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.

Background

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.

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