LIBOR Transition Will Begin to Accelerate as 2021 Approaches

Over the course of the next several months, participants that are actively engaged in project financing will need to begin thinking about how to manage the transition away from the London interbank offer rate (LIBOR, known as the “most important number in finance”).  LIBOR forms the basis for many financing agreements.  LIBOR is scheduled to be phased out by market regulators on December 31, 2021, and many large banks and investment managers have been busy preparing for this fundamental shift.  The Federal Reserve’s Alternative Reference Rate Committee (ARRC) selected the “Secured Overnight Financing Rate” (SOFR) as the successor rate to LIBOR.  SOFR is certainly the leading candidate to replace LIBOR, although there are other alternative rates that are also “competing” to replace LIBOR, such as American Financial Exchange’s “Ameribor” and ICE’s “Bank Yield Index.”  (These non-SOFR rates may be available to borrowers, but this depends in large part on whether an active market in pricing non-SOFR loans develops between now and the end of 2021.)

SOFR is in certain respects fundamentally different from LIBOR.  Thus, the transition will not necessarily be as simple as replacing one interest rate with an equivalent fallback rate.  For instance, one structural difference is that SOFR does not currently have a forward-looking term structure like LIBOR, meaning that it is backward-looking (calculated in arrears).  If a liquid derivatives market based on SOFR develops before the end of 2021, then SOFR may develop a forward-looking term structure – but, until that happens, participants may find this feature to be one of the most significant operational differences between LIBOR and SOFR .  Further, SOFR is a secured overnight rate, whereas LIBOR is an unsecured rate with various tenors.  Fundamentally, this means that LIBOR has an implicit credit component that SOFR does not have – which means that the adoption of SOFR as a replacement rate will need to incorporate a credit spread adjustment that effectively replaces LIBOR’s implied credit component.

From a documentation standpoint, LIBOR transition will require the modification of existing loan agreements that reference LIBOR, in addition to any interest rate swaps that are based on the rate.  This means that projects with debt plus a hedge will need to think about any switch to SOFR as a “package,” with a primary goal of ensuring that the interest rate hedge remains stable and tightly aligned with the terms of the project debt.  If a project sponsor only hedges a portion of the notional value of the project debt – effectively carrying a certain amount of floating rate exposure – then the unhedged portion will be based on SOFR.

To this end, on October 23, 2020, the International Swaps and Derivatives Association (ISDA) published a protocol addressing the upcoming transition, which was one of the final major pieces of the puzzle that the market needed to see in order to begin taking steps to transition the derivatives market away from LIBOR.  On the loan side, the Loan Syndications and Trading Association (LSTA) recently published a concept credit agreement that utilizes SOFR.  We will be publishing additional content on LIBOR’s phase-out in the future. This initial post is intended to flag this upcoming shift in the debt market’s financial plumbing for sponsors that are actively financing (or refinancing) projects.

California CCAs, including San Diego Community Power, Receive Proposed Decision for 2019 RPS Plan

On August 19, the California Public Utilities Commission (CPUC) issued a proposed decision accepting the 2019 Renewables Portfolio Standard Procurement Plans submitted by four new Community Choice Aggregators (CCAs): Butte Choice Energy Authority; Clean Energy Alliance; the City of Santa Barbara; and San Diego Community Power.  Each of these CCAs is anticipated to start providing electricity to customers in 2021.  As we have noted previously, San Diego’s CCA is forecasted to serve a total load of over 6,000 GWhs, making it one of the largest CCAs in California.

While the CPUC accepted, and deemed as final, the RPS Plans for these CCAs, the CPUC cautioned that going forward the CCAs must submit more detailed RPS Plans and improve the quality of their filings.  San Diego Community Power’s RPS Plan deficiencies recognized by the CPUC included (i) a more robust assessment of risk was needed, (ii) clarification of whether San Diego anticipated being able to use its excess renewable resources to meet its Minimum Margin of Procurement (MMoP), (iii) more detailed information on the bid solicitation protocol when procurement activities commence, (iv) how it will address curtailment concerns, and (v) additional description of the organization’s approach to safety.  For instance, the CPUC noted that San Diego Community Power raised concerns about the “impact[] of the COVID-19 pandemic and ramping up with long-term procurement; but [did] not explain what their exact concerns are or what the impacts of supply chain disruption could be for new renewable project development[.]”

The CPUC acknowledged that some of the deficiencies were the result of the CCA’s new status and lack of signing long term contracts for RPS resources.  Nonetheless, the CPUC was clear that it expected more responsive details and correction of the deficiencies in future filings of the following issues:

  • future plans should provide more details on their long-term contracting processes and timeframe, particularly providing a basis for potential delays related to issues raised for COVID-19 pandemic or their ability as a new CCA to meet this requirement;
  • clarifying mixed messages of noting concerns for meeting requirements due to the current pandemic, reopening of direct access market and signaling the need for a long-term contracting on-ramp, while stating that the CCAs will be able to meet the procurement requirements;
  • clarification of (i) whether over-procurement of renewables will be RPS-eligible, (ii) whether they anticipate being able to use their excess RPS resources as their MMoP, and (iii) the process they will use for adjusting their MMoP in the future as the procurement quantity requirement increases, forecasts change, and risks evolve;
  • given the 65 percent long-term contracting requirement commences in 2021, clarification of plans for how they will meet the long-term procurement requirement in Compliance Period 2021-2024.

In addition to the foregoing recommendations, which applied to all four CCAs, the CPUC also had additional recommendations directed specifically to Butte Choice Energy and the City of Santa Barbara CCA.

U.S. District Court Upholds California’s Cap-and-Trade Agreement with Québec

On July 17, 2020, the U.S. District Court for the Eastern District of California rendered its decision in U.S. v. California (Case 2:19-cv-02142-WBS-EFB), upholding the agreement between California and the Canadian Province of Québec that links California and Québec’s respective cap-and-trade programs.  In its opinion, the District Court rejected the federal government’s claim that the California-Québec agreement is preempted under the Foreign Affairs Doctrine.  The District Court ruled earlier this year on the federal government’s other claims, finding that the agreement did not violate either the Treaty or Compact Clauses of the U.S. Constitution.  With the decision on July 17, the California-Québec agreement will remain in place, allowing the two jurisdictions to continue to link their cap-and-trade programs.  The federal government has not yet stated whether it will appeal the District Court’s decision.

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FERC Issues Final Rule Overhauling PURPA Regulations

Yesterday, the Federal Energy Regulatory Commission (FERC) issued Order No. 872 and implemented the largest overhaul to FERC’s regulations affecting Qualifying Facilities (QFs) in more than a decade.  The order itself is 491 pages in length and there remain plenty of details to unpack in its implementation (including future proceedings to come at the FERC and state public utility commission level), but what is clear is that Order No. 872 substantially changes the ground rules for developing QFs.

Order No. 872 includes the following significant changes, among others:

  • One-Mile Rule.  There is no longer an irrebuttable presumption that projects located more than one mile from each other are considered to be at separate sites for purposes of qualification as a QF.  Rather, only projects located 10 miles from each other will benefit from an irrebuttable presumption, while projects that are between one and ten miles from each other will only be afforded a rebuttable presumption.  Furthermore, for purposes of determining whether QFs are located at the “same site,” FERC will consider several new factors including, but not limited to, shared transformers or generation interconnection facilities, common debt and equity financing, and common permitting and access rights.  None of these factors, which fall into the categories of physical characteristics or ownership/other characteristics, is dispositive in determining whether QFs are located at the “same site”; rather, FERC will weigh the evidence on a case-by-case basis.
  • Legally-Enforceable Obligations.  For QFs, establishing a legally-enforceable obligation, or a LEO, represents that point in time when power purchase agreement pricing is locked in.  Order No. 872 introduces new LEO regulations that require QFs to demonstrate commercial viability and a financial commitment to developing the project.  FERC left it for each state to determine how a LEO is formed there, but it suggested that a QF be required to demonstrate that it has completed, or at least undertaken, site control for the project, filed an interconnection application, and applied for the required permitting and zoning.  But ultimately FERC left it to each state agency to determine criteria for establishing a QF’s commercial viability and financial commitment.
  • Challenges to QF Status.  Prior to Order No. 872, a party challenging the QF status of a project was required to seek a declaratory order from FERC, which carries a roughly $30,000 price tag.  As the result of this order, parties challenging a QF’s status, including same site presumptions (which can be done after the filing of an initial QF self-certification or recertifications that make substantive changes) need not pursue a declaratory order and therefore will avoid the associated fee. Substantive changes in the QF recertification include changes in electrical generating equipment that increases power production capacity by the greater of 1 MW or 5% or a change in ownership in which an owner increases its equity interest by at least 10%. Thus, a change in upstream ownership of an existing QF may open up that QF to challenges regarding aggregation with other affiliated same fuel source facilities within 10 miles.
  • Avoided-Cost Rates.  Once again, FERC left it for the states to determine the proper method for determining a utility’s avoided costs.  Yesterday’s order allows state agencies to eliminate fixed avoided-cost energy rates (while still retaining fixed capacity rates) and to have instead the energy rates vary with changes in the utility’s as-available avoided costs as the energy is delivered. And if the state decides to retain fixed energy rates, the fixed energy rate can now be based on project energy prices at the anticipated time of delivery. There is a new rebuttable presumption that as-available energy rates can be based on locational marginal prices, if a utility is located within an organized market, or according to liquid trading hub prices or natural gas indices for those outside of organized markets.  Avoided costs may also be determined through a competitive solicitation (provided that it satisfies certain transparency and non-discriminatory procedures).  Thus, states will now decide if QFs will bear merchant risk in their power sales arrangements.
  • Must-Purchase Opt Out. Lastly, for several years, utilities have been able to opt out of their obligation to purchase from QFs that are larger than 20 MW and located within an organized market.  Yesterday’s order drops that threshold to 5 MW, meaning that utilities located within organized markets may apply to FERC for relief from the obligation to purchase power from QFs larger than 5 MW.

There is no avoiding the fact that Order No. 872 is a game-changer for QFs and utilities alike when it comes to PURPA, and yesterday’s order represents yet another instance where PURPA has become increasingly narrowed by FERC.  There is more to play out with respect to Order No. 872 and we will provide further details as its implementation signals the order’s true scope.

 

D.C. Circuit Affirms FERC Order No. 841, Ensuring Storage Access to Wholesale Markets

On Friday, July 10, 2020, the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) upheld the Federal Energy Regulatory Commission’s (“FERC”) Order Nos. 841 and 841A, which established a framework for electric storage resources’ (“ESRs”) participation in wholesale markets. The D.C. Circuit rejected the petitioners’ arguments that FERC exceeded its jurisdictional boundaries and intruded on regulatory matters left to the states in prohibiting states from barring ESRs located on their distribution and retail systems from participating in federal markets. The D.C. Circuit also held that FERC’s orders were not arbitrary and capricious, and that FERC adequately explained its decision to reject a state opt-out, a feature present in previous FERC programs addressing demand-response participation in wholesale markets.

In holding that FERC’s prohibition on state-imposed bans on local ESR participation in federal markets directly affects wholesale rates, the D.C. Circuit explained: “Keeping the gates open to all types of ESRs – regardless of their interconnection points in the electric energy systems – ensures that technological advances in energy storage are fully realized in the marketplace, and efficient energy storage leads to greater competition, thereby reducing wholesale rates.” The D.C. Circuit concluded that FERC did not unlawfully regulate matters left to the States: “There is little doubt that favorable participation models will lure local ESRs to the federal marketplace, which will require use of States’ distribution systems, but that is the type of permissible effect of direct regulation of federal wholesale sales that the FPA allows. . . . Nothing in Order No. 841 directly regulates those distribution systems.” The court noted that states retain their authority to prohibit local ESRs from participating in both the interstate and intrastate markets simultaneously, retain their authority to impose safety and reliability requirements, and remain unimpeded in their ability to manage utilities and allocate costs incurred in operating and maintaining their systems. Finally, the court concluded that FERC adequately explained its refusal to permit a state opt-out, determining that burdens on the states were outweighed by the benefits of increased participation of ESRs in wholesale markets.

DC Circuit Rejects FERC’s Long-Established Practice of Issuing Tolling Orders

On June 30, the DC Circuit struck down the Federal Energy Regulatory Commission’s (FERC) use of tolling orders to buy additional time in responding to requests for rehearing—a longstanding agency practice that had the effect of materially delaying litigants’ rights to seek judicial review of FERC’s orders.  The opinion was issued in a case that implicated the Natural Gas Act;  however, it is unlikely FERC will be able to avoid having the court’s rationale also impact the agency’s orders issued under the Federal Power Act.

From a procedural perspective, before a party may appeal a decision by  FERC it must first seek rehearing of the subject decision.  A party must request rehearing within 30 days of an order, and “[u]pon such application the Commission shall have power to grant or deny rehearing or to abrogate or modify its order without further hearing.  Unless the Commission acts upon the application for rehearing within thirty days after it is filed, such application may be deemed to have been denied.”  It is that obligation—FERC’s obligation to “act” within 30 days—that was before the court for consideration.

For decades, FERC has used delegated orders issued by its Secretary within the thirty-day time period to toll the time for further action on requests for rehearing. Those tolling orders took no substantive action with regard to a request for rehearing—nor could they, given the Secretary’s limited authority—and as a result they operated merely to delay FERC action on a request for rehearing for an undefined period of time.  And to say FERC does this routinely would be an understatement.  For instance, according to the DC Circuit, every request for rehearing with respect to a pipeline certificate issued since 2017 has been met with a tolling order.  And in that specific context, landowners were left in a legal purgatory where they could not seek an appeal while a pipeline moved forward with eminent domain proceedings.  But no more.

Yesterday’s decision finds that the Natural Gas Act does not allow FERC to issue tolling orders for the sole purpose of preventing rehearing from being deemed denied by its inaction and the statutory rights to judicial review attaching.  Rather, FERC must at least substantively engage with a request for rehearing application within the thirty-day period, or the request is deemed denied and aggrieved parties may seek judicial review.  The opinion represents a significant blow to a decades-old practice at FERC, and ensures that parties will have timely access to judicial review.

FERC Takes Additional Actions to Address Coronavirus Pandemic

On April 2, the Federal Energy Regulatory Commission (“FERC” or the “Commission”) took several additional actions in response to the COVID-19 pandemic.  These actions supplemented FERC’s previous actions on March 19.  In addition to the actions identified below, Chairman Chatterjee highlighted two additional procedural options for obtaining more formal enforcement or compliance-related guidance: standards of conduct waivers and no-action letters.  Two FERC staff task forces were created to expeditiously process standards of conduct waiver requests and no-action letters, and contact information is available for the appropriate staff on FERC’s website: here, here, and here. Continue Reading

FERC Updates Operations During the Coronavirus Pandemic

On March 19, 2020, the Federal Energy Regulatory Commission (FERC or the Commission) announced several updates to their operations in response to the Coronavirus pandemic.  Chairman Chatterjee held a press conference and stated that FERC is fully functioning via the telework process and expects to continue to be able to complete its work considering matters and issuing orders on a timely basis.  Most Commission employees are on telework status until further notice, and FERC’s headquarters are closed to all outside visitors, unless they are cleared for entry by the Office of the Executive Director.  The Commission made the following announcements regarding its response to the pandemic:

  • Technical Conferences: All technical conferences scheduled through May 2020 will be conducted via conference call or WebEx, or postponed.  Schedules will be posted to the FERC.gov calendar.
  • Hearings and ALJ Settlement Conferences: Chief Administrative Law Judge (“ALJ”) Carmen Cintron has postponed one hearing scheduled to start on April 7, 2020 and will make case-specific calls on other hearings as their start dates approach.  ALJ settlement conferences will continue via teleconference.
  • Extension for Non-Statutory Filings Prior to May 1, 2020: The Commission issued a notice extending, until May 1, 2020, deadlines for certain required filings that are due between now and that date. Those filings include non-statutory items required by the Commission such as compliance filings, responses to deficiency letters, and rulemaking comments, as well as forms required by the Commission, except for FERC Form No. 6 (Annual Report of Oil Pipeline Companies).  The extension also will apply to filings required by entities’ tariffs or rate schedules.
  • Other Extensions and Waivers May Be Requested: Entities may seek extensions for other deadlines and may seek waiver of Commission orders, regulations, tariffs, and rate schedules, as appropriate.  The Commission aims to be flexible and responsive during this time and stated that it will be receptive to requests for deadline extensions and other forms of relief.  For example, the Commission granted a request from a regulated entity to waive a tariff requirement for face-to-face meetings.
  • Enforcement Matters: The Commission will exercise its enforcement discretion to take the extenuating circumstances into account as it evaluates compliance and enforcement matters.  The Office of Enforcement is postponing audit visits and investigative testimony and will adjust other deadlines as appropriate.  They will also aim to be flexible and act expeditiously in granting extensions and waivers of compliance filings, forms, and electronic quarterly reports (EQRs), as appropriate.
  • FERC Coronavirus Point of Contact: The Commission appointed Caroline Wozniak as its point of contact for all industry inquiries related to impacts of the Coronavirus on FERC-jurisdictional activities.  Regulated entities can email PandemicLiaison@ferc.gov to receive responses to their questions from Commission staff.
  • Coordination with Other Federal Agencies and NERC: The Commission is working with other federal agencies to proactively identify and address issues affecting energy infrastructure.  FERC and NERC have agreed to coordinate to use their regulatory discretion as appropriate to provide temporary relief from certain compliance requirements while ensuring the reliability of the grid.  NERC is postponing on-site audits, certifications, and other on-site activities through July.

Finally, the Commission emphasized that it is actively exploring other ways to lift burdens on the regulated community and maintains open lines of communication for regulated entities to make inquiries.  Staff and the Office of Enforcement has been directed to work with companies to provide informal guidance and advice that reasonably balances what is happening on the ground with applicable compliance requirements.  The Commission has specifically stated that it “will not be in the business of second guessing the good faith actions that companies take to keep the lights on.”

If you have any questions regarding your compliance obligations or deadlines, please do not hesitate to reach out to your Stoel Rives LLP contacts.

CFTC Proposed Rule Benefits Certain Financially-Settled Offtake Arrangements

On February 20, 2020, the Commodity Futures Trading Commission (CFTC)  unanimously approved a proposed rule that would revise certain reporting requirements for financially-settled offtake contracts that qualify as “swaps” under the Commodity Exchange Act (as amended by the Dodd-Frank Act), such as proxy revenue swaps, fixed-volume price swaps and certain virtual PPAs.  Many counterparties to these kinds of agreements — such as project companies that sell renewable energy – are considered “end-users” under Dodd-Frank, and, in certain cases, bear a transaction reporting burden under parts 43 and 45 of CFTC regulations.

For example, under the proposal end-users would have an additional day to comply with certain reporting obligations under §45.3 of CFTC regulations , such that the transaction would need to be reported on or before the second business day after the date of execution, instead of within 24 hours from execution as provided under the current rule.  In his statement, CFTC Chairman Heath Tarbert recognized that that “[e]nd users often lack the reporting infrastructure of big banks, and may be unable to report data as quickly as swap dealers and financial institutions.”   The proposed rule also explained that “[t]his extended deadline reflects the [CFTC’s] interest in relieving some of the swap data reporting burdens previously imposed on end users in a way that should also help improve data quality.”   These acknowledgments are a welcome shift for end-users, which do not necessarily have the same level of operational resources devoted to swap data reporting as swap dealers or other financial entities.

If you have any questions regarding how the CFTC’s swap reporting regulations apply to cash-settled offtake contracts, please do not hesitate to reach out to your Stoel Rives LLP contacts.

Minnesota Court of Appeals Determines MEPA Review Required for Wisconsin Natural Gas Generating Facility

On December 23, 2019, the Minnesota Court of Appeals reversed and remanded a decision by the Minnesota Public Utilities Commission (the “Commission”) approving affiliated-interest agreements permitting Minnesota Power and its Wisconsin affiliate to move forward with the construction of a large natural gas facility – the Nemadji Trail Energy Center (“NTEC”) – in Superior, Wisconsin (the “Order”). The result of the Order may complicate the already complex issue of state permitting, specifically a state’s ability to regulate activity occurring in another state.

Honor the Earth and certain Clean Energy Organizations sought additional review of the Commission’s order based on concern about the lack of a Commission-ordered environmental assessment worksheet (“EAW”) pursuant to the Minnesota Environmental Policy Act (“MEPA”). During the initial Commission proceeding, Minnesota Power, and indeed the Commission, determined that an EAW was not necessary because (1) MEPA does not apply to the affiliated-interest agreements because NTEC does not meet the definition of “project” under MEPA, and (2) the Commission does not have authority to order an EAW for a project located in Wisconsin. In its Order, the Court of Appeals addresses each point, in turn.

The Order holds that MEPA applies to affiliated-interest agreements. Contrary to the Commission’s interpretation, the Court of Appeals concludes that the NTEC affiliated-interest agreements are “projects” as defined by MEPA. The Court’s definition of “project” is “a definite, site-specific, action that contemplates on-the-ground environmental changes.” The Order notes that the construction and operation of NTEC are definite and site-specific actions that will affect the immediate location as well as the surrounding environment (including Minnesota – 2.5 miles away – and Lake Superior). The Court went on to note that because the construction of NTEC is an environmentally significant event that may not occur without Commission approval of the affiliated-interest agreements, Commission approval of such agreements constitutes indirect governmental action manipulating the environment and triggering MEPA. Therefore, the Court concluded that MEPA “applies to the governmental action of approving the NTEC affiliated-interest agreements.”

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