D.C. Circuit Affirms FERC’s Broadview Order Confirming that Qualifying Facilities May Install Greater than 80 MW of Nameplate Generating Capacity

Yesterday, February 14, 2023, the D.C. Circuit issued an order affirming FERC’s order in Broadview Solar, LLC, 174 FERC 61,199 (2021) and its “send-out” approach to determining the net power production capacity of a Qualifying Facility (“QF”).  As a brief recap of the history of Broadview, Broadview filed an application for QF certification of a 160 MW solar and 50 MW battery storage system in September 2019.  The facility’s inverters limited its instantaneous export capability to 80 MW.  In a September 2020 order, the Commission denied the application, concluding that Broadview’s 160 MW of solar nameplate capacity exceed the 80 MW limit for QF status, reversing decades of prior precedent that relied upon a facility’s “send-out” capacity to determine its power production capacity.  Then, in March 2021 and under the leadership of a new Chairman, the Commission reversed course and determined that while the statute was ambiguous as to the proper measure of a facility’s “power production capacity,” the “send-out” approach was the best interpretation because it considered all of the facility’s component parts working together. Therefore, Broadview did meet the requirements to be a QF after all, because its inverters capped its instantaneous send-out capacity to 80 MW.  The Commission reaffirmed that order in June 2021, rejecting arguments that the battery and solar facilities should be considered separately.  The Commission’s orders were appealed to the D.C. Circuit.

In its order yesterday, the D.C. Circuit agreed with the Commission that the statute was ambiguous and determined that the Commission’s interpretation was reasonable.  The D.C. Circuit specifically noted that the inverters are an integral component in producing power, that the only grid-usable power is AC power, that the mandatory purchase obligation under PURPA only applies to grid-usable, or AC power, and that the Commission’s focus on net output was consistent with the statutory purpose of encouraging the development of renewable resources. The D.C. Circuit explained that the use of the battery to release power at optimal times was a feature allowing the facility to more-consistently produce and send out the maximum amount of renewable energy permitted under the statute. 

In response to arguments raised by the appellants regarding Broadview’s inconsistent reporting in Form 556, the D.C. Circuit noted that it was reasonable for the Commission to treat Form 556 as a tool meant to aid the Commission in determining a project’s eligibility for QF status and not itself “determinative” or “dispositive.”

In response to arguments that the Commission should have treated the facility and battery separately, the D.C. Circuit pointed to FERC’s requirement to consider the combined power production capacity of facilities at the same site and the fact that the DC power stored in a battery is not usable to the grid to affirm that FERC was reasonable in determining that the battery is not a separate “facility.”

Altogether, the D.C. Circuit’s order should provide renewable energy developers with more comfort and flexibility in designing QFs that are inverter-limited to 80 MW or less but include batteries or more than 80 MW of DC generating capacity.

Commission Issues Long-Awaited Proposed Decision in Transportation Electrification (TE) Proceeding, Setting a Framework for California TE Policy and Investment

On October 14, 2022, the assigned Commissioner (Rechtschaffen) issued a proposed decision (PD) on Transportation Electrification Policy and Investment in the pending rulemaking (R.) 18-12-006 before the California Public Utilities Commission (Commission).  Commission approval of the PD would adopt a new Transportation Electrification Framework (TEF) to guide utility investments in electric vehicle (EV) charging infrastructure and would authorize $1 billion in ratepayer funding for the first five years of the TE program, known as Funding Cycle 1 (FC1).  In recognition of the rapidly evolving EV landscape, the PD proposes to cap spending during first three years of FC1, which is a five-year funding cycle, at $600 million, and access to the remaining $400 million budget is held until the Commission issues a “Mid-Cycle Assessment” decision to determine whether modifications to or termination of the program budget is warranted.  Notably, the Commission would prohibit Fortune 1000 companies from receiving any FC1 rebates, regardless of whether they propose to operate in a disadvantaged community. 

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U.S. Fish and Wildlife Proposes Revisions to Eagle Permit Rules, Including General Permits for Qualifying Wind Energy Projects, Power Lines, and Disturbance and Nest Take

On September 30, 2022 the U.S. Fish and Wildlife Service (“Service”) published notice in the Federal Register of a proposed rule amending its regulations authorizing permits for eagle incidental take and eagle nest take. Although the proposed rule includes other proposed revisions, the most notable change is the Service’s proposal to create general permits for certain projects and activities. Under these general permits, applicants would register with the Service, pay the required fees, and certify compliance with general permit conditions. By making general permits available to certain activities and projects, the Service aims to remove administrative barriers, reduce costs, and make the process less confusing for applicants. For projects or activities that do not qualify for a general permit, individual or specific permits will remain available.

In the proposed rule, the Service proposes general permits for four types of qualifying projects or activities: wind energy generation projects, power line infrastructure, disturbance of breeding bald eagles, and bald eagle nest take. We discuss each proposed general permit in turn below.

Eagle Incidental Take Permit for Qualifying Wind Energy Projects. To encourage broader participation in the eagle permitting program by wind energy developers and operators, the Service is proposing a five-year general permit for certain qualifying wind energy projects. Eligibility is determined based on the relative eagle abundance in the project area. To be eligible, all turbines associated with the project must be located in an area with seasonal relative eagle abundance (based on eBird data) below the threshold amounts across five eagle “seasons.” The project must also be greater than 660 feet from a bald eagle nest and two miles from a golden nest to qualify under the general permit.

For existing wind energy projects, the proposed rules would allow project operators to request coverage under the wind energy general permit even when a portion of the project is within an area that does not fall below the applicable relative abundance thresholds. The Service anticipates “issuing a letter of authorization for most existing projects where only a small percentage of existing turbines do not qualify under the relative abundance thresholds or when an existing project has conducted and provides monitoring data demonstrating fatality rates consistent with those expected for general turbines.”

The proposed wind energy general permit requires permittees to monitor eagle take but allows project proponents to use onsite employees rather than relying on third-party monitors. If a project is covered by a general permit and has four eagle fatalities during the permit term, the project will be required to implement adaptive management measures and seek an individual permit at the expiration of the general permit.

The proposed application fee for the wind energy general permit is $500, and the proposed administrative fee is $525 per turbine per year or $2,625 per turbine for a five-year permit. Under the current proposal, wind energy general permits would be valid for five years.

Eagle Incidental Take Permit for Power Lines. The Service is also proposing a general permit option for power line infrastructure. To qualify for coverage under the power line general permit, the applicant must, in addition to meeting other general requirements: (1) ensure that new construction is electrocution-safe for bald and golden eagles; (2) implement a reactive retrofit strategy following all eagle electrocutions; (3) implement a proactive retrofit strategy to retrofit a portion of existing infrastructure during each general permit term; (4) implement an eagle collision response strategy; (5) incorporate information on eagles into project siting and design; and (6) implement an eagle shooting response strategy (aimed at addressing illegal shooting of eagles on power lines). The proposed application fee for the power line general permit is $500 and the proposed administration fee is $5,000 for each state for which the power-line entity is seeking authorization. Like the wind energy general permits, under the current proposal, power line general permits would be valid for five years. Continue Reading

Effective Immediately, California Energy Commission Jurisdiction Expands to Include Non-Thermal Projects Greater Than 50 MW

On June 30, 2022, California Governor Gavin Newsom signed Assembly Bill 205 (“AB 205”), which, among various other things, expands the siting jurisdiction of the California Energy Commission (“CEC”) to include non-thermal generating facilities, such as solar and wind projects, with a capacity of 50 megawatts (MW) or more.  The CEC’s siting jurisdiction was previously limited to thermal generating facilities like gas-fired and geothermal power plants with a capacity of 50 MW or more.  In addition, AB 205 allows the CEC to have siting jurisdiction over energy storage facilities with a capacity of 200 MW hours or more.

Below is a list of CEC siting-related changes set forth in AB 205:

  • The bill requires the CEC to “establish and implement the Long-Duration Energy Storage Program to provide financial incentives for projects that have power ratings of at least one megawatt and are capable of reaching a target of at least 8 hours of continuous discharge of electricity in order to deploy innovative energy storage systems to the electrical grid for purposes of providing critical capacity and grid services.”
  • The bill establishes a CEC siting certification process for solar photovoltaic (PV) and onshore wind facilities with a generating capacity of 50 MW or more and energy storage systems capable of storing 200 MW hours or more of electricity. The certification process would include transmission lines from those generating or storage facilities to the first point of interconnection.
  • This expanded CEC certification process also covers facilities manufacturing, producing, or assembling energy storage, wind, or solar PV systems or their components, or other specialized products, components, or systems that are integral to renewable energy or energy storage technologies, as long as there is a capital investment associated with the facility of at least $250 million over a period of five years.
  • The bill allows a person proposing to construct any of those facilities to file an application for certification (“AFC”) with the CEC on or before June 30, 2029.
    • The CEC is required to review the AFC and determine whether to issue the certification “no later than 270 days after the application is deemed complete, or as soon as practicable thereafter.”
    • The CEC must forward the AFC to the local government with land use jurisdiction over the proposed facility and site and requires local agencies to review and submit comments on the application.
    • The CEC would be the designated lead agency for purposes of CEQA analysis of the certification decision. Local governments could seek fees related to their review of and input on the AFC.

Upon receipt of an AFC that the CEC determines meets the criteria laid out in AB 205, the CEC would have the exclusive power to certify a site and related facility and the associated environmental impact report, whether the application proposes a new site and related facility or a change or addition to an existing facility.  AB 205 contains detailed information on the requirements that a project must meet to fall within the CEC’s jurisdiction.

Note that AB 205 does not modify the California Public Utilities Commission’s (“CPUC”) jurisdiction, including the issuance of a certificate of public convenience and necessity for a facility that is proposed by a utility regulated by the CPUC.  The bill also does not supersede the authority of the State Lands Commission to require leases and receive lease revenues, if applicable, or the authority of the California Coastal Commission, the San Francisco Bay Conservation and Development Commission, the State Water Resources Control Board, or regional water quality control boards.

Please see the text of AB 205 for more detailed information.  According to AB 205, the bill takes effect immediately.

Stoel Rives attorneys have extensive experience with the CEC’s AFC process.  If you have any questions about AB 205 and changes to the CEC’s jurisdiction, or the CEC’s AFC process, please contact Melissa Foster, Allison Smith, or Seth Hilton.

FERC Proposes Broad Reforms to Interconnection Process

At its June 16, 2022, open meeting, the Federal Energy Regulatory Commission (FERC or Commission) issued a notice of proposed rulemaking (NOPR), Improvements to Generator Interconnection Procedures and Agreements, 179 FERC ¶ 61,194 (2022), proposing reforms to the Commission’s standard generator interconnection procedures and agreements.  The goal of the NOPR is to reduce queue backlogs and expedite the process for connecting new electric generation facilities to the transmission grid, and to do that the Commission has proposed altering its 20-year-old approach to processing interconnection requests to align with “first-ready, first-served” methods used in the organized markets around the country.

At the end of 2021, more than 1,400 gigawatts of generation and storage were waiting in interconnection queues throughout the country.  This backlog in the interconnection queue has created uncertainty regarding the costs and timing of interconnecting projects, many of which will be needed to maintain reliability in the wake of generation retirements across the country.  The NOPR seeks to address these issues through (1) implementing a first-ready, first-served cluster study process, (2) increasing the speed of interconnection processing, and (3) incorporating technological advancements into the interconnection process.  We’ve summarized several highlights of the NOPR here; however, there is a lot to digest in its 258 pages of proposals.  As is standard with any proposed rulemaking, the Commission has requested comments on specific topics.  Comments are due 100 days after publication of the NOPR in the Federal Register.  Reply comments are due 130 days after publication in the Federal Register.

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California Releases Its Draft Deployment Plan for Federal Funding Under the National Electric Vehicle Infrastructure (NEVI) Program

The California Energy Commission (CEC) hosted a workshop on Tuesday, June 14 to discuss its recently issued (June 10) proposal to deploy federal electric vehicle (EV) infrastructure funding under the NEVI Program authorized by President Biden’s federal infrastructure bill signed into law late last year.[1]

The CEC held the workshop in conjunction with the California Department of Transportation (Caltrans), which is jointly charged with implementing the state’s NEVI funding. After taking public comment on the draft plan (comments are due by June 28),[2] California will submit its final plan for approval with the Joint Office of Energy and Transportation (Joint Office) on August 1. Federal funding will be released to each state upon approval of the final deployment plans, which is expected by September 30, 2022. The CEC expects to develop the grant funding details later this summer/fall and to release the grant funding opportunity in the winter of 2022. This plan anticipates the first chargers under NEVI project funding should be operational in Q2 of 2025, with full buildout completed by 2030.

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Updated FERC Guidance on Qualifying Facility Certifications

FERC issued two notable orders this spring in Irradiant Partners, LP (Docket No. EL22-8-000) and Dalreed Solar (Docket No. QF20-1037-002) that provide further guidance on qualifying facility (QF) certifications.  Here are the key takeaways:

  • QF Re-Certifications Should Be Filed Before or At the Time of a Material Change: FERC’s regulations do not contain specific guidance on when QF re-certifications need to be filed, but FERC Staff’s informal guidance has previously been that they should be filed within 30 days of a change.  In its March 24, 2022, order in Irradiant Partners, LP, the Commission explained that the qualifying status of a facility “may no longer be relied upon” once the QF fails to conform with any material facts or representations.  The Commission noted that the re-certification can be filed in advance if the material change and date of the change can be reasonably anticipated.  Based on FERC’s guidance, QFs should be making re-certification filings prior to or immediately after a material change and be aware that prior certifications cannot be relied upon once they are inaccurate.
  • Each QF Re-Certification Must Be Made Individually: The Commission’s order in Irradiant Partners, LP stemmed from a request for a waiver of the requirement to file a recertification for each of the 185 QFs in a portfolio in which Irradiant had acquired a greater than 10% interest. The Commission rejected the waiver request, emphasizing that the “filing requirement is a substantive and important criterion for QF status” that “must be followed.”  This is consistent with the informal guidance we have received from FERC Staff in the past.  The Commission explained that “it considers a change in ownership in which an owner increases its equity interest by at least 10% from the equity interest previously reported to be a material change [necessitating a re-certification], as would be the addition of an owner not previously reported that holds an equity interest of 10% or more.”
  • QF Status Is Not Grandfathered Under Pre-Order No. 872 Rules Where a Facility Makes a Substantive Change: In an order issued May 13, 2022, in Dalreed Solar LLC, the Commission confirmed that when a facility re-certifies and makes a substantive change from its existing certification, such as a change in its net power production capacity, it is subject to the new rules established in Order No. 872 (including the rebuttable presumption that affiliated, same-energy resource facilities greater than one mile apart but within ten miles of each other are separate sites). This is consistent with the guidance the Commission provided in Order No. 872.  The Commission’s order in Dalreed Solar appears to be the first time the Commission has applied the 10-mile aggregation factors to revoke a facility’s QF status.  In its order determining that the facilities should be considered the same site, the Commission specifically noted that the facilities at issue had the same owner, same operator, shared a common off-taking utility, shared a common interconnection request, shared common interconnection facilities (including shared busses, step-up transformers, and relays), planned to share a common interconnection point, were located on land owned by the same landowner, and had or were in negotiations with the same offtaker for PPAs.  The Commission declined to consider the history of the project’s interconnection negotiations that the developer alleged led to some of the common attributes.
  • QF Status Is Dependent Upon the Facts at the Time of Filing: Dalreed Solar also argued that the Commission should consider in the 10-mile analysis that the upstream owner would likely change prior to commercial operation, and that aggregation should not occur until then. In response, the Commission declined to consider the possibility of such future changes and stated that “[u]pon submitting Form No. 556, a small power production facility at that time either meets the requirements to qualify as a QF under PURPA and the Commission’s regulations or it does not.” As a result, QF certifications should be submitted with current information and developers should expect that their QF facilities will be subject to aggregation rules as of the date of certification (or re-certification, in this case), even prior to energization or commercial operation.
  • QF Aggregation Is Not Forever: The Commission in Dalreed Solar noted that if the circumstances underlying the Commission’s findings change such that Dalreed is no longer affiliated with the other affiliated solar QFs within 10 miles, the facility could seek to re-file for QF status.

The California Public Utilities Commission Issues Proposed Decision on New Resource Adequacy Framework

On May 20, 2022, the California Public Utilities Commission (CPUC or Commission) issued a proposed decision (PD) that would, among other things, adopt Southern California Edison’s (SCE) 24-hour-slice proposal as the new resource adequacy (RA) framework applicable to load-serving entities (LSEs) under the CPUC’s jurisdiction.  Generally, the proposal would require each LSE to show that it has enough capacity to meet its specific gross-load profile, including a planning-reserve margin, or PRM, for all 24 hours for the “worst day” of each month.  The “worst day” would be defined as the day of the month that has the highest coincident-peak-load forecast.  This new RA framework would likely be implemented in 2025, with 2024 serving as a “test year” for the new framework.

The Commission initially began examining potential changes to its RA framework due to significant and ongoing changes in California’s generation-resource mix, with the increasing reliance on variable resources such as solar and wind, and use-limited resources, such as energy storage and demand response, as well as the retirement of older natural gas generation.  The Commission solicited proposals for a new RA framework starting in 2020, and in 2021 it tentatively adopted Pacific Gas and Electric’s (PG&E) slice-of-day proposal in decision 21-07-014.  The Commission ordered a series of workshops to further develop the proposal, culminating in a workshop report submitted March 1, 2022.  During the workshops, two alternate proposals were developed:  SCE’s 24-hour-slice proposal, and a two-slice proposal developed by Gridwell Consulting.  The parties generally favored one of the two alternate proposals, rather than the PG&E slice-of-day proposal.  The selection of SCE’s 24-hour-slice proposal will set the direction for further development of the new RA framework. Continue Reading

California Energy Commission Discusses Draft Report on Offshore Wind

On May 18, 2022, the California Energy Commission met to discuss its draft report to evaluate and quantify the maximum feasible capacity of offshore wind to achieve reliability, ratepayer, employment, and decarbonization benefits and establish megawatt offshore wind planning goals for 2030 and 2045. The report is the first of three interim work products that California AB 525 directs CEC to prepare. By the end of this year, the CEC must complete and submit a preliminary assessment of economic benefits as they relate to seaport investments and workforce development needs, and complete and submit a permitting roadmap. The ultimate requirement of AB 525 is to require, by June 30, 2023, the CEC, in coordination with federal, state, and local agencies and a wide variety of stakeholders, to develop a strategic plan for offshore wind energy developments installed off the California coast in federal waters and submit it to the California Natural Resources Agency and the Legislature. Continue Reading

Commission Ruling Reopens the NEM 3.0 Record to Invite Comment on and Consider Limited Issues

In its first move since hitting “pause” on the California Public Utilities Commission’s (Commission) consideration of a controversial December 2021 proposed decision (Proposed Decision or PD) that would have overhauled the existing net energy metering (NEM) tariff for California’s solar customers, the presiding administrative law judge (ALJ) issued a ruling on May 9 to reopen the record and invite party comments on a limited scope of issues.


The Commission adopted California’s existing solar tariff, known as NEM 2.0, on January 28, 2016 in Decision (D.) 16-01-044.  Customers opting into this tariff pay a one-time interconnection fee (less than $150 for systems under 1 MW and $800 for systems over 1 MW).  Customers taking service on the NEM tariff are automatically opted into a time-of-use rate plan and are subject to select non-bypassable charges (NBCs) that are used to fund general customer programs such as contributions to the wildfire fund, nuclear decommissioning, and the public purpose program, among others. NEM customers receive a bill credit for any excess generation produced by their system and exported to the electric grid, which credits may be used to offset customer energy costs. Under NEM 2.0, any excess generation credits are applied to the customer’s bill at the same retail rate (including generation, distribution and transmission charges) the customer would have paid for the energy consumption. Continue Reading