Brett A. Snyder, Frederick M. Lowther, and Jane Thomas
On July 16, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 872 (“Order”), a final rule that significantly revised its rules implementing the Public Utility Regulatory Policies Act of 1978 (“PURPA”). Congress enacted PURPA to reduce the country’s reliance on oil and natural gas by promoting “Qualifying Facilities” (“QFs”) that rely on alternative energy sources or more efficient generation. Since their promulgation, FERC’s regulations implementing PURPA have been largely unaltered. FERC opined that the energy industry has substantially evolved since PURPA was promulgated and that the final rule is necessary to address the changing landscape and more closely align with underlying congressional intent.
Among other things, PURPA requires electric utilities to offer to purchase electric energy from QFs, which are categorized as either small power producers or cogenerators. The rate that a QF may receive for energy must be a rate “not to exceed the incremental cost to the electric utility of alternative electric energy,” which is “the cost to the electric utility of the electric energy which, but for the purchase from such cogenerator or small power producer, such utility would generate or purchase from another source.” In other words, “the purchasing utility cannot be required to pay more for power purchased from a QF than it would otherwise pay to generate the power itself or to purchase power from a third party.” This is referred to as the utility’s “avoided cost.”
Rates for energy are generally categorized as either fixed or “as-available.” Fixed rates are generally fixed at the time of the contract or other legally enforceable obligation (“LEO”) between the QF and the utility and do not vary over the term of the contract or LEO. For example, many renewable energy projects, which generally produce only to sell into the market and rely on a fixed revenue stream for financing, often rely on fixed energy rates. Conversely, other types of generators, such as cogeneration facilities, might only sell into the market when they have excess energy and will take the prevailing price at the time of sale. This rate is referred to as an “as-available” energy rate and is variable. Rates for capacity are generally fixed at the time of contract or LEO. QF rates for energy and capacity are set by state commissions.
Order No. 872 follows a technical conference, notice of proposed rulemaking (“NOPR”), and multiple rounds of industry comments. The Order adopts most of the NOPR proposals and substantially alters the rules for QFs.
Please click here for the full client alert.
Mark R. Haskell, Brett A. Snyder, Lamiya N. Rahman, and Jane Thomas
On March 19, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) announced several regulatory responses to the coronavirus pandemic and FERC Chairman Neil Chatterjee held a press conference to discuss the agency’s initiatives. The Chairman emphasized the capabilities of the Commission and its staff to work in a timely manner throughout the pandemic response, while striving to provide necessary flexibility to regulated entities.
The Chairman named Caroline Wozniak, a Senior Policy Advisor in the Office of Energy Market Regulation, as the point of contact for all energy industry inquiries related to the impacts of COVID-19. Members of the regulated community may e-mail PandemicLiaison@FERC.gov with questions for Commission staff.
Chairman Chatterjee clarified that the Commission will provide regulated entities with flexibility when needed, but emphasized the Commission is fully functioning and will try not to delay decisions. Chairman Chatterjee also stated his goal is to issue certain rehearing orders involving pipeline certificate projects challenged by affected landowners within 30 days, consistent with guidance from the Chairman issued on January 31, 2020.
Please click here for the full client alert.
Margaret Anne Hill, Christopher A. Lewis, Frederick M. Lowther, Frank L. Tamulonis III, and Stephen C. Zumbrun
At the outset of 2019, Pennsylvania Governor Tom Wolf set a goal for Pennsylvania to significantly reduce greenhouse gas emissions. Now, Governor Wolf plans to achieve that goal by taking the bold step to establish a carbon dioxide cap-and-trade program through executive action. On October 3, 2019, Governor Wolf issued an Executive Order directing the Pennsylvania Department of Environmental Protection (“DEP”) to begin the process for Pennsylvania to join the Regional Greenhouse Gas Initiative (“RGGI”, pronounced “Reggie”). RGGI is a market-based cap-and-trade program implemented by several Northeast states to reduce power sector CO2 emissions. Governor Wolf’s Executive Order made national headlines because of the potential implications of Pennsylvania—a state known for its coal and natural gas reserves—joining RGGI. But this news is only the start of a long regulatory process, one that could realistically take years to become implemented. At this stage, Pennsylvania fossil-fuel power generators should familiarize themselves with RGGI’s requirements and procedures as well as the rulemaking process by which the Commonwealth might join RGGI.
The RGGI Program
RGGI is a collective effort by its member states to create a Northeast regional cap-and-trade program affecting fossil-fuel power plants greater than 25 megawatts. Member states—currently Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island, and Vermont, with New Jersey in the process of rejoining—each enact statutory or regulatory programs in their respective states that are RGGI compliant. CO2 emitting power plants then participate in RGGI regional auctions to purchase CO2 emission allowances for usage, or to sell on secondary markets. RGGI caps the total amount of CO2 emission allowances, measured in tons of carbon, with the most recent cap being 80.2 MM-tons. Beginning in 2021, the cap will be set at 75.1 MM-tons, which will then be reduced by 30 percent between 2020 and 2030. Proceeds from the auctions are distributed to the respective states for investment in programs to further reduce CO2 emissions, such as energy efficiency, renewable energy, or consumer benefit programs. Continue reading “Pennsylvania Plans to Join the RGGI CO2 Cap-and-Trade Program”
Mark R. Haskell, Frederick M. Lowther, and Lamiya N. Rahman
With the May 1 order, the Commission reaffirms its view that it has concurrent jurisdiction over debtors’ efforts to reject their FERC-jurisdictional contracts in bankruptcy. Further developments in judicial proceedings in the Sixth and Ninth Circuits are expected.
On May 1, 2019, the Federal Energy Regulatory Commission (“FERC” or “the Commission”) denied Pacific Gas and Electric Company’s (“PG&E”) requests for rehearing of two Commission orders asserting concurrent jurisdiction with bankruptcy courts over the disposition of wholesale power contracts PG&E seeks to reject through bankruptcy.1
In its Rehearing Order, the Commission acknowledged a circuit split regarding the relative authorities of the Commission under the Federal Power Act (“FPA”) and the bankruptcy courts under the Bankruptcy Code as they relate to the review and disposition of FERC-jurisdictional contracts in bankruptcy proceedings. However, the Commission affirmed its prior holdings that that “the way to give effect to both the FPA and the Bankruptcy Code is for a party to a Commission-jurisdictional wholesale power contract to obtain approval from both the Commission and the bankruptcy court to modify the filed rate and reject the contract, respectively.”2 Continue reading “In PG&E Bankruptcy, FERC Reasserts Concurrent Jurisdiction over the Disposition of Wholesale Power Contracts”
Frederick M. Lowther
The ingenuity of the renewable energy industry and the energy-oriented financial players is never to be doubted. Within the past few years, several creative financial tools have emerged to support the development of new wind and solar projects as well as further advances in large-building energy efficiency. The traditional regulatory and financial incentives for renewable energy and energy efficiency projects—investment tax credits, production tax credits, mandated renewable portfolio standards, mandated energy efficiency targets—remain in place (at least for now). However, there is a new incentive at play, one which until recently the industry has not tried to monetize. The new incentive is the desire, indeed the perceived need, of certain companies to “go green,” to demonstrate a commitment to improving the climate in the face of growing public concerns about climate change. Companies that produce consumer products—beer, bread, computers, pharmaceuticals, etc.—and companies that provide services—telecommunications, online shopping, search engines—have concluded that there is ascertainable value to putting words like “100% Renewable Energy” on bags, cans, and packaging; on social media advertising; and on bricks and mortar. Building owners perceive ascertainable value in labeling their buildings as “green” buildings. What the creative minds of the energy and financial industry players have done is develop vehicles to capture and quantify those values, and put them to use.
This blog post discusses three such vehicles: the Virtual Power Purchase Agreement (“VPPA”), the Virtual Net Metering Program (“VNMP”), and Metered Energy Efficiency Credits (“MEECs”). All three are relatively new, relatively complex, and in two cases—VPPA and VNMP—substantially regulated. However, the basic concepts are easy to explain and that is the goal of this post. Continue reading “The Emergence of Creative Financial Tools for Renewable Energy and Energy Efficiency Projects”
Margaret Anne Hill and Stephen C. Zumbrun
Right now, cases involving climate change are being heavily litigated in courts across the United States. Hundreds of climate change-related cases have been filed in both federal and state courts, where parties are challenging governments’ and industry’s knowledge of and contribution to climate change. In the abstract, one would think that litigation involving emissions of greenhouse gases (“GHG”) linked to climate change would largely focus on the federal Clean Air Act. Yet, climate change-related cases now involve ever-expanding causes of action, including not only claims under the federal Clean Air Act and other federal statutes, but claims under the U.S. Constitution, state law claims, and common law claims.
There are several active cases that may have major implications on the government’s role in determining the direction of climate change policy, and on private companies’ past and future liability for alleged contributions to climate change, as well as knowledge of climate change impacts on business decision-making. This article discusses notable current cases involving climate change. Continue reading “Charting Climate Change Cases: A Survey of Recent Litigation”
Stephen C. Zumbrun
In a move that has excited the renewable energy and electric storage industries, the Federal Energy Regulatory Commission (“FERC”) last month voted to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by Regional Transmission Organizations (“RTO”) and Independent System Operators (“ISO”). Pursuant to Section 206 of the Federal Power Act, which requires “just and reasonable rates,” FERC amended 18 C.F.R. § 35.28 to require RTOs/ISOs to revise their tariffs to establish market rules that recognize the physical and operational characteristics of electric storage resources and to facilitate their participation in the RTO/ISO markets. In the same order, FERC also punted on a decision for distributed energy resource aggregation reforms and called for a technical conference to further study possible reforms for the RTO/ISO markets. Continue reading “FERC Advances the Ball on Electric Storage, Calls for a Huddle on Distributed Energy Resource Aggregation”