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November 24, 2024

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DOE Doubles Down on Advanced Nuclear with HALEU Contracts

With tech giants Google and Amazon turning to small modular reactors to power their megawatt-guzzling data centers, the U.S. Department of Energy is doubling down on its efforts to build out a domestic supply chain for the high-assay, low-enriched uranium (HALEU) these advanced reactors will need.  

In a series of recent announcements, DOE awarded 10 contracts covering two of the key stages of the nuclear fuel production cycle ― enrichment and deconversion ― and released its final environmental impact statement (EIS) aimed at accelerating the development of such facilities. 

The goal, according to the EIS, is to produce 290 metric tons — that’s 639,341 pounds — of HALEU over the next 10 years. Doing so by expanding existing enrichment and deconversion facilities could have the lowest level of environmental impacts, the EIS says. 

Announced Oct. 17, four of the DOE contracts will help to expand HALEU enrichment capacity, while the other six contracts, for deconversion, were announced Oct. 8. Each of these companies will be negotiating with DOE for 10-year contracts for a minimum amount of $2 million, with additional billions in funding available for enrichment and deconversion services.  

According to a DOE press release, the multiple awards will create “strong competition … allowing DOE to select the best fit for future work,” while building “a strong, reliable domestic nuclear fuel supply chain free of influence from adversarial foreign nations.” 

The U.S. has a well-established supply chain for the low-enriched uranium (LEU) used in the country’s existing fleet of 95 light-water reactors, including two new units at the Vogtle nuclear power plant in Georgia, which came online this year. 

Prior to Russia’s 2022 invasion of Ukraine, the U.S. was dependent on a single company in Russia for its supply of HALEU. Building out a domestic supply chain quickly became a bipartisan priority, and Congress passed a law prohibiting such uranium imports from Russia, which President Joe Biden signed in May.  

The war in Ukraine, coupled with the boom in electricity demand driven by data centers, has created a “muscular resurgence” of interest in nuclear, National Climate Advisor Ali Zaidi said in a DOE press release on the enrichment contracts.  

The four companies receiving the enrichment contracts are Louisiana Energy Services, Orano Federal Services, General Matter and American Centrifuge Operating (ACO). 

Orano was also chosen for a deconversion contract, and ACO is a subsidiary of Centrus, another deconversion awardee. The other four on this list are BWX Technologies, Framatome, GE Vernova and Westinghouse. 

Most of the companies have extensive experience as either developers of advanced reactors or suppliers of nuclear fuel and will be expanding existing facilities or, in the case of Orano, building new ones.  

ACO has already been producing small amounts of HALEU under a DOE-funded demonstration project, while Orano recently announced its plans for building a state-of-the-art enrichment facility on a site owned by DOE in Oak Ridge, Tenn.  

In a Centrus press release, CEO Amir Vexler said the enrichment contract will help the company expand its HALEU production capacity “so that we can restore a robust, American-owned uranium enrichment capability to power the future of nuclear energy.” 

ACO’s own domestic supply chain for the equipment it will need for enrichment includes 14 U.S. suppliers in 13 states, the company said.  

HALEU 101

Nuclear fuels are classified based on their concentrations of the “fissile” U-235 isotope used to trigger or maintain the nuclear reactions that produce energy. The concentration for LEU fuel is 3 to 5%, while for HALEU, it is 5 to 19.75%.  

A higher concentration of fissile material means reactors fueled with HALEU can be smaller, with smaller fuel cores, but still produce high levels of energy. The fuel cores also will last longer ― requiring less refueling ― and the reactors can operate more efficiently and produce less radioactive spent fuel to be stored.  

On the downside, the World Nuclear Association notes that the various parts of the HALEU fuel cycle will cost more and, in the U.S., will require separate licensing from the Nuclear Regulatory Commission (NRC). 

The NRC notes that it licensed the Centrus pilot program and has also licensed HALEU used by a Navy test reactor. The commission is also “actively reviewing license applications for fuel enrichment facilities and fuel fabrication facilities to produce and utilize HALEU.”

For example, Louisiana Energy Services is a subsidiary of Urenco, another nuclear fuel provider that has an enrichment facility in New Mexico. According to Urenco, the DOE contract will allow it to expand the New Mexico plant, but additional licensing from the NRC will be needed.  

The nuclear fuel cycle starts with mined uranium, which contains less than 1% of the fissile U-235 isotope and more than 99% of the heavier, nonfissile U-238 isotope. The enrichment process runs mined and milled uranium, called yellowcake, through a series of centrifuges, which spin out the heavier U-238 isotopes, automatically increasing the concentrations of U-235. 

Patrick White, research director of the Nuclear Innovation Alliance, noted that the extra processing to get from LEU concentrations of U-235 to the higher HALEU concentrations might require a relatively modest expansion of an existing facility. 

The more concentrated uranium produced by enrichment is smaller in size, making further concentration easier, he said.  

“The amount of enrichment facilities that you need for lower enrichment is going to be much greater than the amount of enrichment facilities you’re going to need to do higher enrichment because it’s a lot more work to do those initial steps of concentrating because you’re managing such a large volume of material,” White said. 

“Essentially, it takes much less work to go from 5 to 20% [enrichment] than it does to go from natural uranium to 5%,” he said. 

The enriched uranium, in the form of uranium hexafluoride (UF6), is then further processed, or deconverted, into one of two forms of uranium used in fuel cores, uranium oxide (UO2) or metallic uranium, in both cases via a chemical process.  

Deconversion facilities for UO2 already exist for LEU production, but White said, they are not “rated for and compatible with HALEU, so they will need to develop new infrastructure for HALEU deconversion.” 

TerraPower, which will use metallic uranium as fuel stock for its Natrium reactor, has partnered with Framatome to build a pilot plant for metallization, located at Framatome’s existing nuclear fuel plant in Richland, Wash. 

Economies of Scale

But will the U.S. need 290 MT of HALEU over the next 10 years? 

DOE’s Advanced Reactor Demonstration Program is funding the development of two advanced reactors ― TerraPower’s Natrium reactor and X-energy’s Xe-100 ― which will each need between 20 MT and 25 MT of HALEU per year, according to a department spokesperson. 

But beyond these demonstrations, the power demand from hyperscale data centers running artificial intelligence could provide the market needed for broad commercialization. 

On Oct. 14, Google and Kairos Power signed an agreement to develop a fleet of SMRs that will be able to provide 500 MW of power by 2035. Amazon’s investment in X-energy, announced Oct. 16, is aimed at putting 5 GW of new power on the grid by 2039. 

In addition, DOE is now accepting applications for $900 million in funding for the development of first-of-a-kind SMRs that will generate a string of orders. 

White sees the DOE contracts and other programs as a means to create economies of scale for HALEU production and provide a buffer for any disconnect of supply and demand. 

“How much material do we need to procure to actually make reasonable investments in production?” he asked. “One of the challenges with any of these systems, whether it’s the enrichment facilities or whether it’s the deconversion facilities, is that they really are subject to economies of scale. Producing one kilogram of HALEU costs a heck of a lot more on a per unit basis than producing one MT or 10 MT.” 

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ISO-NE Boosts Energy Adequacy Modeling Capabilities

ISO-NE is working to add to its probabilistic energy adequacy tool the capability to model preemptive actions to help conserve stored fuel prior to extreme winter weather events, ISO-NE representatives told the NEPOOL Reliability Committee (RC) on Oct. 22.  

The probabilistic modeling framework, or PEAT, initially was developed in coordination with the Electric Power Research Institute for several long-duration shortfall risk evaluations in 2023. It now is being incorporated into ISO-NE’s energy assessments and would be the backbone of the RTO’s proposed Regional Energy Shortfall Threshold (REST).  

REST is intended to quantify and determine an acceptable level of shortfall risk for the region, and eventually to inform the development of solutions when risks are identified. (See ISO-NE Details Proposal for Regional Energy Shortfall Threshold and NEPOOL Reliability/Transmission Committee Briefs: Aug. 13-14, 2024.) 

ISO-NE plans to run REST analyses seasonally to evaluate near-term shortfall risks and over longer periods to better understand risk trends in the region. 

The PEAT modeling is being improved to account for both preventive and corrective capacity deficiency actions, said Mike Knowland of ISO-NE. While the PEAT modeling already includes corrective actions, modeling preventive actions is a new addition.  

“Incorporating both preventive and corrective actions directly into PEAT allows for a robust quantitative estimate of the impacts of these actions on shortfall amounts,” Knowland said, adding that the modeling will be able to isolate the effect of preemptive actions.

The preemptive modeling is intended to help the RTO optimally dispatch resources prior to and during extended periods of resource adequacy risk, which ISO-NE expects to increase as intermittent renewables proliferate.  

Jinye Zhao of ISO-NE said the RTO also “has significantly enhanced PEAT to incorporate a multiday rolling-horizon economic dispatch for the 21-day energy assessment,” which looks out three days in advance on a rolling basis to optimize the dispatch of stored fuel resources. 

“Based on system conditions and fuel availability in the future days, the model can decide the appropriate time to trigger preventive actions and allocate the appropriate amount as needed to alleviate an anticipated energy shortfall,” Zhao said.  

In the new process, ISO-NE first will conduct its 21-day energy assessment using only modeling of corrective shortfall actions. Following the identification of an energy shortfall, the RTO will run the assessment again and include modeling of both preventive and corrective actions.   

Net import relief and net conservation relief, which will be incorporated in both the preemptive and corrective PEAT modeling, each will be “modeled as a block of up to 500 MW,” Zhao said. 

For the REST project, the modeling improvements could enable “a multimetric criteria which may include an additional metric that captures the duration of energy shortfall,” the RTO told stakeholders. 

ISO-NE is scheduled to present its initial proposal on the REST at the RC in November. It has emphasized the need for stakeholder input on the level of acceptable shortfall risk for the region.  

Determining an acceptable risk threshold will require more than just modeling expertise — it will pose political questions about how much the states are willing to pay for reliability insurance on the grid, and it could have a significant impact on regional programs supporting stored-fuel or dispatchable resources.  

“Following establishment of the REST, a subsequent effort will evaluate if adherence to the REST requires development of specific regional solutions,” Knowland noted. 

ISO-NE’s inventoried energy program (IEP), which compensates generators for keeping stored fuel on site during the winter, is set to expire after this winter. While the IEP was intended as a short-term solution, the RTO has not committed to either ending or continuing the program. 

Presenting the results of the RTO’s Economic Planning for the Clean Energy Transition report at the Planning Advisory Committee meeting in August, Patrick Boughan of ISO-NE emphasized that new market enhancements may be needed in the long-term to support dispatchable resources as renewables proliferate. (See ISO-NE: New Mechanisms May be Needed to Ensure Future Grid Reliability.) 

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Attentive Withdraws NY Offshore Wind Proposals

Barely three months after it was launched, New York’s fifth offshore wind solicitation has its first casualty: Attentive Energy has withdrawn the 1,275-MW proposal it submitted this summer.

Attentive said it remained committed to offshore wind and to helping the region meet the environmental and economic goals that offshore wind is expected to benefit.

New York’s fifth solicitation (NY5) has turned into a near-repeat of NY3. (See NY OSW: If at First You Don’t Succeed, Try, Try Again.)

Attentive, Community Offshore Wind and Vineyard Offshore’s Excelsior Wind were awarded contingent contracts in NY3, but NY3 was canceled in April when GE Vernova halted development of the turbine that was key to those contracts. (See NY Offshore Wind Plans Implode Again.)

NY5 opened in July. The same three developers submitted proposals again, along with a new entrant: Ørsted’s Long Island Wind.

Their deadline to submit offer pricing for the combined 25 proposals was Oct. 18. On that date, Attentive withdrew its four proposals.

The New York State Energy Research and Development Authority expects to notify the three remaining bidders of contingent awards by Nov. 8 but will not disclose details publicly until the contracts are finalized, likely in the first quarter of 2025.

Attentive is a joint venture of TotalEnergies, Rise Light & Power and Corio Generation.

In a prepared statement Oct. 21, it said: “Attentive Energy commends the state’s steadfast support of offshore wind and will continue to evaluate market conditions and future opportunities as they arise.”

Attentive’s lease area is closer to New Jersey than to New York. It won a contract in NJ3 and has submitted a bid in NJ4. (See NJ Awards Contracts for 3.7 GW of OSW Projects and 3 OSW Proposals Submitted to NJ.)

In other offshore wind news along the East Coast:

No Federal Grant for Maine Port

The state of Maine did not get the $456 million U.S. Department of Transportation grant it sought to help build a port to support the floating offshore wind industry.

The state hopes to grow into a leader in floating wind, which relies on still-expensive and immature technology, but which is poised for growth, as most offshore areas are too deep for fixed-bottom turbines.

The first-ever Gulf of Maine wind lease auction is scheduled Oct. 29.

DOT on Oct. 21 announced 44 grants totaling more than $4.2 billion through the Bipartisan Infrastructure law. Among them were 18 large port projects, but Maine’s was not among them.

In a prepared statement, MaineDOT Commissioner Bruce Van Note responded:

“We knew the grant program would be extremely competitive and that our application was ambitious. We believe the result is a reflection of the fiercely competitive nature of this program and that it does not reflect, or undermine, the widely recognized need for this port, the strong merit of Maine’s plan, or the vast economic and environmental benefits associated with port development.”

Van Note added that the state still is awaiting word on another, smaller grant that would help cover the cost of designing and permitting the port.

The port has other hurdles to clear: The state’s preferred site is an island that is a nature preserve. (See Maine Chooses Nature Preserve for Floating Wind Port.)

Preservationists have vowed to fight the plan, and they have a long track record of successfully beating back other development proposals.

Cables for Leading Light

Hellenic Cables announced it has reached an agreement to supply 132-kV inter-array cables for the Leading Light Wind proposal off the New Jersey coast.

The Garden State chose the Leading Light plan for a contract in January as part of NJ3.

At 2,400 MW, it is one of the largest wind farm plans yet announced off the U.S. coast, but developers have run into a problem they must solve before they can put Hellenic’s 65 kilometers of submarine cable to use: They need wind turbine generators with a combination of output and cost that will render the project economically viable.

The New Jersey Board of Public Utilities in September granted the developer more time to shop for turbines, lest the project become financially untenable under terms negotiated with the state — the same fate that doomed many of the now-canceled contracts along the Northeast coast. (See New Jersey BPU Approves Invenergy Offshore Wind Delay.)

Leading Light Wind is a rarity in the still-young U.S. offshore wind industry — it is led by two American companies, Invenergy and energyRE.

A commercial and industrial ecosystem to support offshore wind energy development is growing in the United States, but the sector still has a heavy European component at this stage.

To wit: Fulgor will manufacture the cables in Corinth, Greece. Fulgor is a subsidiary of Hellenic Cables, headquartered in Athens. Hellenic is a subsidiary of Cenergy Holdings, based in Brussels. Cenergy is a subsidiary of Viohalco, originally of Greece but now of Brussels.

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NY Project Alleviates Transmission Chokepoint

A major transmission project completed last year is already alleviating congestion on a historic chokepoint between upstate and downstate New York. On its blog, NYISO claims these upgrades, particularly to the Central East Interconnection, have paid dividends, reducing wind energy curtailments along the transmission corridor. 

NYISO claims these are the most significant upgrades in 30 years, boosting the transfer capability by about 1,000 MW.  

The Central East Interconnection slides through the hills of upstate New York along the relative smoothness of the Mohawk River. It forks, hooking into the rest of the grid at Schenectady and southward out of the river valley into New Scotland, a distant suburb of Albany. 

“Albany was functionally downstate,” said Marguerite Wells, executive director of the Alliance for Clean Energy New York (ACE NY). “Even though nobody in Albany thinks they live downstate and nobody in New York City thinks that Albany is anything other than upstate.” 

The bottleneck grew out of multiple historical trends, including the industrial development along the Mohawk River and the piecemeal creation of the power grid. The last time the corridor was updated was during the 1960s.  

“The issue was that this whole corridor … they had old, existing 230-kV transmission lines as well as some old 345-kV lines,” said Girish Behal, vice president of projects and business development for the New York Power Authority. “These were old existing transmission lines in old existing corridors that over a period of time got utilized to a point where you couldn’t put more energy on it.” 

Behal likened the upgrade to transforming a state road to an interstate highway, using the same right of way but upgrading the engineering specifications to allow more capacity.  

A collage of images from the New York Power Authority showing initial construction of the Central East Interconnection transmission upgrades. | NYPA

“It increased the Central East interface thermal transfer limit by 350 MW and the voltage transfer limit by 875 MW — a significant amount of capacity on those transmission lines to move those electrons around,” he said.  

About 93 miles of new lines were from new steel monopoles from Albany County to Oneida County, effectively quadrupling the power through the corridor.  

Curbing Wind Curtailment

NYISO says the upgrades mean this chokepoint on the grid has opened. Wind curtailments, once a norm, have plummeted. In December 2023 in the early evening, the interface flow for Central East surpassed 3,000 MW for the first time since 2005.  

Before the upgrade, the Capitol District was powered mostly by gas turbine plants. Much of the new power comes from renewable sources. According to NYISO, about 30% of the state’s installed wind capacity is in the Mohawk Valley.  

In 2023, NYISO asked wind generators to turn off to the tune of 162 GWh because the grid could not handle the energy. Roughly 80% of those requests came in the first four months of 2023, before the upgrades to Central East were completed. 

“It’s not incorrect for … NYISO to say that the Central East Interface improvement unbottles wind because it unbottles the whole state,” Wells said.  

Wells explained that this particular upgrade helps the entire state move power more effectively. Because upstate has more renewable energy than downstate, this effectively unbottled wind without touching the transmission infrastructure that hooks directly to wind generation.  

She said the next phase of upgrades to transmission would directly improve the lines that attach to wind generation, reducing curtailment even further.  

A big step in a massive process

This is far from the only upgrade that’s necessary for New York’s energy transition. At the ACE NY fall conference, Bart Franey, a vice president at National Grid, said some of the circuits in need of upgrades are over 100 years old.  

“They were designed to basically import 100 MW. Now they’re being asked to export 1,000,” Franey said in a panel on transmission infrastructure. “What we’ve come up with, supported by the state, is what we call the Upstate Upgrade. That’s 1,000 miles of rebuilding and modernizing upstate New York transmission.” 

Schuyler Matteson, the clean energy planning lead for the New York Department of Public Service, echoed these comments.  

“We live in a state that has some of the oldest electrical infrastructure in the world — not just the region, but in the world,” Matteson said. He ran through the preliminary results of the Coordinated Grid Planning Process, saying that to meet the state’s generation needs, the number of interconnections would have to triple. “Then we need to find ways to get those electrons to customers.”  

Later in the panel discussion, Franey and Matteson made it clear the 1,000 miles of new upgrades were just the beginning and not all of that would involve new transmission lines. They mentioned dynamic voltage support, grid-enhancing technologies and other avenues to make the best use of existing infrastructure and rights of ways.  

In an interview with RTO Insider, Behal also emphasized the Central East Interconnection upgrade was far from the last upgrade needed. New York, as the birthplace of the electrical grid, has many sections in need of refurbishment.  

“We have some transmission lines in upstate New York that were built in the 1940s,” Behal said. “It’s an antiquated system that now, with renewable generation coming in and trying to connect there’s a very significant need to upgrade those to a higher voltage or higher conductor size.” 

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SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024

LITTLE ROCK, Ark. — SPP says it is devoting significant resources to finally resolve Attachment Z2, a bone of contention among SPP stakeholders since 2016, by the end of this decade. 

General Counsel Paul Suskie told the Markets and Operations Policy Committee on Oct. 15 that it will take 24,000 hours of staff time and nearly $2 million to finally resettle Z2 refunds and resettlements following a pivot by FERC in ordering SPP to reverse its previously approved invoicing process. 

“Think through this: It took us from 2008 to 2016 to create the Z2 process. Now we have to undo it and recreate it and resettle going back to 2015,” Suskie told MOPC. “Luckily, we have a lot of knowledge and expertise and processes that will make that easier than it was to create it, but it is a significant undertaking that will probably take until 2029 to complete.” 

Under Attachment Z2, transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year. 

However, software problems delayed the attachment’s final implementation for eight years before 2016, during which the RTO did not invoice for the upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.) 

By then, SPP already back-billed market participants $138 million, not including interest, in 2016 and continued to use Z2 credits at the same time. It has applied $503 million in Z2 credits since 2015. 

“Because this is a process [where] each payment impacts other payments, what we’re doing today is in error because FERC reversed what they did from 2008 to 2015,” Suskie said, noting it will require recalculating each operating day since September 2015 to undo and refund the historical settlement. 

Several members filed Section 206 complaints against SPP over the Z2 resettlements. In 2022, the grid operator filed an update to its proposed refund plan from 2019. It urged FERC not to order refunds until all litigation is final. (See 8th Circuit Denies Review of FERC Orders on SPP Attachment Z2.) 

SPP’s Michael Desselle, who is retiring, is given a standing ovation by the Strategic Planning Committee. | © RTO Insider LLC

Suskie said the commission has been clear that the RTO is not to process refunds without a FERC order. Left in limbo are individual refunds totaling $147 million, plus $33.4 million in interest, due to transmission customers from 2008 to 2015.  

SPP is developing an interim software solution to calculate and distribute resettlements on activity from September 2015 until the production system can be used. It expects to have resettlements in sync with routine monthly settlements by 2029. That will require unwinding more than $20 billion in previous settlements to resettle Z2 activity; only 1 to 2% of all resettlements will be related to Z2, staff said.  

SPP emailed estimates of the refunds owed and/or that will be received after the MOPC meeting. The grid operator has created a Z2 website and is building an email distribution list to keep stakeholders updated.

SPP Modifies GI Backlog Process

SPP has modified its approach to clearing the backlog in its generator interconnection queue that dates back to 2018, revising the methodology to improve the accuracy of studies and restudies.  

“That just made more sense and provided more accurate results at the time than when we filed [at FERC] for the backlog plan,” SPP’s Jennifer Swierczek said. “We realized that doing that many clusters at once, customers might not have all the information they needed to proceed to the facility study and the [generator interconnection agreement],”  

The grid operator has added a planned restudy after each cluster’s first two definitive interconnection system impact studies (DISIS). A facility study and the execution of the GIA follow the restudy. 

The backlog initially included four clusters, from 2018 through 2021. SPP planned to keep the 2022 window open “so the line didn’t get longer behind us,” Swierczek said, but a record number of requests forced the RTO to shut down the cluster and add it to the backlog. The same thing happened in 2023 when its 129 requests exceeded those of the previous year’s 108. 

The 2024 cluster will be handled under the RTO’s normal process, but the grid operator has requested a waiver from FERC to extend the 2024 cluster study’s close from Oct. 31 to March 1, 2024.  

SPP began tackling the backlog in 2022 with the 2018 cluster. The queue contained 1,139 active requests for 221 GW of capacity at the time; it now has 395 active requests for 82 GW of capacity. The RTO has executed 48 new GIAs for 7.75 GW of capacity during the backlog work. 

Swierczek said the 2017 cluster, which is not part of the backlog, and the first 2018 study group have 91 projects between them, most of which she said are healthy. Large numbers of withdrawals in other clusters will have to be addressed in their next DISIS phase, with all backlog clusters ready for restudies by next summer, she said. 

Separately, members approved a proposed revision (RR651) to the GI manual allowing upgrades approved mid-DISIS study from other planning processes to be considered as potential mitigations for constraints identified during the ongoing study. SPP says constraint mitigations identified in the study process will be provided by solutions that have been approved and reduce the need for restudies due to withdrawals.

New MOPC Leadership, Members

The meeting was the last for ITC Holdings’ Alan Myers after two years as MOPC chair. 

“He’s done a great job over the last two years, and I’m looking forward to see what he has to close this out with,” said Lanny Nickell, Myers’ staff secretary. 

ITC Holdings’ Alan Myers (right) chairs his last MOPC meeting. | © RTO Insider LLC

“It has truly been my privilege to lead this group for two years,” Myers said after a round of applause, thanking members for their recognition. Then, true to his nature, he said, “Let’s dive in.” 

Omaha Public Power District’s Joe Lang will assume the chairmanship in January. 

MOPC added two new members: Ozarks Electric Cooperative’s Derrick Redfearn and Viridon Southwest’s Neeya Toleman. A Blackstone company, Viridon develops transmission projects in SPP.

Curing LREs’ RAR Deficiencies

Members easily endorsed three revision requests in separate votes.  

The Supply Adequacy Working Group’s proposal (RR632) giving load-responsible entities several more weeks to address deficiencies in meeting their resource adequacy requirement. LREs would have from March 15 to May 15 (an additional 30 days) to cure summer season deficiencies and from Sept. 15 to Nov. 15 (15 extra days) to resolve winter season deficiencies. 

SAWG’s vote to delay a revision request (RR642) until SPP completes its load-hosting capacity tool (LHCT) next year, giving applicable transmission owners three months to review the tool’s data. SAWG is working to implement the Holistic Integrated Tariff Teams’ directive to modify Attachment AQ of the tariff so SPP can proactively perform analysis to determine how much load can be accommodated at each node on the system without incremental investment (load hosting capacity assessment). 

The Market Working Group’s recommendation (RR638) to remove the exemption for day-ahead reliability unit commitment self-commits. It said the removal will mitigate market manipulation by resources intentionally switching between “self” status and “market” status to increase their make-whole payments and help the market reach a more economical solution with more accurate information. 

MOPC’s consent agenda included SPP’s annual violation relaxation limit analysis; the Project Cost Working Group’s in-service date delay report; the 2025 Integrated Transmission Planning assessment scope; and nine RRs that, if approved by the Board of Directors, would: 

    • RR545: Add language clarifying the objectives and initiation of a high-priority study and provide additional flexibility when developing the scope by removing the requirement to perform economic analysis and expanding on the current requirement to only conform to the ITP Planning Manual’s requirements. 
    • RR630: Add Tri-State Generation and Transmission’s various zones in the Western Interconnection to zones that will be a part of the SPP West Region. 
    • RR641: Clarify that self-committing resources contributing to the make-whole payment distribution volume is not only referring to energy storage resources but to all resource types. 
    • RR644: Remove expired or terminated grandfathered agreements from the list of GFAs and update any termination dates or any changes in buying or selling parties as part of the annual update. 
    • RR645: Update the ITP manual by considering aging infrastructure in transmission planning solutions by accounting for avoided or deferred reliability transmission facilities and aging infrastructure replacement. 
    • RR646: Update the ITP manual’s contingency screening criteria in the constraint assessment from 25% loading to 10% loading for 200-kV and above systems. 
    • RR647: Increase the cap under Schedule 1-A (Recoverable Costs) from $0.465/MWh to $0.515/MWh.  
    • RR648: Remove the regulation-up and regulation-down mileage factors from the applicable mitigated offer calculation and clarify terminology to match the supporting calculation for uncompensated costs for offline uncertainty. 
    • RR649: Add value to the network resource interconnection service (NRIS) product by creating an expedited process for designating new network and designated resources outside of the aggregate transmission service study process. It also would revise the generator interconnection study process for new NRIS requests, define deliverability areas and allow existing resources that meet eligibility requirements to use the expedited process.  
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Agencies Describe a Year of Iran Cyber Attacks

Cyber actors backed by Iran have been attacking critical infrastructure providers in the U.S. and other countries for more than a year, hitting sectors including energy, government and information technology, intelligence agencies from multiple countries said.

The warning about Iranian cyber activities came in an advisory released Oct. 16 by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and endorsed by the FBI, the National Security Agency and their counterparts in Canada and Australia. The agencies described tactics that the Iran-supported actors have used since October 2023, as observed in “FBI engagements with entities impacted by” the attacks.

Several approaches are documented in the report. Attackers gain initial access to target networks through brute force techniques such as password spraying, in which they use the same password against many different user accounts. If the user account has multi-factor authentication enabled, the attacker will bypass the safeguard by “push bombing” the account, hitting the user with multiple MFA notifications until they approve the request by accident or stop notifications.

Once they have entered the network, attackers often register MFA in their names to protect their access. The agencies observed two cases in which intruders took over an account with uncompleted MFA registration and set it to their own devices.

Discovering the attackers’ presence in a compromised system can be difficult because they make use of living off the land techniques to blend in with normal system activities. Cyber experts have seen these techniques used increasingly by actors linked to China — particularly the Volt Typhoon group — to infiltrate U.S. critical infrastructure organizations. (See China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn.)

The agencies recommended reviewing authentication logs for multiple failed login attempts to valid accounts. To detect the use of compromised credentials, agencies said entities could look for a single IP address being used for multiple accounts, or cases of “impossible travel” when a single account shows logins from multiple IP addresses with significant geographic distances.

Mitigations include disabling user accounts and system access for departed staff, continuously reviewing MFA settings to ensure all active internet-facing protocols are covered and ensuring password policies align with relevant guidelines from the National Institute of Standards and Technology. The advisory also recommended that software manufacturers incorporate security by design principles to protect against actors using compromised credentials.

CISA and the other agencies said it is likely the Iranian actors’ goal is “to obtain credentials and information … that can then be sold to enable access to cybercriminals.” They did not indicate that they believe these particular attackers aim to disrupt the critical infrastructure providers themselves.

However, Iran has a longstanding place in U.S. security experts’ minds. The country’s history of “aggressive cyber operations” earned it an entry in the Director of National Intelligence’s 2024 Annual Threat Assessment, which noted that “Iran is willing to target countries with stronger cyber capabilities than itself.”

While many of Iran’s cyber operations are aimed at Israel and other rivals in the Middle East, the DNI observed that it has targeted the U.S. in the past. In 2020, cyber actors linked with Iran tried to interfere in the U.S. presidential election by attempting to obtain voter information, sending threatening emails to voters and spreading disinformation. The director said they may attempt to do so again in 2024.

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BOEM Completes Assessment of Future NY Bight Wind Farms

Federal regulators have completed their first-ever regional environmental analysis of future offshore wind farms that have not yet been proposed. 

The Bureau of Ocean Energy Management’s programmatic environmental impact statement (PEIS) looks at six wind lease areas covering nearly a half-million acres in the New York Bight. 

Because all six areas were leased in the same 2022 auction, BOEM concluded that the leaseholders would be likely to submit their construction and operation plans on a similar time frame. Because all six are in close proximity off the New York-New Jersey coast, BOEM concluded the environmental considerations are likely to be very similar. 

Each construction and operation plan submitted for an individual wind farm still would require individual review and approval by BOEM, but the PEIS is intended to speed up those reviews by reducing redundancies. 

BOEM said this will help developers meet the offshore wind goals set by the Biden administration (30 GW by 2030), New York (9 GW by 2035) and New Jersey (11 GW by 2040).  

The six lease areas hold the potential for 5.6 GW to 7 GW of generation, BOEM said, using a conservative ratio of 3 MW per square kilometer. 

The PEIS assumes placement of 1,103 wind turbine generators with rotor tips stretching up to 1,312 feet above the ocean, 22 offshore substations, 44 export cables totaling 1,772 miles and 1,582 miles of inter-array cables across the six lease areas. 

The PEIS lists a series of predicted effects from these potential future offshore wind farms. Most are similar to the effects predicted in individual environmental impact statements BOEM has prepared for wind farms proposed off the Northeast coast, except that in this case, the impact could vary depending on whether it was one project or six being measured. 

And as with the other statements, the PEIS is imprecise in some of its predictions — a specific metric could be better, worse or unchanged after a forest of thousand-foot turbines is installed nearby. 

The impact on benthic resources, invertebrates and fish habitat could range from moderate beneficial to major detrimental, for example. The negative effects on commercial fisheries and the critically endangered North Atlantic right whale could be negligible, moderate or major. Major negative impact is expected on cultural resources, navigation and vessel traffic. The view from the shore might be minimally affected, and it might suffer a major negative impact. 

As with other projects, there is projected to be a major negative impact on scientific research and surveys, which of course would complicate efforts to quantify some of the other impacts as the wind farm is built and begins operating. 

BOEM released a draft of the PEIS in January. It said input received in the subsequent comment period was considered for inclusion in the final PEIS released Oct. 21. 

In a news release, BOEM Director Elizabeth Klein said: “We appreciate the feedback we have received, and we believe our regional approach will provide a solid baseline for future environmental reviews for any proposed offshore wind projects in the New York Bight.” 

There are other wind lease areas in the New York Bight, but these six were sold at the same auction in February 2022, at an early high point for the burgeoning U.S. offshore wind sector. 

The industry was racing forward with support from the federal government and multiple states and had not yet been slammed by the financial and logistic challenges that would, over the next two years, result in the cancellation of most of the offtake contracts for the early Northeast projects and a timeout for some. 

As such, the 2022 New York Bight auction drew $4.37 billion in bids — the nation’s highest-grossing offshore energy lease ever, including for fossil fuels. 

The winners were: 

    • Atlantic Shores Offshore Wind Bight, OCS-A 0541; 
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FERC Commissioner See Explains Her Regulatory Philosophy at EBA

WASHINGTON, D.C. — FERC Commissioner Lindsay See took office the day the Supreme Court issued its Loper Bright decision striking down the Chevron deference to federal agencies, she told the Energy Bar Association’s Mid-Year Energy Forum on Oct. 18. (See Supreme Court Ends Chevron Deference to Administrative Agencies.) 

Under Chevron, the courts had given deference to regulatory agencies’ areas of expertise when their governing statutes were unclear on a subject; the decision reclaimed that legislative interpreter role for the courts.  

“I would like to think that’s not causally related, that suddenly there was concern that a new federal regulator should not have that sort of discretion and deference to the decisions,” See joked. “But it’s certainly a sobering time to be a federal regulator. We have so many of these shifting legal frameworks and standards in place, and this is also, of course, kind of great transition in the industry as a whole.” 

See developed an expertise in energy by working as the solicitor general for West Virginia, which involved litigating many energy cases due to the state’s economy and its attorney general’s priorities. It has been four months since See transitioned from a state litigator to a federal regulator, she said. 

“I have been thinking an awful lot about the difference between [what] spurs FERC’s reactive and proactive authorities,” See said. 

The bulk of FERC’s work is reactive — it must respond to filings by the industry it regulates, whether changing a market rule, setting rates or siting gas infrastructure. The proactive side comes when FERC issues a broader rulemaking that can change how the industry it oversees operates. 

“At least from an outsider’s perspective, when I think about agency work, I think I immediately jump to that second one, to the more proactive policy-making role,” See said. “And that’s not actually the heart of what we do at FERC. So I have been spending a lot of time these first few months really trying to get that first part, to do it well and to really understand that piece.” 

While she is in a different role at FERC, the reactive piece is like the legal work she was doing as solicitor general: It often involves multiple parties with different views arguing about the evidence in a docket, and it builds up precedent that future cases are expected to follow. 

The reactive role of FERC is limited because it cannot control what comes before and it also cannot separate out parts of a filing that it likes, approving those and denying others, See said. 

“I think especially in a time of dynamic change, sometimes incremental change isn’t enough, and there is a need for a more holistic solution that’s able to work more broadly,” See said. 

That is where FERC’s more proactive, rulemaking authority comes into play, and See said she has been thinking about it, noting that it differs greatly from her previous role as a state litigator. 

“I think there’s a lot of wisdom as well in making sure that the cost of that change is actually worth the benefit, and not just acting for the sake of acting,” See said. “Because taking a lot of time to study and think, and then if the conclusion at the end is actually it’s better for X, Y, Z reasons to stay where we are that can look like not actually doing our job.” 

Often change is worth the cost, she said, but that is a test she plans to apply to that proactive role in her new job. Another key to the proactive role is getting a wide range of detailed comments on any potential rule changes. 

“I have a real respect for that process because of the different perspectives and voices that can inform those decisions, because I want to make sure that we’re thinking as best we can,” See said. “What are some of the unintended consequences [regarding] a shift in one direction or another? How is that going to play out on the ground?” 

Being outside the contested case model seeing how a final decision will actually impact the real world is more difficult, but the more commenters that file the easier it is for regulators to figure out what will happen. 

“I think that having sort of a partnership model of listening to different voices and perspectives is what can make the sort of proactive role, that has such a critical and important space at the time we are now, can make that really effective,” See said. 

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PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report

The PJM Independent Market Monitor released the second iteration of its report on the 2025/26 Base Residual Auction, digging deeper into the impact of excluding reliability-must-run (RMR) resources from the capacity market.

The report ran a sensitivity modeling the Brandon Shores and H.A. Wagner generators as offering capacity into PJM’s supply stack, along with including capacity offers from all intermittent and storage resources categorically exempt from the capacity must-offer requirement.

The report found that combining the two led to a 53.9% increase in total capacity costs, amounting to about $5.14 billion. The two generators, owned by Talen Energy, were not required to offer into the 2025/26 auction as they will be operating on an RMR contract. (See PJM Requests 2nd Talen Generator Delay Retirement.)

The second sensitivity analyzed the effect of limiting combustion turbines and combined cycle generators to their summer ratings when PJM’s risk modeling is concentrating risk in the winter, paired with modeling the expected output of the two RMR generators. The analysis estimated that the two led to a 77.6% increase in capacity costs, or about $6.42 billion.

Combining the three components — excluding the two RMR units, and categorically exempt resources from the capacity market and capping gas generation at summer ratings — corresponded with auction prices being 108.1% higher, or a $7.63 billion increase.

The Monitor argued that exempting resource classes from participating in the capacity market and not modeling RMR units allows generation owners to limit access to transmission that could be used by other resources to deliver capacity and create significant differences in the supply stack year-to-year. It argued that the risk of an intermittent capacity resource being subject to capacity performance (CP) penalties for being offline during an emergency at a time when it could not respond could be countered by accounting for availability when assessing performance.

“The inclusion of a must-offer obligation for categorically exempt intermittent and capacity storage resources should be coupled with the removal of (performance assessment interval) penalty liability for such resources when it is not physically possible to perform,” the Monitor wrote. “The capacity market has included balanced must-buy and must-sell obligations from its inception. The current rules can and should be changed to restore that balance.”

During the Organization of PJM States Inc. (OPSI) annual meeting Oct. 21, Monitor Joe Bowring said capacity interconnection rights (CIRs) are a scarce resource that control access to the grid for generators. He argued that those holding CIRs should be required to exercise them.

PJM Executive Vice President of Market Services and Strategy Stu Bresler responded that it would not make sense to count on resources that cannot perform when there’s an auction with an annual commitment to perform. Exempting intermittents from the CP construct would be trading one set of exemptions for another, he said. Instead, PJM is committed in the long term to designing a more granular, seasonal capacity market structure.

The Monitor’s report also recommended expanding the granularity of PJM’s effective load carrying capability (ELCC) accreditation to include hourly data, so that unit-specific accreditation can be implemented, replacing class accreditation with a system of paying resources to be available on an hourly basis, and untying accreditation and summer ratings to allow winter CIRs to determine capability when risk is concentrated in the winter.

“The need for the energy from capacity is not limited to one peak hour or five peak hours. Customers require energy from capacity resources all 8,760 hours per year,” the Monitor wrote. “Rather than develop a complicated seasonal capacity market based on an arbitrary definition of seasons, the hourly value of the energy from capacity should be explicitly recognized in the capacity market.”

The total impact the changes PJM made on the auction led prices to be around double what they would be based on supply and demand fundamentals alone, Bowring said.

PJM Defends Capacity Market Design in Response to Part A of IMM Report

In its Oct. 11 response to the initial portion of the Monitor’s report, PJM argued that while the underlying analysis in the report appeared to be largely correct, the Monitor drew incorrect conclusions and omitted necessary context in its recommendations.

“PJM also does not take exception to the results of the simulations the IMM conducted as they are summarized in the report. They are directionally consistent with those that would be expected given the inputs used,” PJM wrote. “However, the IMM presents an incomplete set of sensitivities, provides insufficient context, and draws several conclusions that either lack support or are incorrect.”

The Monitor’s analysis, released Sept. 20, modeled four sensitivities looking at the impacts of PJM’s marginal ELCC accreditation methodology, exempting generators operating on RMR agreements from being required to offer into the auction, capping accreditation at resources’ summer ratings, and not subjecting intermittent and storage resources to the must-offer requirement.

The Monitor wrote that shifting generation accreditation from equivalent demand forced outage rate (EFORd) to marginal ELCC led to a 49.1% increase in total capacity costs, a finding PJM said conflates the changes made to accreditation and risk modeling. PJM said its revised risk modeling approach accounted for the bulk of the increased capacity costs associated with a market redesign approved by FERC in January 2024 following the Critical Issue Fast Path (CIFP) process conducted last year. (See FERC Approves 1st PJM Proposal out of CIFP.)

“The IMM does not estimate sensitivities capable of differentiating the impacts of these distinct market rule changes, but nevertheless attributes the impact to ‘PJM’s ELCC approach’ and ‘the ELCC availability metric,’” PJM wrote.

PJM went on to defend the marginal ELCC approach, stating that the probabilistic modeling at its core is becoming industry standard, with variants approved by FERC for implementation in MISO and NYISO, with ISO-NE considering similar changes. It argued the EFORd approach of using average availability to determine accreditation predominantly incentivizes performance throughout the year without sufficient focus on high-risk periods.

“Under the tight supply-demand conditions that materialized for the 2025/26 BRA, even relatively small impacts to the supply-demand balance can have outsized impacts on clearing prices because of the inelasticity of both supply and demand,” PJM wrote. “PJM believes that the nearly 2.7 GW impact of the enhanced risk modeling and concordant accreditation changes were appropriate and necessary to reflect emerging patterns of risk and lower-than-expected generator performance during such risk events.”

While the Monitor argued that PJM’s practice of modeling the expected output of RMR units when determining capacity transfer between zones is inconsistent with not including those resources in the supply stack, PJM stated that it views the issue as secondary to recognizing the disparities between capacity resource obligations and RMR agreements. Those contracts require units to operate during limited operational events and carry different obligations from capacity that are incomparable to capacity obligations, PJM said.

The response said more analysis is needed to determine the impact of using winter ratings for gas resources. Adding capacity to high-risk winter hours could shift ELCC weighting toward the summer, where high loads are a greater driver than forced outage rates. That could have the effect of pushing the reliability requirement higher.

PJM said the Monitor’s allegation that intermittent resources could be engaged in market manipulation by withholding their capacity is unsupported and misses valid reasons generation owners may not exercise the must-offer exception.

“The report fails to consider legitimate reasons why exempt resources may not have been offered into the capacity market. … Specifically, PJM believes that the IMM must assess the portfolio profitability impacts of the purported ‘withholding’ in order to determine whether the action could plausibly be connected to the exertion of market power. Additionally, the IMM should request information from market sellers in cases where the IMM suspects exercise of market power to consider whether there were other factors that explain the market sellers’ decisions,” PJM wrote.

PJM said the Monitor had not included an additional sensitivity the RTO had required be included in the report: the cumulative impact four recommendations the Monitor had made in its report on the 2024/25 BRA would have had if implemented in the 2025/26 auction. Those recommendations were establishing a sharper variable resource rate (VRR) curve, extending the must-offer requirement to intermittent resources, and excluding capacity offers from demand response (DR) and external resources.

Excluding DR from the auction would have reduced the excess unforced capacity (UCAP) by 8,769 MW, while doing so for external generation would have removed an additional 1,410 MW of excess UCAP. Combining the two would have left the RTO 6,983 MW short of the reliability requirement, pushing the clearing price to the $375.91/MW-day cap and resulting in a total capacity cost 42% higher than the actual results.

PJM said that gap would not have been made up for by other recommendations the Monitor made to increase available supply, such as requiring intermittent and storage resources to offer. That would have added 2,800 MW of available capacity, leaving a shortfall of 4,183 MW.

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Stakeholders Divided on PJM Proposal to Expedite High-capacity Generation

Stakeholders reacted sharply to additional detail presented on PJM’s straw proposal to create a one-off expedited application window for high-capacity-factor generation interconnection requests. (See PJM Proposes Expedited Interconnection Studies for High-capacity Factor Generation.) 

The proposal would allow a limited number of projects to be added to the initial clusters of Transitional Cycle 2 (TC2) to meet growing resource adequacy concerns staff have identified in the 2029/30 delivery year. The cycle currently includes only projects submitted between October 2020 and September 2021. More details on PJM’s proposal will be presented at the Oct. 30 Markets and Reliability Committee meeting. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

These approaches to determining eligibility were presented: allowing only projects with an effective load carrying capability (ELCC) class rating of 45% or higher or a formula with weighted factors such as ELCC rating; whether a project is an uprate or greenfield; expected commercial operation date; MW output and permitting required. 

The options would limit the number of projects being expedited to 100, which Director of Interconnection Planning Donnie Bielak said is the approximate number of projects staff believe can be analyzed without significant disruption to the milestones of other projects in the queue. If more than 100 projects are submitted, PJM would prioritize them on the amount of accredited capacity they could deliver. 

The 45% ELCC rating approach would categorically prohibit the participation of onshore wind, intermittent hydroelectric, and fixed and tracking solar, as well as projects being built as part of a state agreement approach (SAA) project. The in-service date would need to be June 1, 2029, or earlier. 

Speaking during the Organization of PJM States Inc. (OPSI) annual meeting Oct. 21, Ohio Lt. Gov. Jon Husted (R) said state leaders had met with PJM and requested the RTO create an expedited process for interconnecting resources that could be available any time of day. 

“Thank you and let’s go, that’s how we feel about it. We appreciate PJM’s responsiveness to our request,” Husted said. 

Speaking at OPSI, PJM’s Executive Vice President of Market Services and Strategy Stu Bresler said the initiative is meant to ensure that capacity market price signals can be acted on by generation developers. He said there are investors who want to act on high price signals sent in the 2025/26 Base Residual Auction but can’t do so while PJM progresses through its transitional approach to studying interconnection requests. 

PJM CEO Manu Asthana echoed that sentiment, saying load growth is accelerating at the same time generation deactivations are outpacing new entry. The Reliability Resource Initiative (RRI) would allow resources to respond to market signals quickly enough to address reliability concerns. 

“I think it’s important to create an onramp for additional resources that want to participate and provide that reliability,” he said. 

Several stakeholders at the Oct. 18 PC meeting said the proposal would amount to queue jumping, allowing preferred categories of generation to skip a line of mostly renewable resources that has spanned years. 

The projected reliability gap also was called into question, with stakeholders arguing that the markets are functioning to procure sufficient capacity and ancillary services. More data was requested around load forecasting and operational needs PJM expects. 

E-Cubed Policy Associates President Paul Sotkiewicz said PJM has not articulated a need to disrupt the rules generation owners have relied on to bring their units to those markets. 

“There’s nothing, absolutely nothing that tells me that we have to move quickly at this point,” he said. 

PJM Senior Director of Market Design and Economics Becky Caroll said the RTO’s Energy Transition in a series of PJM reports have documented the resource adequacy needs and the reliability services that intermittent resources in the interconnection queue are not expected to provide. 

On the other hand, stakeholders said it could create a pathway for adding storage to existing resources or unlock potential for existing generation to make upgrades to increase total capacity. 

Bielak said the proposal is one of three avenues PJM is investigating for addressing its reliability concerns, pointing to rule changes on capacity interconnection rights (CIRs) transfers to allow deactivating generation to be more easily replaced with new resources. The Planning Committee endorsed one of three proposals during its Oct. 8 meeting. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.) 

PJM also is open to re-evaluating its surplus interconnection service (SIS) rules, which allow new resources to be co-located with existing generation so long as there are no material adverse impacts and the combined output does not exceed the original resource’s CIRs.