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August 1, 2024

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NERC Confident in Ability to Deliver ITCS On Time

At NERC’s quarterly technical session last week in Ottawa, the ERO’s staff said they’re confident they can finish the congressionally mandated Interregional Transfer Capability Study (ITCS) despite the relatively tight time frame given by lawmakers.

NERC added the technical sessions to the schedule of events for its Board of Trustees and Member Representatives Committee meetings to host more in-depth discussions on topics of interest to the ERO. Last week’s session featured an extended discussion of the ITCS, which has caused considerable discussion among NERC and other stakeholders because of its effect on the ERO’s work plan and budget for 2023 and 2024. (See FERC Approves NERC Transfer Study Funding Request.)

Speakers at the technical session emphasized the importance of the study, which Congress mandated when it passed the Fiscal Responsibility Act in June and which must be submitted to FERC by December 2024. Mark Lauby, NERC’s senior vice president and chief engineer, called the work necessary preparation for the rapidly changing electric grid.

“It’s really a critical time to be looking at transfer capability, because as our system is now [evolving] to one that is much more energy-constrained and not capacity-driven, it’s very important for us to understand where the energy is and where it isn’t, and make sure we have an ability to get from where it is to areas that are [in] deficit,” Lauby said.

John Moura, NERC’s director of reliability assessment and performance analysis, said that while “another study … might not answer every single question that we have,” the ERO sees the ITCS “as an essential component to the energy transformation story arc” that the grid is undergoing. Moura said he saw “no better set of organizations suited to do this” than NERC and the regional entities, which represent an “independent and objective voice.”

A visualization of NERC’s conception of the study. | NERC

Study Comprises Three Tasks

Moura illustrated NERC staff’s approach to the study, and its three components mandated by Congress, with a simplified visualization presenting two systems: one with 200 MW of load and 120 MW of generation — representing a deficiency of 80 MW — and the other with 200 MW of load and 260 MW of generation, a 60-MW surplus.

Task 1, Moura explained, is to calculate the transfer capability between the two systems — in this theoretical case, one system can transfer 40 MW to the other over existing lines and the other can transfer 50 MW, which “isn’t sufficient in meeting what the [system] on the left’s load requirement is.” Therefore, the second task is to determine where deficiencies exist, and how much additional transfer capability would resolve the issues. Under the example presented, adding 30 MW of capability should address the deficiency.

The third task, which Moura called the most important, is to “evaluate what is needed to meet and maintain these transfer limits.” This means, for example, addressing the ability of the system on the right to deliver the 80 MW needed by the system on the left, when it only has a surplus of 60 MW.

“Generation is just as important to transfer capability as transmission,” Moura said. “It’s not all about stringing the wires; we’re going to need generation to support the transfer capability, so we’ll need to identify those needs as well.”

Industry Help Needed

While Congress’ mandate puts NERC “at the helm,” Moura said engagement across industry also will be required. So, the ERO will form the ITCS Advisory Group “in the coming weeks” to provide advice and input on the study scope, approach, results and recommendations. Moura called this group “the tip of the spear for stakeholder coordination,” and said it will review the final report and the recommendations, though the ERO Executive Leadership Group will be in overall control of the study.

Until recently the project was in what NERC staff called “Phase 0” — focused on defining the scope and assumptions, stakeholder engagement and preparing data requests — while awaiting FERC’s approval for its payment strategy, which required redirecting funds budgeted for 2023 and drawing from NERC’s financial reserves. The commission gave its assent on Aug. 10, and the study entered Phase 1, which consists of identifying generation deficient and surplus areas, performing transfer capability analysis and identifying thermal, voltage and stability limits.

NERC expects to prepare a draft of the final report by August 2024, with comments to be solicited from stakeholders over the following three months. While the final report will be submitted at the end of the year, the ERO expects to remain active providing support to FERC as it reviews the study, and in conducting further research and support as needed.

“This is not just to submit to FERC and do nothing. We’d like this to really mean something and for it to be a launchpad for policy and other developments that will occur,” Moura said. “There are benefits beyond the ITCS — substantial benefits — in gaining the expertise and capability to perform these studies.”

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BOEM Approves Revolution Wind off New England Coast

Revolution Wind on Tuesday became the fourth utility-scale U.S. offshore wind project to gain federal approval.

At full capacity, the facility south of the Rhode Island and Massachusetts coast will send 704 MW of power to Connecticut and Rhode Island.

Fabrication of components began this year. Developer Ørsted said in a news release Tuesday that the project remains on track for onshore construction activities to begin in coming weeks and for offshore construction to begin in earnest in 2024. It is targeting a 2025 operational date.

The record of decision issued Tuesday by the Bureau of Ocean Energy Management signals BOEM’s approval of the construction and operations plan.

The decision is being presented by the Department of Interior and the Biden administration as the green light for the project, but BOEM still must issue final approval of the plan. Additional state and federal authorizations are needed as well.

Ørsted said it anticipates receiving BOEM’s approval in November.

Tuesday’s announcement came just shy of 10 years after BOEM executed wind energy lease OCS-A 0486 with an entity called Deepwater Wind New England LLC.

It was later divided into two areas: South Fork Wind and Revolution Wind.

Among the cluster of wind energy areas being developed off the eastern tip of Long Island and the southeastern corner of New England, Revolution Wind will be one of the closest projects to land.

The plan approved by BOEM is a modified version that reduces the number of turbines erected in an attempt to reduce its visual profile and limit the impact on people and industries that use the ocean, such as fishers.

Revolution Wind has committed to compensate recreational and commercial fisheries for losses directly arising from the project.

Details

Revolution Wind is a joint venture of industry leader Ørsted and New England utility Eversource, which is looking to exit the partnership and exit offshore wind development all together.

In a news release Tuesday, the pair touted the economic impact Revolution Wind already has had, even before gaining approval, including: investment of $100 million to help redevelop the State Pier in New London, Conn.; creation of a regional offshore wind component fabrication facility in ProvPort, R.I.; commissioning five vessels at local shipyards; and contributions to multiple career-development programs.

BOEM’s parent agency, the Department of the Interior, said construction of Revolution Wind is expected to create about 1,200 local jobs.

Some of the new shoreline infrastructure already is in use as Ørsted and Eversource build the 132 MW South Fork Wind, which is expected to begin commercial operations before the end of this year.

South Fork gained a critical advantage by being in the forefront of U.S. offshore wind development.

Other projects that are not as far along in the yearslong planning-review-permitting process have been clobbered by soaring material costs and interest rates in the past two years.

Ørsted and Eversource have told New York state they need more money to proceed with Sunrise Wind 1, for example.

New York, in turn, invited them to rebid Sunrise 2 into the most recent solicitation at a lower cost, before the state makes final contract decisions.

The two partners also saw their 884 MW Revolution Wind 2 proposal rejected as too expensive in Rhode Island.

And Ørsted sought and received more money from New Jersey for Ocean Wind 1, a project it is pursuing solo. It became the third offshore wind plan greenlighted by BOEM, last month.

Other developers are citing the same problems with their projects along the Northeast coast, suggesting the first major buildout of offshore wind in the Americas will be slower and/or more expensive for ratepayers than initially projected.

Commentary

Tuesday’s decision was hailed as a milestone and landmark.

Offshore wind has been a priority for President Biden, who has set a goal of 30 GW by 2030. BOEM said in a news release that Tuesday’s approval of Revolution Wind puts the agency on track to complete review of 16 projects with more than 27 GW of nameplate capacity by 2025.

“Today’s approval is not the end of our work on this project. We will continue to maintain open communication and frequent collaboration with federal partners, tribal nations, states, industry and ocean users to address potential challenges to and identify opportunities for the continued success of the U.S. offshore wind industry,” said U.S. Interior Secretary Deb Haaland.

“As the first offshore wind project solicited by Connecticut, we are particularly pleased to see Revolution Wind receive final approval from BOEM, clearing the way for the project to fulfill its promise of delivering clean energy, providing good jobs and enhancing local economies,” said Charles Rothenberger of New England for Offshore Wind.

“The U.S. offshore wind industry is on the move,” said Liz Burdock, CEO of the Business Network for Offshore Wind. “The steady stream of offshore wind project environmental reviews is critical to the success of supply chain investments, and today’s announcement bolsters investments in component production at ProvPort in Rhode Island, cable manufacturing in South Carolina, steel fabrication in western New York, and shipbuilding in Texas and Louisiana.”

“The Revolution Wind project will play a significant role in advancing the state’s Act on Climate law, growing our clean energy economy and achieving our 100% renewable energy standard objectives,” said Rhode Island Gov. Dan McKee.

“With the federal record of decision, we now advance Revolution Wind to the construction phase, bringing good-paying jobs to hundreds of local union construction workers, keeping local ports busy with assembly and marshaling activities and further growing the local supply chain,” said David Hardy, CEO Americas at Ørsted.

“The extreme weather we’ve experienced this summer underscores the growing dangers and devastating effects of global warming, as well as the need for bold solutions to address the climate crisis,” said Connecticut Gov. Ned Lamont (D).

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FERC Sides with Wind Developer vs. NorthWestern

FERC on Monday granted in part, and dismissed in part, Ponderosa Power’s complaint that NorthWestern Corp.’s proposal to assign roughly $30 million in network upgrade costs to the wind farm developer violates NorthWestern’s tariff and the commission’s “but for” cost allocation policy (EL23-48).

The agency agreed with Ponderosa that NorthWestern’s assignment of the disputed upgrade costs in an optional study that applied a rounding policy is contrary to FERC’s “but for” policy and violated the utility’s tariff. FERC dismissed the remainder of Ponderosa’s complaint as moot because it found for Ponderosa on the issue. It also declined the developer’s request to investigate NorthWestern’s interconnection queue practices, saying the record doesn’t warrant such a review.

NorthWestern’s modeling software represents thermal violations in decimal numbers with values to the hundredth decimal point. As a result, loading values between 99.5% and 99.99% are rounded up to 100%, FERC said, which NorthWestern deems to be a thermal violation requiring network upgrades.

Ponderosa is developing a 70-MW wind-powered generation facility that would be interconnected to NorthWestern’s transmission system in Montana. It filed a Section 206 complaint under the Federal Power Act in March after studies determined Ponderosa would have to pay the upgrade costs.

The commission found that the optional study results did not demonstrate that the disputed upgrades are required for Ponderosa’s project. It said the project’s loading value of 99.65% on one line segment did not trigger a thermal overload under the “but for” policy.

FERC said NorthWestern treats the rounding policy “as a practice that is part of its study process” but said it should be more “correctly viewed” as an after-the-fact change that materially modifies and “effectively departs from” the underlying study results.

“The rounding policy’s clear effect here is to deem the disputed upgrades to be ‘required’ for Ponderosa’s interconnection, notwithstanding that the optional study results otherwise establish that they are not,” the commissioners wrote.

FERC directed NorthWestern to issue Ponderosa within 30 days a revised optional study that removes the disputed upgrades and associated requirements and provides an updated estimate of its network upgrade costs, as the developer requested.

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DOE Wants US to Produce 50 Million MT of Clean Hydrogen by 2050

The White House and Department of Energy on Friday unveiled a new interagency task force aimed at reaching the administration’s ambitious goals for the deployment of clean hydrogen to decarbonize a range of hard-to-abate industrial and transportation sectors, from steel production to heavy-duty trucking and aviation.

The Hydrogen Interagency Task Force (HIT) “will be designed to … fully leverage the strengths and capabilities of the U.S. government to develop technologies, implement policy and overcome barriers to building a clean hydrogen economy,” said Mary Frances Repko, White House deputy national climate advisor, during a Friday webinar.

The task force will include representatives from 11 federal agencies, including EPA and the departments of Transportation, Labor, Interior, Agriculture and Commerce. Repko will co-chair the group with DOE Deputy Secretary David Turk, who laid out the administration’s timetable for clean hydrogen deployment.

The U.S. currently produces about 10 million metric tons (MT) of hydrogen a year, most of which “comes from fossil fuel sources without carbon capture,” Turk said. “By 2030, we want to produce the same amount of hydrogen, but we want to do it with clean hydrogen. … By 2040, we want to double that … from 10 million MT to 20 million MT, and by 2050, we want to go to 50 million.”

Deployments of clean hydrogen to decarbonize industry, transportation, and the power grid can enable 10 MMT/year of demand by 2030, ~20 MMT/year of demand by 2040, and ~50 MMT in 2050. | DOE

Reaching that goal would produce enough hydrogen to power all the buses, trains, planes and ships in the U.S., and could help the U.S. cut its greenhouse gas emissions by 20% by 2050, he said.

“So, this is not a nice-to-have,” Turk said. “This is not just a sideshow. This is part of the main event going forward.”

One of the core pillars of the agency’s strategy is building out a network of regional clean hydrogen hubs, with the first six to 10 funded with $7 billion from the Infrastructure Investment and Jobs Act (IIJA). Applications for the funding were due in April, and Todd Shrader, director of project management for DOE’s Office of Clean Energy Demonstrations, said the awards would be announced “in the fall.”

The purpose of the hubs is to co-locate commercial-scale production and end uses “to demonstrate different use cases from different feedstock diversity, meaning different power supplies,” Shrader said. Once DOE helps build the first six to 10 hubs, he said, “what that really does is [it] encourages and shows the lessons learned to industry to build plants 11 through 100.”

An analysis from Resources For the Future found that the applicants competing for the DOE money largely are multistate, private-public collaborations, with many planning to use renewable energy to produce clean hydrogen.

The National Clean Hydrogen Strategy and Roadmap, released in May, lays out three pillars for scaling clean hydrogen, beginning with zeroing in on high-impact end uses, such as heavy-duty transportation. The second is cutting costs so clean hydrogen is competitive with the fossil fuels used for other critical end uses, and the hubs are the third, said Sunita Satyapal, director of DOE’s Hydrogen and Fuel Cell Technologies Office,

DOE’s main initiative for cost cutting is the Hydrogen Shot, one of the agency’s Energy Earthshots, which all are aimed at reducing costs for new technologies needed to reduce U.S. greenhouse gas emissions. The goal for the Hydrogen Shot is to decrease the cost of clean hydrogen from about $5/kg to $1/kg within a decade.

Clean hydrogen is produced by using electrolyzers, powered by electricity, to split water into hydrogen and oxygen. The equipment is expensive and not yet produced at the scale needed for significant market growth.

But the lower the cost of clean hydrogen, the more sectors will open up to its use, Satyapal said. For example, getting the cost to $4/kg would make hydrogen competitive for heavy-duty trucking, she said.

“If we can get 10 to 15% of all the trucks using hydrogen fuel cells, that will enable 5 to 8 million MT of hydrogen in terms of demand,” she said.

Clean hydrogen at $2/kg could compete with biofuels, and at $1/kg, demand for clean hydrogen could grow in steel production, ammonia and energy storage, she said.

Production vs. End Use

Friday’s webinar and the announcement of the interagency task force seemed designed to fill the gap in concrete results on clean hydrogen as President Biden celebrated the first year of the Inflation Reduction Act (IRA). The law provides a production tax credit of up to $3/kg for clean hydrogen, which has been a draw for new investment.

While promoting administrative initiatives like the new taskforce, speakers at the webinar also acknowledged the challenges ahead, calling for an “all-of-industry” commitment to match Biden’s all-of-government strategy.

While passage of the IRA led to a doubling of announcements for new clean hydrogen projects in the U.S. by the beginning of 2023, more than half were for production versus about a third for end use, according to DOE. Projects in planning or under construction almost entirely are in hydrogen production, leaving the market decidedly lopsided.

“It doesn’t really do any good to have lots of production capacity if there’s not end-use capacity or an end user for the product itself,” Shrader said.

DOE recently announced $1 billion in IIJA funds to be dedicated to building demand for clean hydrogen, with the government possibly acting as a “market maker,” buying hydrogen from the hubs and selling it to others. (See DOE to Invest $1 Billion to Build Demand for Clean Hydrogen.)

Other obstacles cited in DOE’s recent Pathways to Commercial Liftoff: Clean Hydrogen report include a lack of “midstream infrastructure” — pipelines or other means of transport — for situations where hydrogen production and end use are not collocated, and the need for increased scaling of renewable energy.

Without adequate renewables — wind, solar and nuclear — the report predicts that fossil fuels with carbon capture and storage (CCS) could be used to produce up to 80% of clean hydrogen by 2050, as opposed to fossil fuels with CCS and renewables producing 50% each.

With utilities and other industries looking at mixing natural gas and hydrogen, pipeline safety also could be an ongoing concern. Mary McDaniel, of the Department of Transportation’s Pipeline and Hazardous Materials Safe Administration (PHMSA), said her agency has been tightening regulations on pipeline leak and rupture detection and mitigation.

“We have 1,500 miles [of pipelines] that are pure hydrogen at this point,” McDaniel said. “We’re going to be looking at hydrogen blending for pipelines as it gets more use in the pipeline line system; so, making sure that we have the infrastructure in place for that. Then we’ll be able to make any leak detection and response for those leaks.”

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NYISO: Software Upgrades for DER Participation to be Ready Next Month

NYISO told FERC on Thursday the software development and testing necessary to implement its distributed energy resource participation model will be ready by Sept. 1 (ER23-2040).

The ISO had requested an effective date of Dec. 15 for the revisions it had submitted in June, later than it thought necessary but proposed “out of an abundance of caution.”

“Prompt commission action will enable DER and aggregations to begin enrolling in the NYISO’s markets by the end of 2023,” the ISO said in response to FERC staff’s deficiency letter, which sought more information on the proposal. (See FERC Seeks More Info on NYISO DER Aggregation Proposal.)

FERC had approved NYISO’s participation model in 2020, but the ISO proposed modifications this year to better align the model with its new software and ease the burden on staff. Among those changes was a controversial 10-kW minimum for DERs in an aggregation to participate. The commission directed the ISO to explain how it had come to the 10-kW figure.

NYISO said it had become apparent that the new manual processes developed to enroll and track DER and aggregations “would be unmanageable with a high volume of DER penetration.” It said it analyzed enrollments in its existing Emergency Demand Response Program and Special Case Resource program as comparable proxies to the DER participation model. Of the 9,814 resources in the two programs as of July 1, 6,475 are less than 10 kW, it said. At a combined 7.3 MW, they represent just 0.58% of the programs’ total capability.

“NYISO does not currently have sufficient resources to timely and efficiently administer the monthly enrollment processes required for the DER and aggregation participation model if several thousand end-use customers seek to enroll in the markets at once,” the ISO wrote. “The costs associated with building the infrastructure to enable such participation include more staff, more software and the development of new market rules that will result in less oversight of small DER.”

FERC also asked NYISO to explain what it considers a DER “material modification,” address its proposed DER metering and telemetry requirements, justify why it will use the lowest cost DER as an aggregation’s reference level and explain why it would eliminate locational-based marginal pricing and bid-based reference levels for aggregations.

NYISO said a material modification constitutes “any change to the physical and operating characteristics of the DER” and included nearly 40 examples that would trigger a review, including a change of address, ownership or capability.

The ISO also responded that its metering rules ensure consistency among similar resources and do not give one participation model, whether aggregation or standalone, an undue advantage.

Additionally, NYISO justified its reference levels revisions by claiming the proposals will help the ISO better understand aggregation market and bidding behaviors, as the lowest-cost DER level incentivizes aggregations to be available more often, while switching to cost-based references will allow the ISO to better study relevant financial data.

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NCUC Approves Duke’s Performance-based Rates

The North Carolina Utilities Commission (NCUC) on Friday approved Duke Energy Progress’ latest rate case, which includes “performance-based regulation” meant to help achieve the state’s environmental policies.

Gov. Roy Cooper (D) signed HB 951 into law in October 2021, which required the utility to implement performance-based regulation. The law defined that as “an alternative rate-making approach that includes decoupling, one or more performance incentive mechanisms and a multiyear rate plan, including an earnings-sharing mechanism (ESM), or such other alternative regulatory mechanisms.”

The law recognizes that traditional ratemaking no longer works well because utilities are shifting from making larger and more infrequent investments (such as large-scale power plants) to smaller, more frequent investments such as grid improvements and distributed energy resources, the utility said in its initial application.

Duke Energy Progress told the NCUC that it took a conservative approach on its first application for performance-based regulation (PBR) so it could gain experience from its implementation. DEP serves 1.7 million customers in the Carolinas. The firm’s other utility in the state, the larger Duke Energy Carolinas, has a pending application to implement PBR.

The new rate mechanism represents a “fairly significant departure” from how the state has regulated its utilities for decades, Friday’s order said. Specifically, the new law approved four new concepts in retail rate regulation.

First, the multiyear rate plan means DEP has its rates set for several years, with periodic changes in base rates that do not require an additional rate application. Second, utilities including DEP can use a decoupling mechanism for its residential customers. Third, the ESM allows utilities to decide to file a new rate case when their weather-normalized earnings fall below the authorized rate of return and requires them to refund customers on excess weather-normalized revenue, plus 50 basis points.

The fourth major change is the performance incentive mechanism that links rates with performance in targeted areas consistent with public policies. DEP can earn extra money for doing well under the PIMs, or it could face penalties that go back to customers if it does poorly.

The PIMs are designed to increase the number of customers on time-differentiated rates, raise the number of net-metered interconnections, encourage the interconnection of utility scale generation above DEP’s targets and help large commercial and industrial customers achieve decarbonization goals.

The order drew partial dissents from four of the seven NCUC commissioners. Chair Charlotte Mitchell dissented in part and was joined by Commissioner Kimberly Duffley in full and Commissioner Karen Kemerait on its findings on DEP’s rate of return and recovery of COVID-19 costs. Commissioner Daniel Clodfelter wrote a separate dissent.

The commission approved a rate of return of 9.8%, while Mitchell and her colleagues would have approved 10%, reasoning that the costs of borrowing money have risen significantly and DEP risks a potential ratings downgrade at the lower level, which would cost customers. It could force the utility to cut costs to maintain its rating.

“Given the dynamics of the electric system, including changes in the generating mix, as well as the increasingly extreme summer and winter weather in North Carolina, now is not the time to put DEP in a position to cut to the extent that could impair the reliable operation of the system,” Mitchell said in the dissent.

COVID expenses include costs from having a moratorium on disconnections during the pandemic, which led to bad debt and other costs, as well as costs incurred by DEP and its employees to maintain the grid during the pandemic. Mitchell would have allowed DEP to collect additional funds, and, in her dissent, argued the majority decision is not good for the firm’s financial ratings.

Clodfelter’s dissent focused in part on the PIMs, arguing the commission should have adopted ones that encourage DEP to cut costs in order to offset upward pressures on rates, and to encourage the utility to finish projects early or under budget. He noted the law gave the NCUC and stakeholders little time to implement the first rates and argued they should prepare well for the next rate case in a few years.

Duke said it was reviewing the order and that the multiyear rate plan approved by the NCUC would strengthen the electricity grid while facilitating a cleaner energy future.

“We believe this is a constructive outcome that enables Duke Energy to maintain strong progress toward building a cleaner, more reliable energy future for our North Carolina customers,” the firm said in a statement.

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PJM Stakeholders Finalize CIFP Proposals Ahead of Vote

PJM and stakeholders have finalized their critical issue fast path (CIFP) proposals and posted executive summaries detailing how their packages would redesign the capacity market if approved by the Board of Managers.

The proposals will be presented to the board during the CIFP Stage 4 meeting on Wednesday, followed by a special Members Committee meeting in which stakeholders will vote on recommending packages to the board. The board letter initiating the CIFP process stated its intention to direct PJM to make a FERC filing in October with a slate of capacity market changes to be informed by stakeholders’ recommended proposals.

The 20 proposals on the table largely fall into three camps: PJM’s two proposals and variants building off it from Constellation, Buckeye, Vistra, LS Power and the Consumer Advocates of the PJM States (CAPS); the Independent Market Monitor’s Sustainable Capacity Market (SCM) design and variants from Daymark/East Kentucky Power Cooperative (EKPC) and American Municipal Power (AMP)/J-Power; and an annual market with two capacity products designed by Leeward Energy and American Electric Power (AEP).

PJM Adds Annual Auction Design Proposal

Following stakeholder feedback that its seasonal capacity market design may need additional development, PJM added a second proposal retaining the annual Base Residual Auction (BRA) structure, while including all other changes in its original proposal. Both options will be voted on Wednesday. (See PJM Updates Proposal as CIFP Nears End.)

The seasonal design would allow generators to submit a “menu” of offers, with summer, winter and annual components. Seasonal offers would include the incremental costs to deliver capacity for that period, while the annual offer would be based on costs that could be avoided if the resource were to be committed for the full year. Resources would have separate accreditations for each season. Variable resource rate (VRR) demand curves would be created for each season and calibrated to allow the reference resource to recover its full annual costs in one season if the other season clears at zero.

Both the annual and seasonal proposals would include correlated outages, ambient de-rates and other availability risks in resource accreditation and all resources, except for energy efficiency, would be accredited under a marginal effective load carrying capability (ELCC) approach.

PJM’s proposals would shift to expected unserved energy (EUE), which aims to measure the breadth of an outage both in duration and number of megawatts shed, as the reliability metric instead of loss of load expectation (LOLE), which tallies the number of outages experienced. Marginal effective load carrying capability (ELCC) would be used for the accreditation of all capacity resources, except for energy efficiency.

The option for retroactive replacement of capacity obligations after a performance assessment interval (PAI) would be eliminated and the proposals would create a market where resources can trade hourly obligations prior to the day-ahead market.

Generators would have the option of using a default capacity performance quantified risk (CPQR) calculation to represent the risk they take on as a capacity resource.

Several Stakeholders Propose Variants of PJM Proposals

Three proposals — from the Monitor, Daymark/EKPC and AMP/J-Power — focus on the capacity performance (CP) non-performance penalty charge rate and the annual stop-loss limit. The three would redefine both parameters to be based on the annual BRA clearing price, rather than the net cost of new entry (CONE). Since their effect is the same, they will be combined in Wednesday’s voting.

The penalty rate and stop-loss were two of the three changes to the CP structure the MC recommended changing in a May vote. However, the Board of Managers directed PJM to file changes to the triggers initiating a PAI, which defines when a generator can be penalized for not meeting its capacity obligations. (See FERC Approves PJM Change to Emergency Triggers.)

In addition to changing the penalty and stop-loss to the capacity clearing price, Buckeye Power recommended that all capacity resources be required to offer into the energy market, provide hourly operating parameters and real-time telemetry, and have a fuel cost policy if their capacity offer is above zero. The company offered two variants of its proposals, including PJM’s seasonal and annual designs and the bulk of their other components.

Buckeye stated that PJM’s report on the December 2022 winter storm showed that the RTO lacks insight into the amount of curtailment it will receive from demand response (DR) resources and additional provisions are needed to ensure it can deliver on its capacity obligations. Either firm-service level (FSL) or guaranteed load-drop (GLD) would be required for DR to participate in the capacity market. Intermittent and DR resources would retain their exception from the requirement that generators offer into the capacity market.

Constellation’s two proposals mirror the bulk of PJM’s annual and seasonal capacity options, but change the risk modeling to use 50 years of historical weather data, rather than 30 years and would use a “prompt auction” timeline with six to 12 months between the auction and delivery year. The proposals also include a commitment to open a stakeholder process to consider additional changes to the energy and ancillary services (E&AS) markets.

PJM had proposed to use 50 years of weather data in previous iterations of its proposal, but arrived at the conclusion that an adjustment for warming temperatures would be needed past 30 years. After presenting multiple versions of how such an adjustment could be done, PJM decided to start its weather lookback with data from 1993 with no adjustment. The Constellation proposal would not include a climate change adjustment.

While it’s supportive of a more granular capacity market design in the future, Vistra’s executive summary argued that additional work is needed on a seasonal design before the company can support filing changes with FERC. Its proposal is based on PJM’s annual auction proposal, but with several modifications including retaining the ability for generation owners to retroactively substitute capacity obligations after a PAI, changing the default CPQR calculation and holding off on expanding the ELCC construct to all resources to the 2026/27 BRA to allow for more refining.

Vistra’s proposal would retain the penalty rate and stop-loss based on net CONE, arguing that using auction clearing prices to determine the penalties would reduce the incentive for resources to perform during an emergency. Eligibility for bonus payments to generators that overperform during a PAI would include all resources that are eligible to participate in capacity auctions, including those that do not clear. PJM’s proposal would tighten eligibility to only cleared capacity resources, which Vistra argued would reduce the incentive to perform.

The proposal includes PJM’s testing requirements, but states PJM should account for market and operating conditions when scheduling tests to avoid creating “testing traps” where a generator that would meet its obligations under real-world conditions nonetheless fails the test. It recommends testing take into account the gas pipeline nomination cycle, arguing that many resources would not procure fuel when system conditions do not indicate they will be dispatched.

The company’s proposal also calls for a stakeholder process to be initiated looking at improving accreditation for thermal resources, including marginal ELCC or alternatives, and a second CIFP process with the goal of “developing a framework that protects both consumers and market participants alike from market power, but allows resources to employ their best commercial judgement in submitting offers into the market.”

The consumer advocates’ proposal supports PJM’s seasonal model, but opposes calibrating the demand curves to allow full annual cost recovery in one season, arguing that could lead to a doubling of capacity payments. It also opposes removing the capacity benefit of ties (CBOT) from the balancing ratio, a proposition it calls “overly conservative” and not in line with the probabilistic manner in which the value of generation resources is viewed.

Removing CPQR from the calculation of resources’ avoidable cost rate (ACR) also raises market power mitigation concerns and leads to uncompetitive auctions.  It recommends leaving CPQR as a component of ACR so that risks can be offset by net E&AS revenues.

“It is unlikely that any consumer advocate office could support such a significant change in PJM’s philosophies. The consumer advocates have always strongly supported competitive wholesale markets and see the competitive construct focus as a pillar by which PJM stands upon,” the CAPS executive summary states.

The proposal also includes changing the distribution of CP bonus payments to include a share going to consumers to reimburse them for the capacity that was not delivered by resources not meeting their obligations.

LS Power based its proposal off PJM’s annual capacity package, arguing the seasonal design has not been adequately vetted, modeled and back-cast. It would substitute the marginal ELCC accreditation for thermal resources with an equivalent unavailability factor-weighted approach, which reduces accreditation for any historical shortfall in performance. Capacity offers would be similar to the energy market, with generators offering market-based and cost-based offers. The marginal offer would be subject to the Monitor market power test and would be mitigated to the cost-based offer if it fails and the auction re-run until the marginal offer does not fail the market power test.

Fixed resource requirement (FRR) entities would be required to meet their own capacity needs, as well as the average percentage that the BRA has cleared above the installed reserve margin in the prior five years. The proposal also retains retroactive replacement transactions for generators and status quo eligibility for CP bonus distribution.

The LS proposal would change the CP penalty charge rate to be based on the BRA clearing price but leave the annual stop-loss based on net CONE. The company offered a second proposal identical to its first but leaving the status quo charge rate in place.

Monitor Proposes Hourly Model with Annual Pricing

The Monitor’s proposal would create a forward capacity market where committed resources are paid for the capacity they’re available to provide in each hour of the year based on a single annual clearing price.

Resources would be cleared based on their expected hourly availability, which is based on historical data including outage correlations with temperatures and weather.

Resources would be tested at least twice each year, once each in the summer and winter, and if they fail to start then or when dispatched they would forfeit all capacity revenues going back to the last time they started and reached their full installed capacity (ICAP) and going forward until they successfully start and ramp up to their ICAP. The Monitor’s executive summary argued that the model would incentivize resources to mitigate their risk by ensuring they’re able to start at any time of the year and to self-schedule their generators periodically to both self-test and to limit the potential lost revenue if they fail a test.

All resources, including intermittent and storage, would be subject to the requirement that resources offer into the capacity market, which the Monitor argued is imperative to ensure access to transmission capability is not withheld, as intermittents make up an increasing share of the PJM fleet. Resources’ obligation would be based on their availability in each hour and they would be paid when they’re available according to their obligation, which the Monitor argued means that intermittents would not be penalized for not being available when they couldn’t produce energy.

Without penalties for nonperformance, the proposal would eliminate the CP construct and its bonuses and penalties, which the Monitor said fail to provide functional incentives outside of PAIs and potentially can increase the likelihood of emergency conditions. The high penalty rates also create a corresponding relationship with the CPQR component in generators’ offers, increasing clearing prices.

“This impact illustrates the circular logic of the CP model. The CP model creates arbitrarily high penalty rates which affect CPQR which increase the ACR market seller offer caps … Under the SCM approach, the arbitrary and extreme penalties would be eliminated and therefore the impact on CPQR and the impact on capacity market clearing prices would be eliminated,” the Monitor’s executive summary states.

Stakeholder Hourly Capacity Proposals

The joint EKPC and Daymark proposal also would clear capacity to meet firm load in each hour of the delivery year with locational deliverability constraints, but would bifurcate the product into base capacity (BC), which would be hourly expected load plus the reserve margin, and emergency capacity, which is aimed at meeting hourly load during emergency conditions with modeling of extreme weather and fuel delivery force majeure. Resources could take either an EC or a BC position in capacity auctions, but not both.

Emergency capacity resources would be required to demonstrate they can operate under extreme temperatures and humidity, akin to the enhanced winterization concept in PJM’s proposal, show they have the financial ability to absorb non-performance penalties and have verifiable firm fuel. It would be procured in tranches and committed for three-year intervals.

Base capacity would be considered to have met its obligation if it offers committed capacity into the day-ahead and real-time markets, while EC would be considered to have not met its obligation if it’s unavailable during a dispatch day where emergency conditions are present. A non-performing EC resource would be subject to a penalty of the daily capacity rate multiplied by 120 and its unforced capacity. If it’s unavailable three times during a three-year interval, it would be removed from the roster of EC resources for the remainder of the period.

The third joint EKPC and Daymark proposal would combine PJM’s risk modeling component, eliminate CP penalties and use the Monitor’s hourly method of measuring and compensating capacity.

Taken together, the three joint AMP and J-Power proposals would create a two-phased transition to a modified version of the Monitor’s SCM. The transitional phase would include the proposed shift to a CP penalty and stop-loss based on capacity clearing prices, as well as changes to the balancing ratio to include net exports and applying the same penalties to FRR resources that generators participating in PJM’s Reliability Pricing Model face. The option of using physical penalty commitments also would be eliminated for FRR entities.

The proposal for the second phase would revise the SCM to have a two-year procurement horizon with two Incremental Auctions and no exceptions to the requirement that capacity resources offer into the energy market.

Leeward and AES Propose Four-plus Season Market

A proposal from Leeward and AES, jointly made as the capacity coalition, would create a capacity market with at least four seasonal and four intervals for each day of the delivery year. The auction structure would follow the status quo for establishing clearing prices, but would have separate accreditation for their expected output for each seasonal and daily interval. All resources would be subject to the must-offer requirement into the capacity market once the new market structure has been established.

Rather than being designed for implementation in coming auctions, like other proposals, the coalition’s proposal recommends rollout in the 2030-31 delivery year. The proposal calls for an additional CIFP-like process to create more detailed rules for the new structure.

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Contentious Commentary on Zero-Emissions Path in NY

As the New York Public Service Commission probably already knew when it requested comments on “zero emissions,” everybody has their own solution to save the world — and it often aligns closely with their income stream.

The answers to a series of PSC questions in case 15-E-0302 on the theory and execution of zero emissions in the state drew a wide range of responses.

The PSC in May formally recognized what others have been warning about for some time: The preferred renewable technologies now available at scale — wind and solar — may not be enough for the state to meet its statutory goals for the clean energy transition. (See NY Renewable Portfolio May Come up Short on Getting to Net Zero.)

The landmark Climate Leadership and Community Protection Act of 2019 mandates 70% renewable energy by 2030 and a zero-emissions grid by 2040.

As state leaders point out, accurately and frequently, New York has a robust pipeline of renewables in development. But what they don’t highlight is that the pipeline is flowing slowly, with numerous project delays and cancellations, as well as spiraling costs.

Perhaps more importantly, no renewable technology has been identified to keep the lights on when the wind doesn’t blow and the sun doesn’t shine in a state increasingly reliant on electricity.

So the PSC is looking for other ways to reinforce the power portfolio, potentially including renewable natural gas, nuclear fission and hydrogen — none of which are supported by the progressive activists and environmental advocates who are helping push New York’s energy transition.

The commission requested public input on decisions that may direct billions in spending and impact millions of New Yorkers. It received comments from dozens of stakeholders before the comment period ended last week.

Push And Pull

As one would expect, the answers covered a spectrum of possibilities.

Labor unions urged the PSC to choose the options that best protect their members and the planet.

Gas utilities said they’re ready to heat and power the state with climate-friendly gas, be it RNG or hydrogen.

Environmentalists decried any rush to unravel the CLCPA, such as by burning RNG or hydrogen.

A developer with wind power, energy storage and transmission projects in the works said more renewables, more storage and more transmission are needed.

Progressives demanded continued focus on the disadvantaged communities that have been breathing elevated levels of fossil fuel emissions for decades.

The waste management industry wants RNG extracted from landfills and the dairy industry wants RNG extracted from cow poop. An RNG trade organization wants both.

New York City, with a poverty rate 47% higher than the national average, supports decarbonizing the grid but wants someone other than its residents to pay to do it.

Nuclear power generation must expand. No, it must halt!

National Grid — whose utilities serve more than 2.5 million natural gas customers statewide and are facing a huge if not existential threat from the campaign for zero emissions — advocated for continued use of gas. It also questioned the very concept of zero emissions.

“‘Zero emissions’ as used in this section of the law cannot be defined literally, as very few sources of energy have literally zero GHG emissions associated with their production and use throughout their life cycle,” National Grid wrote.

It also parsed the language of the law to conclude that “zero emissions” must not exclusively mean “renewable energy systems.”

The New York State Energy Research and Development Authority, which is administering the clean energy transition in New York, provided a two-page comment that at once was among the broadest and most succinct of all submitted.

In summary, NYSERDA said New York needs to identify the appropriate resources to meet the grid’s 2040 needs, refine the cost and performance estimates, further evaluate their emissions, find a place to site them, calculate impacts on disadvantaged communities, factor in demand response and storage, incorporate any future nuclear or 100-hour storage technology yet to be perfected, then integrate all this with existing resources.

Comments

A cross-section of these comments is excerpted and summarized below:

The Energy Justice Alliance said the state’s climate targets and its most urgent environmental justice challenges can be met only through retiring fossil fuel generation in an orderly and just manner. It urged stakeholder and public input before selecting any nonrenewable resources. It said alternatives such as RNG, green hydrogen biofuels, carbon capture and advanced nuclear technology were recommended in the Climate Action Council Scoping Plan for only limited and strategic use, to be considered only after rigorous review.

U.S Plumbers and Steamfitters Local 22 urged an expanded, inclusive definition of “zero emissions energy sources” as anything that does not lead to a net increase in greenhouse gas emissions in the process of generating electricity. Clean hydrogen should be recognized as fitting the bill, it said.

Constellation Energy Generation, owner of the state’s nuclear fleet, said all types of nuclear technology should be included in the definition of “zero emissions.” One of its New York nukes recently began sustained generation of pink hydrogen in a pilot project; Constellation said hydrogen combustion will be a valuable part of the puzzle.

The supervisor of the town of Scriba, home to two of the nukes, urged the PSC to formally recognize nuclear fission as a zero-emission resource.

The Alliance for a Green Economy said it’s deeply concerned about the environmental, human health and financial implications of including nuclear power in a definition of zero emissions — which it is not, because it emits radiation.

Nuclear New York said nuclear power should be the backbone of the state’s future emissions-free energy system, not the backup, adding that the state itself found that adding 4 GW of nuclear generation would eliminate the need for 12 GW in intermittent renewables and 5 GW of storage.

In a joint comment, the Sierra Club and Earthjustice advocated for strict and literal interpretation of “zero emissions” — no pollutant emissions. That rules out hydrogen, RNG, carbon capture and sequestration, biomass and, under some circumstances, demand response. They did not mention nuclear power, a longtime target of the Sierra Club.

The New York State AFL-CIO and the New York State Building & Construction Trades Council, umbrella groups for unions representing 2.7 million people, said the PSC must prioritize maintenance and creation of good union jobs while maintaining service and limiting price increases. They indicated support for the broader definition of “zero emissions.”

A collection of 43 environmental and progressive organizations jointly commented that while it was good the PSC is looking for strategies beyond wind and solar to meet the zero-emissions mandate, technology may advance in the coming decade, and it’s premature to create policies now to avert a resource gap in 2040. There is no “need to water down” the CLCPA’s targets, they said.

NYISO urged that “zero emission” be defined to allow as many technologies as possible to qualify. It noted that increasing transmission and increasing generation will not by themselves fully solve the problem of insufficient resources. The technologies that would solve the problem are not available, and it’s unknown when they will be.

Plug Power, a New York-based generator of green hydrogen and manufacturer of hydrogen technology, said the PSC should fully support and incentivize the full suite of existing and emerging green hydrogen applications. In fact, the PSC should establish a new tier in the state’s Clean Energy Standard for zero emissions resources, with an emphasis on green hydrogen, and help jump-start investment in hydrogen infrastructure.

PSC should expand the definition of net-zero “combustion turbines” to include reciprocating internal combustion engines, said Wartsila Energy, North America, whose parent company has deployed over 76 GW of reciprocating internal combustion engine power plants worldwide.

National Fuel Gas Distribution Corporation said a good definition of zero emission would be “systems other than renewable energy systems that generate electricity or thermal energy technologies that do not lead to a net increase in greenhouse gas emission into the atmosphere.” And that should be construed to include RNG.

New York Transmission Owners stated electric system reliability must remain the paramount priority, coordination with NYISO is essential, an agnostic approach to technology is best and pilot programs will be helpful. And all of this must be done in a timely and deliberate fashion.

The PSC in May directed Department of Public Service staff to convene a technical conference on the matter.

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Commerce Department to Reimpose Tariffs on SE Asian Solar Manufacturers

The Commerce Department on Friday announced its final decision to impose tariffs on solar cells and panels imported from Cambodia, Malaysia, Thailand and Vietnam, finding that some Chinese manufacturers are shipping their products through the four countries to avoid paying tariffs called “antidumping and countervailing duties” (AD/CVD).

Confirming a preliminary decision from December 2022, Friday’s ruling found that of eight companies operating in the countries, five “were attempting to avoid payment by completing minor processing in third countries, and that three companies were not circumventing.” The three noncircumventors are Hanwha Q CELLS and Jinko Solar, both with facilities in Malaysia, and Boviet Solar in Vietnam.

The circumventing companies are BYD Hong Kong and New East Solar in Cambodia; Canadian Solar and Trina Solar in Thailand; and Vina Solar in Vietnam. Other solar manufacturers in these countries, though not part of the official investigation, also were found to be circumventing.

Hanwha is the No. 1 panel provider in the U.S. market, according to industry analysts Wood Mackenzie, while Jinko, Canadian and Trina also are in the top 5, which in 2022 accounted for 50% of the U.S. market.

President Joe Biden declared a two-year moratorium on the tariffs in June 2022, which means the Commerce decision will not go into effect until June 2024. Following a congressional resolution seeking to roll back the moratorium in May, Biden also stated he does not intend to extend the moratorium. (See Biden Veto Upholds 2-year Moratorium on Solar Tariffs.)

No tariffs will be imposed on any solar imports from the four countries until June 2024, providing that any products from the four countries “are consumed in the U.S. market within six months” of the end of the moratorium, according to Commerce’s announcement.

“This provides U.S. solar importers with sufficient time to adjust supply chains and ensure that sourcing is not occurring from companies found to be violating U.S. law,” the department said.

The solar industry quickly criticized the decision, arguing that it undercuts the administration’s efforts to increase solar deployment as part of its fight against climate change.

The department’s investigation was based on a complaint from a U.S. solar manufacturer, Auxin Solar, that was “meritless from the beginning,” Abigail Ross Hopper, CEO of the Solar Energy Industries Association (SEIA), said in a statement released Friday.

“The inquiries have caused uncertainty in the U.S. market at a time when solar energy is on the rise. The final affirmative determinations only perpetuate current supply problems, given the lack of adequate domestic supply of cells and modules,” Hopper said.

While noting that clean energy manufacturing incentives in the Inflation Reduction Act (IRA) have driven a “$20 billion solar manufacturing renaissance” in the U.S., “it will take at least three to five years to ramp up domestic solar manufacturing capacity, and the global supply chain will be vital in the short term,” she said. “This case will just make it harder for American businesses to keep deploying, financing and installing solar power.”

Gregory Wetstone, CEO of the American Council on Renewable Energy, lamented that the Commerce decision comes just days after Biden had celebrated the first anniversary of the IRA at the White House. The decision “directly undermines Biden administration efforts to accelerate the deployment of renewable energy and address climate change,” Wetstone said. “The policy whiplash now being inflicted on the U.S. solar industry is incredibly disruptive and will only delay our nation’s clean energy progress.”

“Our collective focus should be on fostering smart policies that accelerate clean energy deployment nationwide,” said George Hershman, CEO of SOLV Energy, a utility-scale solar contractor. “Detrimental trade barriers like this one run counter to our efforts to meet deployment goals while the industry capitalizes on the incentives provided in the Inflation Reduction Act to boost domestic manufacturing and grow our national supply chain.”

Mamun Rashid, CEO of Auxin, previously has defended his company’s complaint to the Commerce Department, saying Chinese imports are an “existential” threat to its business, according to a CNN report.

“When prices of finished panels from Southeast Asia come in below our bill of materials cost, American manufacturers cannot compete,” Rashid said. “If foreign producers are circumventing U.S. law and causing harm to U.S. producers like Auxin Solar, it needs to be addressed.”

Carrots and Sticks

The Commerce decision highlights the conflict between the U.S. solar industry’s ambitious targets for market growth and its ongoing dependence on foreign — specifically Chinese — manufacturers for its key components.

A 2022 Energy Department report found that 97% of silicon wafers, an essential component of solar panels, are manufactured in China, and 75% of the silicon solar cells built into panels installed in the U.S. come from Malaysia, Thailand or Vietnam.

Also, the industry has been hobbled by the Uyghur Forced Labor Prevention Act (H.R. 6256), passed in 2021, which prohibits the import into the U.S. of any goods produced in China using forced labor. This year, U.S. Customs and Border Protection was holding a major backlog of solar imports under the law, hitting hard at solar developers and causing project delays, according to an Axios report.

Both sides of the aisle in Congress have been taking a harder line on China, and ClearView Energy Partners sees Friday’s decision as in line with Commerce’s “protectionist leanings … irrespective of political polarities.”

The department first slapped tariffs on Chinese solar panels in 2012, during the Obama administration, siding with U.S. solar companies that argued that Chinese companies, heavily subsidized by their government, were undercutting domestic manufacturers and dumping cheaper panels in the U.S. market. AD/CVD tariffs — from 31 to 250% at the time — were intended to level the playing field and spur the buildout of a domestic supply chain, they argued. (See Solar Industry Slams Commerce Decision Extending Solar Tariffs.)

Over the next decade, solar manufacturing migrated to Cambodia, Malaysia, Thailand and Vietnam, and U.S. tariffs failed to catalyze a homegrown supply chain. In 2018, President Donald Trump expanded the Chinese tariffs to the four Southeast Asian countries.

Biden decided in February 2022 to continue the tariffs but instituted the two-year moratorium after Commerce opened the investigation of the Auxin complaint. In an April 2023 policy statement, the White House said the moratorium was intended as “a short-term bridge to ensure there is a thriving U.S. solar installation industry ready to purchase the solar products that will be made in these American factories” built with incentives from the IRA.

Jason Grumet, CEO of the American Clean Power Association, said his organization has counted 52 new or expanded solar manufacturing facilities announced since passage of the IRA. But the majority of the announcements are for plants that will make panels or related system components, not the silicon wafers and cells to replace the Chinese supply chain.

Hanwha, a Korean company, announced in January it would invest $2.5 billion to expand its manufacturing capacity in the U.S. Similarly, Jinko is putting $52 million into expanding its U.S. plant in Jacksonville, Fla.

CubicPV, a U.S.-based company with backing from Bill Gates’ Breakthrough Energy Ventures, is planning a U.S. facility to produce wafers. NorSun, a Norwegian wafer and ingot manufacturer, also has announced plans for a 5-GW U.S. plant.

ClearView believes the U.S. solar industry will continue to have a lopsided supply chain even as the market continues to grow. SEIA estimated that the U.S. industry had about 7.5 GW per year of panel manufacturing capacity at the end of 2021, a figure that could triple by 2024 with incentives from the IRA, according to the White House.

But the Energy Information Administration is estimating solar deployments of more than 39 GW this year alone, which ClearView says will leave the industry still dependent on imports, with further help from Biden unlikely.

Writing ahead of Friday’s announcement, ClearView said, “The Biden administration may view new and expanded renewable power tax credits as sufficient ‘carrots’ to offset a possible affirmative AC/CVD circumvention determination ‘stick.’”

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CEC: California Renewable Use Rose Sharply in Past Decade

Natural gas made up the largest share of California’s electric generation mix in 2022, but solar is accounting for a growing percentage as the state works toward 100% clean energy by 2045.

The data are in a report the California Energy Commission (CEC) released Friday.

Natural gas accounted for 36% of the state’s overall power mix last year, which includes in-state electric generation plus imports from the Northwest and Southwest.

The second-largest share was from solar, at 17%, followed by wind at 11%. Nuclear power and large hydroelectric generation each contributed 9% to the state’s 2022 energy mix.

Fifty-four percent of the state’s total energy mix came from non-GHG and renewable sources in 2022, up from 52% in 2021.

CEC Vice Chair Siva Gunda called the findings “encouraging.”

“Even as climate impacts become increasingly severe, California remains committed to transitioning away from polluting fossil fuels and delivering on the promise to build a future power grid that is clean, reliable and affordable,” Gunda said in a statement.

California’s energy mix has changed markedly since 2012, when 43% of the total came from natural gas. Over the past decade, natural gas generation decreased 20%, to 104,495 GWh.

Meanwhile, solar generation has grown from 2,609 GWh in 2012, when it was less than 1% of the power mix, to 48,950 GWh last year.

Wind generation in California’s power mix grew by 63% since 2012. Coal has been nearly phased-out, the CEC said, contributing just 2% of the power mix in 2022.

Total utility-scale electric generation for California increased 3.4% in 2022, to 287,220 GWh. Twenty-nine percent of the power mix was from imports, about the same as in the previous two years.

Despite the decrease in natural-gas fueled power generation in California, some are calling for a faster phase-out. Looking just at in-state electricity generation, natural gas made up 47% of the total in 2022.

Advocacy groups including Regenerate California point to the disproportionate effect the gas-fueled plants have on disadvantaged communities.

And the group said gas “stands in the way” of the state meeting its target under Senate Bill 100 of 2018, which directs the CEC and other state agencies to plan for all retail electricity sales in California to come from renewable energy and zero-carbon resources by the end of 2045.

“As we power down California’s dirty fossil fuel infrastructure, this gives us the opportunity to create thousands of clean energy jobs and an entirely new system that transforms current and historic social injustices,” Regenerate California said on its website.

The issue of retiring gas plants boiled over this month at a CEC hearing, where the commission voted to keep three old gas-fired plants along the Southern California coast in operation for grid reliability. (See Calif. to Keep Old Gas Plants Operating for Reliability.)