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

BOEM Launches Process for Offshore Wind Leasing in Oregon

Today, Bureau of Ocean Energy Management (BOEM) Director Amanda Lefton announced a Call for Information and Nominations (Call) to assess commercial interest in potential offshore wind leasing within two areas off the Oregon coast.  Together, the two areas total 1,158,400 million acres located at least 12 miles offshore Coos Bay and Brookings, respectively.  Once the Call is published in the Federal Register (anticipated for April 29, 2022), the public will have 60 days to submit comments.  More information on the Call and BOEM’s activities in Oregon can be found here.

Interestingly, the Call did not include the approximately 237,000 acre proposed call area off the coast of Bandon that was included in BOEM’s February 25 presentation to the Oregon Intergovernmental Renewable Energy Task Force and noted in our last blog on the topic.  Nevertheless, this is a first for Oregon and an exciting development for the floating offshore wind industry.  BOEM’s action today will hopefully spur the Oregon legislature to expedite action on its goal to “plan for the development” of up to 3 GW of floating offshore wind by 2030 that was set forth in H.B. 3375 last year.  In order for projects to pencil, they will not only need a lease from BOEM, but a plan for selling the power; and the legislature can help with that.

BOEM Announces Offshore Wind Call Areas in Oregon and Historic Lease Sale in the New York Bight

On Friday February 25, the Biden administration continued its push to achieve 30 GW of offshore wind by 2030 when the Bureau of Ocean Energy Management (BOEM) announced three Call Areas for the development of floating offshore wind in federal waters off the Oregon coast.  The Call Areas, located 13.8 miles off the coast of central and southern Oregon near Coos Bay, Bandon and Brookings are the agency’s first step in determining competitive interest for leases. The announcement came just ahead of the 10th BOEM Oregon Intergovernmental Renewable Energy Task Force meeting, and on the same day that BOEM announced the results of the historic $4.37 billion competitive lease sale in the New York Bight.

The Call Areas on the Oregon coast total 2,181 square miles at depths of up to 1,300 meters.  Those areas will be whittled down into smaller Wind Energy Areas (WEAs) by the end of 2022 according to BOEM, but only after BOEM considers public comments on the areas themselves, ocean uses, and stakeholder concerns. Whether BOEM is required undertake a full environmental analysis of the WEAs it ultimately identifies prior to issuing leases, however, is a question our colleague Cherise Gaffney raised in a separate article for Utility Dive last year.

Assuming things move forward as planned, BOEM’s near-term target matches the state’s 2021 goal in H.B. 3375 to “plan for the development” of up to 3 GW of floating offshore wind projects in federal waters by 2030.  BOEM expects to offer up to 3 GW in leases by the first quarter of 2024, taking advantage of the estimated 2.6 GW the National Renewable Energy Lab estimates could be installed without major upgrades to the trans-coastal transmission system in Oregon. However, it is worth noting that the three Call Areas are adjacent to only two of the five existing substations identified  by NREL as potential points of interconnection.


California Makes Progress Towards Ensuring Electric Reliability for Summer 2022

On January 11, 2022, the California Energy Commission (CEC) issued an update to its Summer 2022 Stack Analysis.  Previously, on September 8, 2021, the CEC issued a revised Summer 2022 Stack Analysis that showed potential energy shortfalls ranging from 200 MW to 4,350 MW during the months of July through September 2022, in the evening hours.  The early evening hours have become one of the most challenging period for California reliability.  Abundant solar is available to meet daytime peak load, but as that solar rolls off the system in the evening, alternate resources are needed to meet the evening demand.

To update the Stack Analysis, the CEC updated information about new resources, including procurements ordered by the California Public Utilities Commission.  The CEC also updated demand forecasts.  A substantial increase in available resources, including 1,230 megawatts of energy storage, has improved the outlook for summer 2022.  Using a 22.5 percent procurement reserve margin to address impacts to demand from climate change and potential extreme weather events, the updated Stack Analysis finds that there continues to be a risk for energy shortfalls during September 2022, ranging from 200 to 2,400 MW.

Oregon Department of Energy Seeks Stakeholder Input on Floating Offshore Wind Development

The Oregon Department of Energy (ODOE) is kicking off the stakeholder engagement part of its Floating Offshore Wind Study on January 20 at 9 a.m. As directed by HB 3375, ODOE is preparing a report on the challenges and benefits of integrating up to 3 gigawatts (GW) of floating offshore energy into Oregon’s grid by 2030, and it will submit that report to the legislature in September. A summary from the first part of the study, a literature review, should be released soon. Following the kickoff meeting, ODOE anticipates two more virtual meetings, as well as an opportunity to submit comments. Continue Reading

California ISO Issues Straw Proposal in Interconnection Process Enhancements Stakeholder Proceeding

On December 6, 2021, the California ISO issued an issue paper and straw proposal (“Straw Proposal”) for its Interconnection Process Enhancements stakeholder proceeding. The California ISO initiated this stakeholder proceeding on September 30, 2021 with the issuance of a preliminary issue paper. The stakeholder process comes at a time when an unprecedented level of energy procurement in California has caused dramatic increases in the number of projects in the California ISO’s interconnection queue. The California ISO’s most recent cluster, cluster 14, saw a record number of 373 interconnection requests being submitted, representing 150,000 megawatts of generating capacity, compared to 155 requests submitted in 2020. Ultimately, the volume of interconnection requests forced the California ISO to seek authority from the Federal Energy Regulatory Commission to extend its interconnection process by approximately one year.

The Interconnection Process Enhancements initiative will have two phases. Phase 1 will focus on near-term enhancements for cluster 14 and before the summer of 2022. The proposals in Phase 1 are scheduled be submitted to the California ISO Board of Governors in May 2022. Phase 2 will focus on longer term modifications and broader reforms to align interconnection processes with procurement activities. Those proposals are scheduled to be submitted to the Board in November 2022. Continue Reading

Reactive Power Compensation for Renewable Generators – On the Chopping Block?

On November 18, 2021, FERC issued a Notice of Inquiry (NOI) seeking comments on reactive power capability compensation and market design.  (Link to NOI here). Reactive power is a critical component of the bulk electric system. Almost all bulk electric power is generated, transported, and consumed in AC networks. These AC systems consume both real and reactive power. Reactive power supports the voltages necessary for system reliability to allow the supply of real power from generation to load. All balancing authorities must procure enough sources of reactive power to safely manage the grid and generator interconnection agreements contain provisions requiring generators to operate within certain reactive power limits. Reactive power is an ancillary service and costs are recovered separately from the cost of standard transmission service. Continue Reading