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November 1, 2024

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FERC Sets MISO TOs’ ROE at 9.98%, Again Eliminates Risk Premium Model

FERC continues to fiddle with the return on equity MISO transmission owners can earn, this time setting the base amount at 9.98% while once again eradicating the risk premium model from the calculation.  

The Oct. 17 order is the latest in a yearslong string of adjustments to the MISO TOs’ ROE and might represent a step closer to settling the more-than-decade-old debate over which rate inputs are appropriate (EL14-12, et al.).  

FERC said when examining the case, it found no evidence that investors use the risk premium model, a conclusion it came to once before in 2019. The commission insisted it made “a principled and reasoned decision supported by the evidentiary record.” 

By ousting the risk premium model, FERC again is down to relying on two models — the discounted cash flow (DCF) and the capital asset pricing (CAPM) — to establish a zone of reasonableness and set the ROE at its midpoint. FERC said the new zone of reasonableness is between 7.39 and 12.58%. 

FERC ordered MISO TOs to adopt the 9.98% base ROE effective near the end of September 2016 and provide refunds to customers with interest for a 15-month refund period beginning with the date of the initial complaint Nov. 12, 2013.  

The commission has tinkered with and set an assortment of ROEs for MISO TOs in recent years: In 2013, it was using a 12.38% rate; after the complaint from MISO transmission customers, it landed on a 10.32% rate in 2016, which was reduced to 9.88% in 2019 and then upped to 10.02% in 2020. FERC said in the latest order that it continued to find the circa-2013, 12.38% base ROE excessive.  

FERC has cut the risk premium input once before, when it set the 9.88% base ROE, then changed course when it established the new ROE in 2020 under a Republican majority of commissioners. When formulating an ROE for the privately held MISO TOs, the commission attempts to formulate their stock price as if they were publicly traded. The risk premium model tries to emulate the cost of equity using the premium that investors would expect to earn on a stock investment over the return they would expect to earn on a bond investment. 

FERC found the ROE case back on its docket because of the risk premium model’s inclusion since 2020. The D.C. Circuit Court of Appeals in 2022 vacated FERC’s 10.02% value. The court said it didn’t understand why FERC would spend pages describing the risk premium model’s shortcomings, circular nature and scarce use only to reinstate its application in 2020. (See DC Circuit Sends FERC Back to Drawing Board on MISO ROE.)  

FERC left the other two models alone and continued to find a DCF zone of reasonableness at 6.97 to 12.07%, and the CAPM’s range is 7.80 to 13.09%. 

While this time FERC said no further changes to the ROE methodology are necessary, it left the door open to including the risk premium model once again if parties can show that potential benefits outweigh concerns with the model.  

The commission said it understood that cutting the risk premium model reduces the “diversity of inputs” and increases the weighting for the CAPM and DCF model. FERC said it could be open to using “a blended historical and forward-looking risk premium in the CAPM in future proceedings as a potential means to mitigate volatility concerns with the commission’s ROE methodology.”  

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5th ‘Alert’ Touts Markets+ Support for Clean Resources, GHG Policy

Proponents of SPP’s Markets+ argue in their latest “issue alert” published Oct. 16 that the framework allows more flexibility for integrating greenhouse gas emission reduction programs across various states than CAISO’s Extended Day-Ahead Market (EDAM).

The alert is the fifth in a series of seven notices highlighting the purported advantages of Markets+ over EDAM and the Western Energy Imbalance Market (WEIM). The first covered differences between how the two markets would be governed, the second focused on reliability, the third compared pricing practices, and the fourth tackled market seams.

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power.

In their fifth alert, the proponents argue that Markets+ is better positioned to address risks associated with market price formation, deliverability and congestion that can “materially impact the feasibility and expected value of investments in clean energy that can be brought to load.”

For example, Markets+ uses fast-start pricing and graduated scarcity pricing approaches, which, according to the proponents, send “transparent price signals to encourage investment and use of clean and flexible resources and storage when they are needed most.”

The alert also points to the flow-based dispatch used in Markets+, which the proponents claim will increase “the deliverability of resources across the [balancing authority]-to-[balancing authority] and [transmission service provider]-to-[transmission service provider] seams within the footprint, resulting in less congestion and more delivered clean energy than the EDAM design.”

Additionally, Markets+ provides enhanced protection from congestion costs by allocating congestion revenue to firm transmission rights holders in proportion to the congestion costs incurred on their specific transmission paths, according to the alert.

“This approach provides an opportunity for remote resources to hedge congestion costs and reduce the price risk of delivering clean energy investments to load,” the alert stated. “In contrast, the EDAM congestion revenue structure increases the financial risk for those delivering remote clean resources as the congestion revenue allocation is split between the market operator (at BAA boundaries) and EDAM entities (internal congestion).”

“This bifurcation creates significant uncertainty that the allocation methodology selected by each EDAM entity may not allocate congestion costs on an individual transmission path basis, preventing those delivering remote resources from being able to accurately forecast or hedge against congestion,” the alert added.

GHG Pricing, Tracking and Reporting

The alert also touts Markets+’s greenhouse gas emissions pricing features and tracking and reporting system.

It says the “Type 1A” option in Markets+ would ensure that external supply contracted to serve load in a GHG pricing zone will be attributed to that zone if dispatched.

“This provides load-serving entities with an increased ability to hedge their exposure to GHG costs through advanced contracting of clean supply,” it says. “It is our understanding that the same functionality is not currently available in EDAM.”

Additionally, a “Type 2” option allows a market participant located outside a GHG pricing zone to economically offer its own surplus clean energy to be attributed to a GHG pricing zone, allowing it to “retain the clean supply needed to serve its load obligations while providing an opportunity to be compensated for its surplus clean energy.”

The alert says also that the Markets+ reporting and tracking mechanism allows the market to quantify emissions associated with “residual” dispatched energy not “otherwise claimed by load-serving entities in the market.”

“The design enables participants to determine how energy is attributed to meeting their own load and how unattributed surplus energy is accounted for in residual energy reporting,” it says.

“We are pleased to have worked closely with a diverse group of Western entities to meet each state’s GHG tracking and reporting needs with the development of M+ GHG protocols,” Lisa Tiffin, senior vice president of energy management at Tri-State, said in a statement. “GHG tracking, including from energy markets transactions, will be critical for Tri-State as we progress in the energy transition.”

“CAISO also has recently proposed to develop a GHG tracking and reporting framework based on stakeholder requests and the Markets+ approach may serve as a starting point,” the alert says. “This development highlights how the existence of two competing organized markets provides greater opportunity for both markets to continuously evolve with improved products, services and market design.”

Reached for comment, CAISO said its Western Energy Imbalance Market already supports renewable integration across the West “by efficiently optimizing low-cost renewable generation and dispatching it to serve demand in the middle of the day when it is most abundant, reducing the costs of serving load for utility customers. The Extended Day-Ahead Market (EDAM) design, approved by the Federal Energy Regulatory Commission (FERC), builds on those proven advantages.”

The issue alert follows the release of a white paper by The Brattle Group, published in early October, offering a point-by-point comparison of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ that leans in favor of EDAM but stops short of endorsing either market. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.)

Regarding greenhouse gas pricing mechanisms, the Brattle study notes that EDAM builds off the Western Energy Imbalance Market, saying EDAM benefits from this tried and tested approach.

“The experience of the last ten years and our own forward-looking simulation analysis indicates that the WEIM/EDAM approach is effective at delivering customer savings while limiting leakage, which could otherwise reduce the effectiveness of GHG regulations,” according to the Brattle study. “Therefore, stakeholders in EDAM have more certainty that the GHG pricing mechanism will achieve efficient outcome while minimizing leakage.”

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MISO to Request Year Deferral on FERC Order 1920

CARMEL, Ind. — Though it’s largely compliant with the directives of FERC’s Order 1920 on regional transmission planning, MISO intends to seek a yearlong extension of the June 2025 compliance deadline. 

MISO said it expects to file an extension request with FERC at the end of this month to give it more time to describe how it meets all planning directives.  

At an Oct. 16 Planning Advisory Committee, Director of Expansion Planning Jeanna Furnish said that though MISO believes it’s “directionally compliant” with Order 1920 through its work on long-range transmission planning (LRTP), “much work and assessment is still needed to show compliance.”  

Some stakeholders said it seemed strange MISO would need a year to demonstrate to FERC that it’s already planning projects in general accordance with the order.  

The Union of Concerned Scientists’ Sam Gomberg said that “at first blush,” a yearlong extension seems excessive. A former FERC commissioner has said MISO is ahead of the pack on transmission planning initiatives and acknowledged the commission modeled the order largely on planning taking place within the footprint. (See MARC 2024 Displays Mixed Feelings on Transition Feasibility.)  

Stakeholders asked if MISO planners were getting a jump on drafting a compliance plan should FERC reject a delay.  

“We are trying to get the extension request in as soon as possible so we can manage that timeline,” MISO’s Jeremiah Doner said.  

Meanwhile, MISO has put out a call for transmission study ideas from stakeholders for its 2025 Transmission Expansion Plan (MTEP 25). MISO, as it has with other recent MTEPs, warned it will be limited in what new studies it can accommodate because much of its planning bandwidth is dedicated to LRTP.  

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FERC Finalizes Order 1977 on Backstop Transmission Siting

FERC acted on rehearing requests for Order 1977 on Oct. 17, finalizing the rules it will follow under limited backstop siting authority for transmission lines. 

The major change FERC made to the original proposal, which was approved this year alongside Order 1920 on transmission planning, was to require projects seeking rights of way on Tribal lands to include their proposals in Tribal engagement plans. Developers will have to describe how they will work with Tribal landowners on right-of-way issues. 

“We at FERC are focused on Tribal engagement,” FERC Chairman Willie Phillips said in a statement. “It is important that project sponsors work closely with Tribal landowners on these right-of-way issues as part of their overall engagement with Tribes on transmission matters.” 

The order lays out how FERC will handle backstop siting applications in National Interest Electricity Transmission Corridors. They were established by the Energy Policy Act of 2005, but for much of that time, the authority was hobbled by a court decision. Congress updated the law in 2021 to say FERC could overrule a state that denies a transmission line’s application that would go through NIETC if approved by the Department of Energy. 

DOE announced preliminary NIETCs this spring a few days before FERC’s initial order but has yet to finalize corridors where the commission’s backstop siting authority could be used. (See On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

The new rule includes a Landowner Bill of Rights, codifies an Applicant Code of Conduct as a way for applicants to show good faith engagement with landowners and directs applicants to develop engagement plants for outreach to environmental justice communities and Tribes. 

The New York PSC filed for rehearing, arguing FERC should be able to step in only a year after a complete application has been filed with a state regulator. FERC agreed a final application is an important consideration for the process but declined to include the requirement the PSC sought. 

The pre-filing process requires developers to inform FERC of the status of any state applications and allows state regulators to raise issues around their review when any application is being debated before the federal regulator. The commission will look at issues case by case, the rehearing order said. 

The Louisiana PSC asked that FERC give deference to state decisions and presume they are correct, with the burden of proof on developers to overcome state decisions. FERC said it would take the state decisions into account but that they are not determinative under the law. 

“If the commission finds that the statutory criteria under section 216(b) have been met, it may issue a permit to construct or modify electric transmission facilities in a national corridor notwithstanding a state’s denial of the same,” FERC said. “The commission’s consideration, as described in the final rule, of whether an application meets the statutory criteria for commission jurisdiction does not improperly intrude upon state authority.” 

A group of public interest organizations argued that FERC should automatically include all of a state docket’s information as it reviews a line for backstop siting. FERC rejected that request, saying while it will consider relevant information from state proceedings, some of the filings could be irrelevant to the federal process. 

The public interest groups argued the lack of automatic filing could set a procedural trap to keep relevant information out of the FERC proceeding, noting the start of a pre-filing process and the filing of an actual application with the commission are intended to encourage stakeholder participation and disseminate information about the case. Applicants must make a good faith effort to notify “any known individuals or organizations that have expressed an interest in the state siting proceeding,” the order said. 

The Pennsylvania PUC wanted rehearing on the Landowner Bill of Rights, arguing that states should be able to help develop such documents and the current version ignores state siting authority, which could misinform landowners. 

FERC said having multiple versions of the Landowner Bill of Rights could lead to confusion and inefficiencies. 

“Requiring applicants to provide affected landowners with a copy of the Landowner Bill of Rights — a generic document developed by the commission and intended to provide information about the federal permitting process in a broad and consistent manner — does not preclude an applicant from providing additional information to landowners about additional rights under state law or ongoing state siting proceedings, if applicable,” FERC said. 

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Amazon Moves to Accelerate SMR Development

Amazon is stepping further into the nuclear energy market, announcing multiple agreements surrounding advanced reactor technology that could provide carbon-free electricity for its operations.

The Oct. 16 announcements are the latest display of nuclear interest by energy-intensive data crunchers. Just two days earlier, Google announced a pioneering agreement to support Kairos Power’s development of its small modular reactor (SMR) and then buy power from the first few units built. (See Google, Kairos Sign 500-MW Nuclear PPA.)

Amazon itself agreed earlier this year to operate a data center co-located with Talen Energy’s existing nuclear plant in Pennsylvania. The move made news, and waves. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

“One of the fastest ways to address climate change is by transitioning our society to carbon-free energy sources, and nuclear energy is both carbon-free and able to scale — which is why it’s an important area of investment for Amazon,” Matt Garman, CEO of Amazon Web Services, said in a news release. “Our agreements will encourage the construction of new nuclear technologies that will generate energy for decades to come.”

Amazon’s latest plans involve three other entities: X-energy Reactor Co., Energy Northwest and Dominion Energy Virginia.

X-energy

Amazon and others will invest $500 million in X-energy to help it complete design and licensing of its Xe-100 SMR and build a fuel fabrication facility.

The reactor’s design will be shippable via highways; it is intended to accelerate construction timelines and create more predictable and manageable construction costs.

Amazon and X-energy hope to bring more than 5 GW of SMRs online in the United States by 2039.

As part of the deal, X-energy and Amazon will develop a standardized deployment and financing model for future projects with infrastructure and utility partners.

“To fully realize the opportunities available through artificial intelligence, we must bring clean, safe and reliable electrons onto the grid with proven technologies that can scale and grow with demand,” X-energy CEO J. Clay Sell said in a news release. “We deeply appreciate our earliest funders and collaborators … we are now uniquely suited to deliver on this transformative vision for the future of energy and tech.”

Energy Northwest

Amazon will partner with Energy Northwest to fund efforts to develop the Xe-100 SMR and deploy it near the public power agency’s Columbia Generating nuclear power station in Washington.

The deal gives Amazon the right to purchase electricity from the first phase (four modules totaling 320 MW) and gives Energy Northwest the option to add up to eight more modules (640 MW).

Energy Northwest said as the owner and operator of the only nuclear facility in the Pacific Northwest, and as a developer of clean energy and storage resources, it is well-suited for this new partnership.

“We’ve been working for years to develop this project at the urging of our members, and have found that taking this first, bold step is difficult for utilities, especially those that provide electricity to ratepayers at the cost of production,” Energy Northwest’s Vice President for Energy Services and Development Greg Cullen said in a news release. “We applaud Amazon for being willing to use their financial strength, need for power and know-how to lead the way to a reliable, carbon-free power future for the region.”

Dominion

The memorandum of understanding between Amazon and Dominion Energy Virginia commits them to exploring commercial and financing structures for SMR development in Virginia.

In July, parent company Dominion Energy sought proposals from SMR developers to evaluate the feasibility of adding an SMR at the company’s North Anna nuclear generating station in Virginia.

An objective of the Amazon MOU is to mitigate potential cost and development risks for customers’ capital providers. Large nuclear reactors have proved extremely expensive to develop in the United States in recent decades, and while SMRs hold the promise of eventual cost reduction through standardization, they are still in development and early projects are expected to be expensive.

The SMRs in development now must still clear numerous technical and regulatory hurdles. And any future scenario in which scores or hundreds of new reactors with smaller safety zones dot the American landscape could be expected to prompt extensive debate and litigation.

But Dominion said SMRs could play a pivotal role in the energy mix in the 2030s. “This collaboration gives us a potential path to advance SMRs with minimal rate impacts for our residential customers and substantially reduced development risk,” CEO Robert Blue said in a news release.

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California Hits Milestones for Batteries, DR Grid Support

California’s battery energy storage capacity has hit 13,391 MW, an increase of 3,012 MW in just six months and a milestone that Gov. Gavin Newsom’s office called “a major victory on the state’s path to 100% clean energy.”

As the growth in battery capacity is accelerating, the new milestone is one-quarter of the way to the state’s projected need of 52 GW of battery storage capacity by 2045.

Industry experts cited the growth of battery storage as a key factor in the Western grid having an “uneventful” summer — despite enduring the hottest weather on record. (See Batteries, Energy Transfers Support ‘Uneventful’ Summer in West.)

Batteries are also key to capturing solar energy that’s produced during the day so it can be used when the sun isn’t shining, Newsom’s office said. Battery discharge to the grid increased from 6,000 MW this spring to more than 8,000 MW over the summer.

“These are the essential resources that we’ll continue needing more of as the climate crisis makes heat waves hotter and longer,” Newsom said in a statement.

According to a CAISO special report on battery storage, battery charging accounted for about 8.3% of load in the CAISO balancing area during peak solar hours in 2023.

“During these hours, batteries help reduce the need to curtail or export surplus solar energy at very low prices,” the report said.

Most of the state’s current battery storage capacity comes from 187 utility scale installations totaling 11,462 MW.

Residential battery storage adds 1,354 MW of capacity in 193,070 installations across the state, according to a California Energy Commission (CEC) dashboard. The remaining 576 MW of capacity is from 3,211 commercial installations.

Broken down by region, the 93501 and 92225 ZIP codes have the most battery storage capacity: 1,450 MW and 1,051 MW, respectively. Both areas are in the Southern California desert.

Grid Support Program

California’s battery storage milestone comes as the state is seeing growth in a program aimed at maintaining grid reliability during extreme weather events.

The CEC’s Demand Side Grid Support (DSGS) program pays participants to reduce electricity use or send energy to the grid to reduce the risk of rolling blackouts. The program runs from May through October.

Since its launch in August 2022, the DSGS program has grown to 265,000 participants and 515 MW of capacity, the CEC announced Oct. 15.

The program includes what the CEC describes as one of the largest storage virtual power plants in the world, with a capacity of more than 200 MW. The VPPs are a network of customer-owned battery storage systems — usually paired with solar — that send power to the grid.

In addition to storage VPPs, the program has two other ways to participate. Participants may provide non-combustion resources, such as traditional demand response. It’s also open to demand response aggregators participating in the CAISO market.

So far in 2024, the virtual power plant has been activated 16 times and demand response was activated once, “helping to avoid a grid crisis during four separate heat waves from July through the beginning of October,” the CEC said.

The DSGS program also played a role in the September 2022 heat wave, when it reduced electricity demand by 3,000 MWh during the 10-day event.

DSGS is part of the state’s Strategic Reliability Reserve, created in 2022 through Assembly Bill 205. The reserve is intended to expand the resources available to manage or reduce net-peak demand during extreme events.

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FERC Grills Grid Stakeholders on Reliability

Speaking to FERC’s annual Reliability Technical Conference on Oct. 16, NERC CEO Jim Robb told commissioners the challenges of ensuring reliability across the North American power grid are only growing. 

“We have a very simple math problem: the trend lines for electricity supply and demand are moving in the wrong direction to sustain reliability,” Robb said in his opening remarks. He went on to highlight a few of the emerging pressures on supply, including the replacement of conventional generation with renewable resources like wind and solar that rely on inverters to connect to the grid. 

“Replacement generation lacks the abundant reliability characteristics of the retiring resources,” he said. “And as we’ve seen over the past few years, the weather conditions the system operates under are increasingly severe, whether they’re long-duration, wide-area extreme cold or heat events, space-weather driving [geomagnetic disturbance] events … or tropical systems like the devastating hurricanes of Helene and Milton.” 

NERC CEO Jim Robb | FERC

However, despite the increasingly “turbulent” environment, Robb also emphasized that “the state of reliability remains a great story of progress,” with the severity and duration of outages declining and system restoration times shortening. 

Robb was part of the first panel of the day, along with representatives of a range of ERO stakeholders including ISO-NE, MISO, Duke Energy, the American Public Power Association and American Clean Power. The discussion touched on multiple reliability issues, with a large share of attention on generation retirements. 

Asked by FERC Chair Willie Phillips about the “record pace” of retirements and the wind and solar resources coming online to replace traditional generation, Carrie Zalewski of American Clean Power emphasized that the growth of renewable energy does not need to be seen as an inherent risk. Recalling the failure of natural gas generators in Texas during the winter storm of December 2022, she urged commissioners that “resource diversity is the linchpin of reliability.”  

FERC Chairman Willie Phillips | FERC

“No resource is immune to risks or weaknesses, whether it’s weather dependency, limited energy availability, correlated system outages … insufficient fuel supply or environmental limitations,” Zalewski said. “It’s dangerous to run a grid that focuses on one type of resource alone, and we … have all kinds of facts … out of Winter Storm Elliott [about] the over-reliance on a [single] resource.” 

In the second panel of the day, Phillips noted that NERC’s written comments before the conference called for “close, intense collaboration” between regulators and state governments to build a reliable electric system. NERC Chief Engineer Mark Lauby said the ERO has focused on building a shared vision of how the grid will function with the new resources coming online. 

“The partnership has got to be around getting to a point of understanding what is the design basis of this system of the future?” Lauby said. “We’ve been so very comfortable about” the one-day-in-10 years loss-of-load expectation, “and it’s really held [up] well. Very rarely did you see generation lower than demand. And we’re starting to see that now, as we integrate weather-related or weather-dependent resources, as we have an interconnected gas and electric system, and how they work together.” 

Andrew French, chair of the Kansas Corporation Commission, endorsed Lauby’s vision of collaboration, describing some of the ways his organization’s coordination with NERC and FERC have borne fruit. 

“I think the primary area where we have coordinated very well there is in things like setting accreditation policies and setting those ultimate resource adequacy requirements, things like planning reserve margins,” French said. “These are fuel-neutral policies, they are data-driven policies that tell us what an appropriate level of reliability might be and how we might value different resources based on the attributes they provide to the system, but it ultimately leaves to the state what resources they will implement to achieve those resource adequacy requirements.” 

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SCOTUS Upholds EPA Rule on Power Plant Emissions ― for Now

The Supreme Court on Oct. 16 turned down industry and state efforts to slap a stay on the U.S. Environmental Protection Agency’s new rules aimed at cutting carbon emissions at U.S. power plants burning fossil fuels. But the court left the door open for a second attempt pending a decision on the cases from the Court of Appeals for the D.C. Circuit. 

Under the final rule EPA released April 24, existing coal-fired power plants nationwide will have to either close by 2039 or use carbon capture and storage or other technologies to capture 90% of their emissions by 2032. New natural gas plants will have until 2035 to similarly cut their emissions through efficient design, carbon capture or a combination of both. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt.) 

The brief decision from Justice Brett Kavanaugh responded to a slate of eight cases against the EPA now before the D.C. Circuit, including two separate state challenges: one led by West Virginia, one led by Ohio. Suits also have been filed by the National Rural Electric Cooperative Association, the National Mining Association, NACCO Natural Resources Corp., the Midwest Ozone Group, Electric Generators for a Sensible Transition and the Edison Electric Institute. 

With Justice Neil Gorsuch concurring, Kavanaugh said that while the plaintiffs “have shown a strong likelihood of success on the merits as to at least some of their challenges” to the EPA rule, work on complying with the rule would not have to begin until June 2025. 

The plaintiffs “are unlikely to suffer irreparable harm before the Court of Appeals for the D.C. Circuit decides the merits,” Kavanaugh said. “Given that the D.C. Circuit is proceeding with dispatch, it should resolve the case it its current term.” 

Either the plaintiffs or EPA then could appeal to the Supreme Court, he said. 

The decision notes that Justice Clarence Thomas would have granted a stay, while Justice Samuel Alito “took no part in the consideration or decision of these applications.”  

The mixed decision got a quick reaction from Michelle Bloodworth, CEO of America’s Power, the coal industry’s trade association, who expressed disappointment that the court did not stay the rule, but also pointed to Kavanaugh’s belief that at least some of the state and industry arguments had merit.  

“We have long stated that … EPA’s carbon rule is an illegal overreach of the agency’s authority and would undermine the reliability of our nation’s electrical grid,” Bloodworth said. “By forcing the premature retirement of coal plants, the EPA would reduce needed sources of electricity at the same time electricity demand is exploding. Coal-based electricity is essential to ensuring the United States can develop and deploy artificial intelligence and not fall behind other nations like China.” 

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CEC Unlocks Nearly $43M in Funds for OSW Infrastructure Projects

The California Energy Commission is offering $43 million in grants to fund waterfront facility improvements to support the development and operation of floating offshore wind energy off the state’s coast.  

Eli Harland, energy policy expert and planner at CEC, gave an overview of the solicitation and how to apply during an Oct. 16 workshop. 

“The purpose of the GFO [grant funding opportunity] is to fund projects that will plan for offshore wind energy infrastructure improvements that can advance the capabilities of California waterfront facilities, ports or harbors to support the development and operation of floating offshore wind projects,” Harland said.  

The solicitation implements provisions of Assembly Bill 209, otherwise known as the Energy and Climate Change Budget bill, that requires the commission to implement a variety of clean energy programs, including the Offshore Wind Waterfront Facility Improvement Program. CEC will obtain the funds in June 2025 and make them available to selected grant applicants by June 2029.  

The Waterfront Facility Improvement Program was established in recognition that ports will be crucial to all aspects of the development and operation of floating offshore wind projects, including manufacture of parts such as blades, assembly and transport of turbines, and the operations and maintenance of final products. 

The solicitation required by AB 209 works in tandem with several other policy efforts aimed at advancing West Coast wind projects, including AB 525, which directed the CEC to develop a strategic plan outlining offshore wind development. The report was approved in July and includes a chapter covering efforts to improve ports and waterfront facilities.  

According to the plan, California’s existing port infrastructure is insufficient to support the offshore wind industry. Individual wind turbines are likely to be anywhere from 12 MW to 25 MW each and can only be transported over water, making staging and integration port sites where turbines are assembled essential.  

It also emphasizes that “no single port site in California can support all the needs of the offshore wind energy. Instead, multiple ports will be needed and … [upward] of 16 large and 10 small port sites [could be needed] to support offshore wind development over the next decade or more.”  

The CEC will fund offshore wind infrastructure improvements at waterfront facilities in two investment categories. Category 1 covers activities that support developing individual or regional retrofit concepts and investment plans. Category 2 includes activities that support final design, engineering, environmental studies and review, and construction of retrofits.  

Up to $6.75 million will be available for grants for Category 1, with projects eligible to receive a minimum of $750,000 and a maximum of $2 million. Up to $36 million is available in Category 2, with a project minimum of $9 million for each project and a maximum of $27 million. Eligible applicants include port authorities, operators and commissioners and California waterfront facilities and partners. Applicants in both categories must demonstrate site control.  

Funding, Site Control Concerns

While commenters during the call largely expressed approval of the program, some industry experts weren’t happy with the way the funding was split between categories.  

“We would like to see some additional funding allocated to Category 1 activities, in addition to increasing the overall award size for category one activities from the $2 million cap. That’s really not a lot of money,” said Artie Mandel, director of strategic initiatives at the Port of Los Angeles. “This program is a really unique opportunity for all of the California ports to support the statewide strategy and build out a California supply chain, and we really need to make sure that there’s enough resources there to support all of the ports in undergoing their planning efforts.”  

Other meeting participants echoed the request for increasing Category 1 funding.  

Jason Cotrell, founder and CEO of Sperra, a company that designs and manufactures offshore wind infrastructure, expressed concern about the Category 1 site control requirement.  

“The site control really puts the cart before the horse. I think one thing that we can agree on is that floating offshore wind is very early in terms of supply chain and technology developments, and it will consistently change over the next decade before it’s deployed in California,” Cotrell said. “We really think that site control in Category 1 is an unnecessary requirement that potentially restricts and will discourage participants from participating in Category 1.”  

The deadline to submit applications is Nov. 22, and the notice of proposed awards will be announced in December. The anticipated start time for the project agreements is April 2025.  

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New England Generators Protest ISO-NE Financial Assurance Changes

A recently filed proposal by ISO-NE to increase the collateral requirements for generators with capacity supply obligations (CSOs) has received strong pushback from the New England Power Generators Association (NEPGA), which argued to FERC on Oct. 9 that the proposal would violate the filed rate doctrine (ER24-3071).

The policy changes are intended to reduce risks to the market of generators defaulting on pay-for-performance changes, which are accrued if a generator can’t meet its obligations during a capacity scarcity event.

ISO-NE initiated the updates in the wake of PJM’s struggles with generator defaults following Winter Storm Elliott. (See PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

“There is a significant risk to the New England Markets caused by the fact that many [forward capacity market] participants do not have adequate corporate liquidity to satisfy their contractual, financial obligations related to the CSOs they were awarded,” ISO-NE said.

The RTO filed three updates to the policy last year, which were all accepted by FERC. However, the last set of changes have proven controversial and faced significant pushback in the NEPOOL stakeholder process. Neither ISO-NE’s proposal, nor two amendments proposed by NEPGA, passed the two-thirds approval threshold required for NEPOOL support. (See NEPOOL Participants Committee Votes to Support Hourly GIS Tracking.)

ISO-NE is proposing to introduce a new corporate liquidity assessment that would assign each participant a risk level to determine the collateral requirements. The RTO projects the changes would increase market-wide financial assurance costs by $72 million to $90 million for the 2025/2026 capacity commitment period (CCP).

In response, NEPGA protested the effective date of the proposal but not the underlying changes. The association argued that the changes should not apply to existing capacity commitments and should instead take effect for the 2028/2029 CCP. The auction for this CCP will likely take place in early 2028, depending on the results of ISO-NE’s ongoing capacity auction reform project.

“The [financial assurance policy] changes, if applied beginning on June 1, 2025, as ISO-NE requests, would alter the legal requirements associated with capacity supply obligations assumed years ago in violation of the filed rate doctrine,” NEPGA wrote.

The filed rate doctrine prohibits retroactive changes to rates that have been approved. NEPGA argued that ISO-NE’s proposal would add costs for generators with capacity commitments which were not accounted for in the auction bids.

“Denying the opportunity to reflect the full cost of providing capacity by post facto changing the rules governing the costs of holding a CSO, is not just wrong from a policy standpoint, but could contribute to accelerated retirements,” NEPGA said.

“With announced retirements in New England already outpacing new entry over the coming years, exacerbating this mismatch undermines confidence in the market and consequently risks reliability and the resource adequacy of the region,” the group added.

NEPGA requested that if FERC accepts the changes, it should either direct ISO-NE to adopt a June 1, 2028, effective date or schedule a hearing to determine an adequate effective date.

ISO-NE argued its proposal “does not constitute a retroactive rate change” because the changes would not affect auction prices or capacity supply obligations.

It added that the changes are prospective, not retroactive, because they would take effect in June 2025 and would “not alter prior credit reviews or supplant previously calculated inputs into the formula for the [forward capacity market] delivery financial assurance requirement.”