Order), aff’d in part, set aside in part, 173 FERC ¶ 61,159 (2020).
  11. Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines, 171 FERC ¶ 61,155 (2020) (Pipeline ROE Policy Statement).
  12. Power Comm’n v Hope Natural Gas Co, 320 US 591 at 603 (1944).
  13. Coakley v Bangor Hydro-Elec. Co., 165 FERC ¶ 61,030 (2018).
  14. Inquiry Regarding the Commission’s Policy for Determining the Return on Equity, 166 FERC ¶ 61,207 (2019).
  15. Ass’n of Bus. Advocating Tariff Equity v Midcontinent Indep. Sys. Operator, Inc., Opinion No. 569, 169 FERC ¶ 61,129 (2019).
  16. Ibid at para 1.
  17. See PJM Interconnection, L.L.C., 170 FERC ¶ 61,295 (2020), order on reh’g and clarification, 172 FERC ¶ 61,205 (2020), appealed sub nom. New York Power Auth. v. FERC, DC Cir Case No. 20-1283; Appalachian Power Co., 170 FERC ¶ 61,196 (2020), order addressing arguments raised on reh’g, 173 FERC ¶ 61,157 (2020), appealed sub nom. Am. Mun. Power, Inc. v. FERC, DC Cir Case No. 21-1011; Delaware Pub. Serv. Comm’n, 171 FERC ¶ 61,024 (2020), appealed sub nom. PPL Elec. Utils. Corp. v. FERC, DC Cir Case No. 20-1390; Midcontinent Indep. Sys. Operator, 170 FERC ¶ 61,241 (2020), order addressing arguments raised on reh’g, 172 FERC ¶ 61,100 (2020), appealed sub nom. MISO Transmission Owners v. FERC, DC Cir Case No. 20-1261; Linden VFT, LLC, 170 FERC ¶ 61,122 (2020), appealed sub nom. Linden VFT, LLC v. FERC, DC Cir Case No. 20-1382; ISO New England Inc., 172 FERC ¶ 61,293 (2020), appealed sub nom, LSP Transmission Holdings II, LLC v. FERC, DC Cir Case No. 20-1422; Coal. of MISO Transmission Customers, 172 FERC ¶ 61,099 (2020), appealed sub nom. Coal. of MISO Transmission Customers v. FERC, DC Cir Case No. 20-1421; PJM Interconnection, L.L.C., 171 FERC ¶ 61,212 (2020), addressing arguments on reh’g, 172 FERC ¶ 61,292 (2020).
  18. See LSP Transmission Holdings, LLC v Sieben, 954 F (3d) 1018 at 1025, 1031 (8th Cir 2020).
  19. LSP Transmission Holdings, LLC filed the petition on November 5, 2020, in Docket No. 20-641.
  20. See Tex Util Code §§ 37.051, 37.056, 37.057, 37.151, 37.154.
  21. See NextEra Energy Capital Holdings, Inc. v Walker, Order on Motion to Dismiss, Civil No. 1:19-cv-00626 (WD Tex 2020).
  22. Case No. 20-50160, United States Court of Appeals for the Fifth Circuit, Clerk’s Calendar, online: <>.
  23. Case No. 05771 CVCV060840, Iowa District Court for Polk County (Oct. 14, 2020).
  24. Allegheny Def. Project v FERC, 964 F (3d) 1 (DC Cir 2020).
  25. 15 USC §§ 717f(c), 717b.
  26. Limiting Authorizations to Proceed with Construction Activities Pending Rehearing, 171 FERC ¶ 61,201 (2020).
  27. 15 USC § 717r(a).
  28. Cal Co. v FPC, 411 F (2d) 720 at 721 (DC Cir 1969) (per curiam).
  29. See Allegheny Def. Project v FERC, 932 F (3d) 940 at 948 (DC Cir 2019) (Millett, J., concurring).
  30. Allegheny Def. Project, 964 F (3d) at 3-4.
  31. Compare 15 USC § 717r with 16 USC § 825l.
  32. EPA, Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units, Final rule, 80 Fed Reg 64661 (23 October 2015).
  33. EPA, Repeal of the Clean Power Plan; Emission Guidelines for Greenhouse Gas Emissions From Existing Electric Utility Generating Units; Revisions to Emission Guidelines Implementing Regulations, Final Rule, 84 Fed Reg 32520 (8 July 2019).
  34. See West Virginia v EPA, No. 15-1363 (DC Cir) (17 September 2019 Order).
  35. EPA, supra note 33.
  36. See Lung Assoc. v EPA, No. 19-1140 (DC Cir), consolidated with New York v EPA, No. 19-1165 (DC Cir); Appalachian Mountain Club v EPA, No. 19-1166 (DC Cir); Chesapeake Bay Found., Inc v EPA, No. 19-1173 (DC Cir); Robinson Enter., Inc. v EPA, No. 19-1175 (DC Cir); Westmoreland Mining Holdings v EPA, No. 19-1176 (DC Cir); City and Cnty. of Denver Colo. v EPA, No. 19-1177 (DC Cir); N. Am. Coal Corp. v EPA, No. 19-1179 (DC Cir); Biogenic CO2 Coal. v EPA, No. 19-1185 (DC Cir); Advanced Energy Econ. v EPA, No. 19-1186 (DC Cir); Am. Wind Energy Assoc. v EPA, No. 19-1187 (DC Cir); Consol. Edison, Inc. v EPA, No. 19-1188 (DC Cir).
  37. EPA has, however, issued general updates to the NSR program which may reduce regulatory burdens for existing power generation facilities. For example, on October 22, 2020, EPA announced, that it was finalizing a rule to clarify the process for evaluating whether NSR permitting would apply to proposed projects at existing major stationary emissions sources, including power generation facilities. The rule seeks to eliminate NSR permitting where a proposed project would result in emissions decreases.
  38. CEQ, Update to the Regulations Implementing the Procedural Provisions of the National Environmental Policy Act, Final Rule, 85 Fed Reg 43304 (16 July 2020).
  39. See Wild Va. v CEQ, No. 3:20-cv-00045 (WD Va) (Wild Virginia); Alaska Cmty. Action on Toxics v CEQ, No. 3:20-cv-05199 (ND Cal); Envtl. Just. Health All. v CEQ, No. 1:20-cv-6143 (SDNY); Cal. v CEQ, No. 3:20-cv-06057 (ND Cal); Iowa Citizens for Cmty. Improvement v CEQ, No. 1:20-cv-02715 (DDC).
  40. Executive Office of the President Office of Management and Budget, “Memorandum for the Heads of Executive Departments and Agencies—Budget and Management Guidance on Updates to the Regulations Implementing the Procedural Provisions of the National Environmental Policy Act” (2 November 2020), online (pdf): <>.
  41. EPA, The Safer Affordable Fuel-Efficient (SAFE) Vehicles Rule Part One: One National Program, Withdrawal of Waiver, Final Rule, 84 Fed Reg 51310 (27 September 2019).
  42. See California v Chao, No. 1:19-cv-02826 (DDC); consolidated with S. Coast Air Quality Mgmt. Dist. v Chao, No. 1:19-cv-03436 (DDC); Envtl. Defense Fund v Chao, No. 1:19-cv-02907 (DDC).
  43. See Union of Concerned Scientists v. NHTSA, No. 19-1230 (DC Cir); consolidated with Cal. v Wheeler, No. 19-1239 (DC Cir); S. Coast Air Quality Mgmt. Dist. v EPA, No. 19-1241 (DC Cir); Nat. Coal. for Advanced Transp. v EPA, No. 19-1242 (DC Cir); Sierra Club v EPA, No. 19-1243 (DC Cir); Calpine Corp. v EPA, No. 19-1245 (DC Cir); City and Cty. of San Francisco v Wheeler, No. 19-1246 (DC Cir); Advanced Energy Econ. v EPA, No. 19-1249 (DC Cir); Nat. Coal. for Advanced Transp. v EPA, No. 20-1175 (DC Cir); Ctr. for Biological Diversity v EPA, No. 20-1178 (DC Cir).
  44. EPA, The Safer Affordable Fuel-Efficient (SAFE) Vehicles Rule for Model Years 2021-2026 Passenger Cars and Light Trucks; Final Rule, 85 Fed Reg 24174 (30 April 2020), amended in 85 Fed Reg 40901 (8 July 2020).
  45. California Air Resources Board, “Framework Agreements on Clean Cars” (17 August 2020), online: <>.
  46. See e.g. Coral Davenport, “G.M. Drops Its Support for Trump Climate Rollbacks and Aligns With Biden” New York Times (23 November 2020), online: <>; David Shepardson, “Nissan joins GM in exiting auto group backing Trump” Automotive News (4 December 2020), online: <>.
  47. Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, 162 FERC ¶ 61,127 (2018), on reh’g and clarification, 167 FERC ¶ 61,154 (2019), Order No. 841-A (denying the requests for rehearing and affirming its determinations in Order No. 841) [Order No. 841].
  48. Several entities filed requests for rehearing and clarification of Order No. 841. On May 16, 2019, FERC issued an order denying the rehearing requests, and denying in part and granting in part the clarification requests. See Order No. 841-A.
  49. National Association of Regulatory Utility Commissioners v FERC, 964 F (3d) 1177 at 1180 (DC Cir 2020).
  50. See ibid at 1188–89.
  51. See FERC Docket Nos. ER19-460 (Southwest Power Pool, Inc.’s Order No. 841 compliance docket), ER19-465 (Midcontinent Independent System Operator, Inc.’s Order No. 841 compliance docket), ER19-467 (New York Independent System Operator, Inc.’s Order No. 841 compliance docket), ER19-468 (California Independent System Operator Corp.’s Order No. 841 compliance docket), ER19-469 (PJM Interconnection, L.L.C.’s Order No. 841 compliance docket), ER19-470 (ISO New England, Inc.’s Order No. 841 compliance docket).
  52. Midcontinent Indep. Sys. Operator, 172 FERC ¶ 61,132 at para 1 (2020)
  53. See Utilization of Electric Storage Resources for Multiple Services When Receiving Cost-Based Rate Recovery, 158 FERC ¶ 61,051 at para 9 (2017); Western Grid Dev., 130 FERC ¶ 61,056 at paras 1–2 (2010).
  54. See PJM Interconnection L.L.C., “Meeting Details” (last visited 3 February 2021), online: <{6D298032-D049-4D3E-A53E-0BE8892AFFC8}>.
  55. Electric Power Serv. Corp., 173 FERC ¶ 61,264 at para 37 (2020) (Kentucky Power Company is an affiliate of American Electric Power Company).
  56. Ibid at para 35.
  57. Calpine Corp. v PJM Interconnection, L.L.C., 163 FERC ¶ 61,236 (2018).
  58. Calpine Corp. v PJM Interconnection, L.L.C., 169 FERC ¶ 61,239 (2019), order on reh’g, 171 FERC ¶ 61,035 (2020).
  59. December 2019 Order at para 9.
  60. Ibid.
  61. Ibid.
  62. Calpine Corp. v PJM Interconnection, L.L.C., 173 FERC ¶ 61,061 (2020) (October 2020 Order).
  63. While FERC defined State Subsidy in the December 2019 Order, PJM proposed a slightly modified definition in the compliance filing that FERC accepted in the October 2020 Order. PJM defined State Subsidy as “a direct or indirect payment, concession, rebate, subsidy, non-bypassable consumer charge, or other financial benefit that is a result of any action, mandated process, or sponsored process of a state government, political subdivision or agency of a state or an electric cooperatives formed pursuant to state law, and that (1) is derived from or connected to the procurement of (a) electricity or electric generation capacity sold at wholesale in interstate commerce, or (b) an attribute of the generation process for electricity or electric generation capacity sold at wholesale in interstate commerce; or (2) will support the construction, development, or operation of new or existing Capacity Resource; or (3) could have the effect of allowing a unit to clear in any PJM capacity auction.” Ibid at paras 37, 41. Additionally, FERC accepted PJM’s proposal to exclude seven programs from the definition of State Subsidy. Ibid at paras 43, 45.
  64. Ibid at para 30.
  65. Ibid at paras 69, 87.
  66. Ibid at paras 112, 122, 143,165, 280.
  67. Ibid at para 229.
  68. U.S. Energy Information Administration, “Summary of Legislation and Regulations Included in the Annual Energy Outlook 2021” (February 2021), online: <> (last accessed 8 February 2021).
  69. Kassia Micek, Commodities 2021: States racing to set goals toward net-zero emission, 100% renewable electricity, S&P Global Platts (24 December 2020), online: <> (last accessed 8 February 2021).
  70. Ibid.
  71. Ibid.
  72. Ibid.
  73. Ibid.
  74. Ibid.
  75. Ibid.
  76. See Order Adopting Regulations, Case No. PUR-2020-00120, Va State Corp Comm’n (18 December 2020).
  77. 2018 Mass Acts Ch 227.
  78. 225 CMR 21.05(1)(a) (2020).
  79. “Seasonal Peak Period” means the “time periods during the Clean Peak Seasons when the Net Demand for electricity is typically highest. The Seasonal Peak Periods shall not be less than one (1) hour and not longer than four (4) hours each Business Day in any Clean Peak Season; will be determined on a prospective basis no later than six (6) months prior to the next Compliance year; shall be revised no more than once every three (3) years; and the [DOER] reserves the discretion to exempt existing resources from adjustments to the Seasonal Peak Periods in effect at the time of their qualification.” 225 CMR 21.02.
  80. 225 CMR 21.05(6).
  81. 225 CMR 21.07(1)(a).
  82. 225 CMR 21.07(1)(b).
  83. 225 CMR 21.05(8)(a)-(b).
  84. 225 CMR 21.08(3). The initial Alternative Compliance Payment (ACP) rate is $45.00 per MWh through the 2024 compliance year, and it will decline by $1.54 per MWh each compliance year thereafter through 2050, or until the ACP rate reaches $4.96 per MWh. The rate will then remain at $4.96 per MWh for the duration of the Clean Peak Standard program. Like the long-term contract requirement, this automatic reduction may be adjusted based on market supply.
  85. Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 2222, 172 FERC ¶ 61,247 (2020) . FERC defined DER as “any resource located on the distribution system, any subsystem thereof or behind a customer meter.” Ibid n.1. Such resources “may include, but are not limited to, electric storage resources, distributed generation, demand response, energy efficiency, thermal storage, and electric vehicles and their supply equipment.” Ibid.
  86. Ibid at paras 26–28.
  87. Ibid at para 29.
  88. Ibid at para 6.
  89. Ibid at para 8.
  90. See ibid at para 56.
  91. Ibid at para 64.
  92. Ibid.
  93. Ibid at para 61.
  94. Ibid at para 360; see also Department of Energy, Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators; Notice of Correction in Federal Register of Compliance Deadline, 85 Fed Reg 70143 (4 November 2020).
  95. PG&E, News Release, “Files for Reorganization Under Chapter 11” (29 January 2019) online: <>.
  96. See NextEra Energy, Inc. v Pac. Gas & Elec. Co., 166 FERC ¶ 61,049 at para 28 (2019); Exelon Corp. v Pac. Gas & Co., 166 FERC ¶ 61,053 at para 25 (2019).
  97. In re PG&E Corporation, No. 19-30088-DM (Bankr ND Cal) (7 June 2019), (Memorandum Decision on Action for Declaratory and Injunctive Relief), online (pdf): <>.
  98. See e.g. Ivan Penn, “PG&E, Troubled California Utility, Emerges from Bankruptcy”, New York Times (1 July 2020), online: <>.
  99. Gas & Elec. Co. v FERC et al., No. 19-71615 (7 October 2020), online (pdf): <>.
  100. Department of the Interior, Waste Prevention, Production Subject to Royalties, and Resource Conservation; Rescission or Revision of Certain Requirements, Final Rule, 83 Fed Reg 49184 (28 September 2018).
  101. California v Bernhardt, consolidated with Sierra Club v Bernhardt, No. 4:18-cv-05712-YGR (ND Cal.).
  102. California v Zinke, Nos. 20-16793, 20-16794, 20-16801 (9th Cir).
  103. Wyoming v U.S. Dep’t of the Interior, No. 2:16-CV-00285 (D Wyo); consolidated with Western Energy Alliance v Jewell, 2:16-CV-0280 (D Wyo).
  104. EPA, Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration, Final Rule, 85 Fed Reg 57398 (15 September 2020).
  105. California v Wheeler, No. 20-1357 (DC Cir); Defense Fund v Wheeler, No. 20-01359 (DC Cir).
  106. IRS, “Guidance on Structuring Transactions” (Rev. Proc. 2020-12), online (pdf): <>; IRS, “Beginning of Construction for the Credit for Carbon Oxide Sequestration under Section 45Q” (Notice 2020-12), online (pdf): <>.
  107. Department of the Treasury, Credit for Carbon Oxide Sequestration, Notice of proposed rulemaking, 85 Fed Reg 34050 (2 June 2020).
  108. Final regulations, Credit for Carbon Oxide Sequestration, 86 Fed Reg 4728 (15 January 2021).
  109. FERC, “2020 Report on Enforcement” (19 November 2020) at 31, online (pdf): <>.
  110. Ibid at 7.
  111. FERC, “2019 Report on Enforcement” (21 November 2019) at 8, online (pdf): <>.
  112. FERC, supra note 109 at 5.
  113. Ibid at 5–6.
  114. Vitol Inc. and Federico Corteggiano, 169 FERC ¶ 61,070 at para 1 (2019).
  115. Ibid.
  116. 16 USC § 823b(d)(3)(B).
  117. FERC v Vitol Inc. and Federico Corteggiano, Complaint, Case No. 2:20-cv-00040-KJM-AC (6 January 2020).
  118. FERC v Vitol Inc. and Federico Corteggiano, Vitol, Inc. Notice of Motion and Motion to Dismiss, Case No. 2:20-cv-00040-KJM-AC (6 March 2020) [Vitol Motion to Dismiss].
  119. Ibid.
  120. FERC v Powhatan Energy Fund, LLC, 949 F (3d) 891 (4th Cir 2020).
  121. Vitol Motion to Dismiss at 3.
  122. CFTC, “FY 2020 Division of Enforcement Annual Report” at 1 (1 December 2020), online (pdf): <>.
  123. Ibid.
  124. In the matter of Vitol Inc., Order Instituting Proceedings Pursuant to Section 6(c) and 6(d) of the Commodity Exchange Act, Making Findings, and Imposing Remedial Sanctions, CFTC Docket No. 21-01 at 6 (3 December 2020).
  125. Ibid at 1.
  126. As background, Section 365 of the Bankruptcy Code allows a trustee or a debtor-in-possession in bankruptcy to “assume or reject any executory contract”. 11 U.S.C. § 365(a). Thus, debtors have the ability to determine “whether the contract is a good deal for the estate going forward.” Mission Prod. Holdings, Inc. v. Tempnology, LLC, 139 S Ct 1652 at 1658 (2019). Bankruptcy courts generally approve the debtor’s decision regarding whether to reject or assume the executory contract under the deferential business judgment standard. Ibid. The Bankruptcy Code explicitly states that rejection of a contract “constitutes a breach of such contract.” 11 U.S.C. § 365(g).
  127. See In re Ultra Petroleum Corp., 621 BR 188 at 198 (Bankr SD Tex 21 August 2020) (concluding that “the FERC approved contract at issue here falls within the broad scope of ‘all executory contracts.’ Thus, the Agreement is subject to rejection.” (internal citations omitted)); In re Extraction Oil & Gas, et al., 622 BR 608 at 614 (Bankr D Del 2 November 2020) (“There is no prohibition on or limitation against rejecting a FERC approved contract.”).
  128. Petition for Declaratory Order and Request for Expedited Action of Rockies Express Pipeline LLC, Rockies Express Pipeline LLC, Docket No. RP20-822-000 (filed 29 April 2020). Under the Mobile-Sierra doctrine, FERC is the only entity that may modify or abrogate filed rates, and it only may do so upon a finding that the filed rate harms the public interest. See United States Pipe Line Co. v Mobile Gas Serv. Corp., 350 US 332 at 339 (1956); Fed. Power Comm’n v Sierra Pac. Power Co., 350 US 348 at 353 (1956).
  129. In re Ultra Petroleum, No. 20-32631, 2020 WL 4940240 (Bankr SD Tex 2020).
  130. 378 F (3d) 511 (5th Cir 2004).
  131. Petition for Declaratory Order and Request for Expedited Action of ETC Tiger Pipeline, LLC, ETC Tiger Pipeline, LLC, Docket No. RP20-881-000 (filed 19 May 2020);ETC Tiger Pipeline, LLC, 171 FERC ¶ 61,248 (2020).
  132. ETC Tiger Pipeline, LLC, 171 FERC ¶ 61,248 at para 20 (2020).
  133. See e.g., Rockies Express Pipeline LLC, 172 FERC ¶ 61,279 at para 27 (2020); Midship Pipeline Co., LLC, 173 FERC ¶ 61,011 at para 29–30 (2020); ANR Pipeline Co. et al., 173 FERC ¶ 61,018 at para 27–28 (2020); Rover Pipeline LLC, 173 FERC ¶ 61,019 para 25–26 (2020).
  134. See e.g., Rockies Express Pipeline, LLC, 173 FERC ¶ 61,099 at para 1 (2020); Midship Pipeline Co., LLC, 173 FERC ¶ 61,130 at para 1 (2020); ANR Pipeline Co. et al., 173 FERC ¶ 61,131 at para 1 (2020); Rover Pipeline LLC, FERC ¶ 61,133 at para 1 (2020).
  135. In re Extraction Oil & Gas, Inc., No. 20-11548, 2020 WL 6389252 (Bankr D Del 2020).
  136. Carbon Pricing in Organized Wholesale Electricity Markets, Notice of Proposed Policy Statement, 173 FERC ¶ 61,062 (2020).
  137. Ibid at para 1.
  138. In the Proposed Policy Statement, FERC uses “carbon pricing” to “include both ‘price-based’ methods adopted by states that directly establish a price on GHG emissions as well as ‘quantity-based’ approaches adopted by states that do so indirectly.” Ibid at para 3.
  139. Ibid at para 2.
  140. Ibid at para 7.
  141. Ibid at para 8.
  142. Ibid at paras 9, 11 (citing FERC v Elec. Power Supply Ass’n, 136 S. Ct. 760 at 774–75 (2016), as revised (28 January 2016) (EPSA)).
  143. 173 FERC ¶ 61, 062 at para 10.
  144. Ibid at para 12.
  145. Ibid.
  146. Ibid at para 15.
  147. Ibid at para 1, n.2.
  148. Ibid at paras 4–5.
  149. See Docket No. AD20-14-000.
  150. See Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872, 172 FERC ¶ 61,041 (2020) (Order No. 872), clarified by Qualifying Facility Rates and Requirements Implementation Issues Under the Public Utility Regulatory Policies Act of 1978, Order No. 872-A, 173 FERC ¶ 61,158 (2020) (Order No. 872-A).
  151. See Order No. 872 at paras 549-550. Examples of “substantive” changes are increases in generating capacity of 1 MW or 5 percent of installed capacity, or a 10 percent or greater increase in equity interest by an owner. Order No. 872 at para 550, Order No. 872-A at para 323.
  152. Ninth Circuit, Case Nos. 20-72788, 20-73375, and 21-70113.
  153. Broadview Solar, LLC, 172 FERC ¶ 61,194 (2020).
  154. See 16 USC § 796(17)(A)(ii) and 18 CFR § 292.204(a)(1).
  155. Occidental Geothermal, Inc., 17 FERC ¶ 61,231 (1981).
  156. Broadview, supra note 153 at para 23.
  157. Ibid at para 25.
  158. Ibid at para 27. FERC stated:
    [i]f a QF that has listed a maximum net power production capacity of 80 MW or less has a Form No. 556 on file with the Commission prior to the date of this order, even if it may have included adjustments for inverters or other output-limiting devices to calculate its maximum net power production capacity as 80 MW or less, then it will be grandfathered with regard to the holding in Occidental. In other words, those previously certified QFs will still be considered to be small power production facilities for purposes of PURPA.
  159. While FERC expressly stated that it would “grandfather” QFs that had self-certified or applied for QF status prior to September 1, it did not expressly address the effects of recertification.
  160. DC Cir, Case Nos. 20-1487 and 20-1500.
  161. 50 USC § 1701 et seq.
  162. 50 USC § 1601 et seq.
  163. Securing the United States Bulk-Power System, Exec. Order No. 13920, 85 Fed Reg 26595 (4 May 2020).
  164. Ibid at 26,595–96. E.O. 13920 defines “bulk power system” as meaning “(i) facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof); and (ii) electric energy from generation facilities needed to maintain transmission reliability.” The definition includes transmission lines rated at 69,000 volts (69 kV) or more, but does not include local distribution facilities. “Bulk power system electric equipment” means “control rooms, or power generating stations, including reactors, capacitors, substation transformers, current coupling capacitors, large generators, backup generators, substation voltage regulators, shunt capacitor equipment, automatic circuit reclosers, instrument transformers, coupling capacity voltage transformers, protective relaying, metering equipment, high voltage circuit breakers, generation turbines, industrial control systems, distributed control systems, and safety instrumented systems.”
  165. Department of Energy, Securing the United States Bulk Power System, Request for information, 85 Fed Reg 41023 (8 July 2020).
  166. Ibid at 41024.
  167. Department of Energy, Securing the United States Bulk Power System, Extension of public comment period, 85 Fed Reg 44061 (21 July 2020).
  168. Department of Energy, Prohibition Order Securing Critical Defense Facilities, Prohibition Order, 86 Fed Reg 533 (6 January 2021).
  169. Ibid.
  170. Ibid at 534. Defense Critical Electric Infrastructure is defined in Section 215A(a)(4) of the FPA (16 U.S.C. § 824o-1) as any electric infrastructure located in any of the 48 contiguous States or the District of Columbia that (i) serves a facility designated by the Secretary of Energy as (A) critical to the defense of the United States and (B) vulnerable to a disruption of the supply of electric energy provided to such facility by an external provider, but (ii) is not owned or operated by the owner or operator of the facility designated in clause (i).

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