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November 30, 2024

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NextEra Adds Renewables, Eyes Nuclear Restart

NextEra Energy reported deals for 3 GW of new renewables with its third-quarter financials and said it has reached a framework agreement totaling 10.5 GW with two major corporations.

CEO John Ketchum also indicated the company is interested in recommissioning an Iowa nuclear reactor shut down after storm damage in 2020. Customers, particularly data centers, are showing keen interest in the emissions-free power it would supply, he said.

The third-quarter report issued Oct. 23 was another strong and confident assessment from one of the nation’s leading renewables developers and utility operators.

It was the second quarter in a row that NextEra Energy added 3 GW of new renewables and storage to its backlog. Ketchum said if NextEra achieves only midpoint expectations, it will more than double its renewable generation portfolio from 38 GW today to 81 GW by the end of 2027.

Data centers’ massive power needs are well known, Ketchum said, but the demand growth spreads far beyond them.

The two Fortune 50 firms that struck the 10.5 GW framework agreements with NextEra are not data center operators and are not even part of the technology sector. NextEra will not identify them at this stage but said they are building facilities that will need power, and they would prefer to meet those needs with low-carbon resources.

“Cost, capacity and speed are the three big issues that need to be addressed in meeting power demand, and as we have demonstrated in Florida, a mix of new renewables, storage and gas generation is the solution,” Ketchum said.

He added: “When it comes to economics, renewables and storage are the lowest-cost generation and capacity resource for customers in many parts of the U.S. We believe new wind is up to 60% cheaper and new solar up to 40% cheaper than new gas-powered generation, and that’s on a nearly firm basis when paired with a four-hour battery.”

Ketchum’s remarks on NextEra’s Duane Arnold nuclear plant in Iowa had a different tone than those just three months earlier. During the second-quarter earnings conference call in July, he said the company would consider a restart only under the right circumstances. (See NextEra Reports Continued Growth in Renewables.)

Now the company is “very interested.”

The problem with nuclear is that it essentially is a future-tense solution, Ketchum said. New technology will not come online at scale for at least a decade, he predicted, and existing technology is famously slow and expensive to build. So nuclear is not a short-term solution — unless one is referring to Duane Arnold and just a few other idled plants that could be brought back online. (Work is underway to recommission two others in Michigan and Pennsylvania.)

Duane Arnold is a half-century old, but it is a simpler boiling water design and can be refurbished in less time and at lower cost, Ketchum said.

The Duane Arnold Energy Center in Iowa is shown prior to shutdown in 2020. NextEra Energy is “very interested” in recommissioning the nuclear reactor. | NextEra Energy

Unlike other nuclear proponents, NextEra is not jumping on the bandwagon for small modular reactors (SMRs) just yet, and probably will not any time soon.

“We have been following SMRs for a very long time,” Ketchum said. “We actually advise a couple of Fortune 100 companies on SMRs today.”

NextEra’s assessment: Only a few of the nearly one dozen manufacturers trying to bring SMRs to market have the capitalization to make it happen in the next several years; each design will be an unproven first-of-a-kind technology that carries “a ton of risk”; they initially will be too expensive to compete with a mix of renewables, storage and gas; and an entire supply chain must be built to fuel them.

“That’s why we’re just not bullish on SMRs,” Ketchum told an analyst during the Oct. 23 conference call. “We think it’s kind of an end-of-the-next-decade alternative.”

NextEra Energy’s third quarter net income per share was up 50% on a GAAP basis from the same period in 2023 and up 9.6% on an adjusted basis. The company projects continued annual growth in earnings per share through 2027 and expects to increase its dividend by about 10% per year at least through 2026.

NextEra Energy’s third quarter results are based mainly on the performance of its subsidiaries Florida Power and Light, the nation’s largest utility by customer count, and NextEra Energy Resources, the world’s largest generator of wind and solar power.

NextEra Energy Partners, a separate business that shares corporate leadership with NextEra Energy, posted a net loss of $40 million for the third quarter of 2024, which compares with a net income of $53 million in the same quarter of 2023.

Chief Financial Officer Brian Bolster said NextEra Energy Partners will complete a review over the next three months but added that it has many potential avenues of growth, given the demand for electricity.

NextEra Energy’s stock closed 1.5% higher on a day of widespread losses across the major U.S. markets, while NextEra Energy Partners’ stock was down 16.3%.

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GE Vernova Gives Update on Offshore Wind Woes

GE Vernova reported that its onshore wind business had its best quarter in three years but that its performance was canceled out by problems in its offshore wind business. 

The company cut offshore jobs in the third quarter, and CEO Scott Strazik said the financials of the offshore wind industry will need to change substantially before the company takes new orders. 

GE Vernova also indicated its long history in the fossil-fuel generation sector will extend for years to come: Strazik said GE Vernova will boost its gas turbine production capacity 28 to 45% by 2026 and still expects little room for additional orders. 

For the first nine months of 2024, it has received orders for 78 gas turbines rated at a combined 14.1 GW. That’s 32% more units than in the same period of 2023 and 90% more capacity. 

“In addition to equipment demand growth, we are seeing services demand in our installed base grow meaningfully,” Strazik said during a conference call Oct. 23. “As customers aim to get more capacity and better performance out of their plants, we expect greater demand for upgrades driving gas services growth.” 

Of the three business segments, Power (gas, steam, nuclear and hydro) had the largest revenue and Electrification had the largest revenue growth. Wind was the problem child. 

GE 2.8-127 wind turbines are shown at the Sage Draw wind farm in Texas. | GE Vernova

The offshore wind industry has had financial and logistical problems for more than two years, particularly in the United States. 

GE Vernova’s latest struggles are more acute: A July 13 blade failure at the Vineyard Wind project in Massachusetts and the resulting delays will cost the company an estimated $700 million. Federal safety regulators halted installation of towers and nacelles until Aug. 10 and installation of blades until Oct. 22. 

Additional problems with blades made by a GE Vernova subsidiary have been reported at the Dogger Bank project off the east coast of Britain. 

“We have finalized root cause analysis and confirm the blade issue at Vineyard Wind was caused by a manufacturing deviation from our factory in Canada,” Strazik said. “We are proactively strengthening some of the blades, either back at the factory or in the field, to improve quality and readiness for their intended useful life.” 

The emphasis now is on improving execution as the company delivers on a $3 billion offshore wind backlog. 

“We do not foresee adding to this backlog without substantially different industry economics than what we see in the marketplace today,” Strazik said. 

A financial analyst asked about GE Vernova’s strategy with nuclear fission, which is getting renewed attention as a potential answer to the need to sharply increase power generation and the desire to sharply decrease carbon emissions from generation. 

GE Vernova is involved in the Ontario small modular reactor (SMR) project that is the first in North America, Strazik said, and it sees potential in SMRs — but not for a decade or so. The Ontario project is not expected to go online until 2029, and follow-up projects will be years behind, he said. 

“We’re really excited about what SMR can mean for us, but it’s not going to financially become a meaningful part of our income statement with revenue and growth until early into the next decade,” he added. 

A more immediate opportunity is enhancing the 65 U.S. nuclear reactors that bear the GE name, Strazik said. 

“We see at least 3 GW of incremental nuclear capacity we can add, with uprates of the existing installed base that we have, and another couple gigawatts that could get added from restarting plants that aren’t running today.” 

GE Vernova reported third-quarter 2024 adjusted EBITDA of $200 million on revenue of $8.9 billion and orders of $9.4 billion. This compares with $200 million, $8.3 billion and $8.2 billion in the third quarter of 2023. 

Its stock closed 1.25% higher in trading Oct. 23, a day when U.S. markets were broadly down. 

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Arizona G&T Cooperatives Announces Pursuit of EDAM Benefits Study

A group of Southwest electric cooperatives is planning a study that could motivate the Western Area Power Administration’s (WAPA) Desert Southwest (DSW) Region to join CAISO’s Extended Day-Ahead Market (EDAM).  

Arizona G&T Cooperatives (AzGT), a member-owned, nonprofit electric generation and transmission cooperative that accounts for 70% of WAPA’s DSW load, is looking for potential benefits if WAPA joined EDAM.  

“Today marks an important milestone for the Arizona G&T Cooperatives as we announce our interest in exploring CAISO’s EDAM to determine potential benefits for our customers across Arizona,” AzGT CEO Patrick Ledger said in a press release. “We look forward to continued engagement with CAISO to build on the benefits we have seen through participation in WEIM, and to support WAPA as it explores expanding its participation.”  

AzGT has not yet decided who will conduct the study.  

The announcement follows WAPA’s March decision to pull the DSW region out of the second phase of SPP’s Markets+ development after determining it would see few benefits from both SPP’s and CAISO’s day-ahead markets. (See WAPA DSW Cites Lack of Benefits in Markets + Withdrawal.)  

But WAPA expressed support for AzGT’s announcement.  

“We applaud this first step by AzGT in considering the benefits of joining CAISO’s day-ahead market program,” WAPA administrator and CEO Tracey LeBeau said in a separate press release. “WAPA remains focused on providing value to our customers, and our leadership and Desert Southwest operations teams support this evaluation of EDAM. As a transmission provider, we know WAPA’s transmission system throughout the Southwest and its connectivity across the region will be a crucial factor in determining the value of any day-ahead market construct for our DSW customers.”  

WAPA DSW has been a member of the Western Energy Imbalance Market since 2023. DSW operates the Western Area Lower Colorado balancing authority in Western Arizona and sells federal hydroelectric power and provides transmission service to nearly 70 cities, electric cooperatives, Native American tribes, government agencies and irrigation districts.  

AzGT and more than 20 cooperative members, public power utilities and electrical districts took the first step in the process in September by engaging with CAISO to review the potential benefits of joining EDAM.  

CAISO expressed enthusiasm for the announcement.  

“We are honored to provide real-time energy market services for a diverse set of western utility partners, and excited to learn that AzGT intends to explore further benefits from the extended day-ahead market,” CAISO CEO Elliot Mainzer said. “WAPA and its customers bring critical resources and connectivity for many in the West, and we look forward to continuing the mutually beneficial partnership.”  

Other entities engaged in EDAM are PacifiCorp and Portland General Electric, which executed implementation agreements and intend to join in 2026. Several other entities have indicated a leaning toward EDAM, including the Los Angeles Department of Water and Power, the Balancing Area of Northern California, Idaho Power, NV Energy and BHE Montana. 

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Customer Benefits Must Drive Market Decisions, NM Commissioner Says

SAN DIEGO — Utilities should put customer benefits first when deciding on which Western day-ahead electricity market to join, New Mexico Commissioner Gabriel Aguilera said Oct. 22. 

“I think there are also other things that matter — and governance is one of them —but from my perspective, the primary driver is those customer benefits,” Aguilera said during a panel discussion at the fall joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB).  

“We owe that to customers,” he said. 

Speaking with RTO Insider after the panel, Aguilera said those benefits should be gauged by improvements to “cost and reliability.” 

The New Mexico Public Regulation Commission (PRC) member’s comments come nearly two months after The Brattle Group released a study showing the state’s two major utilities, Public Service Co. of New Mexico (PNM) and El Paso Electric (EPE), would earn greater economic benefits from joining CAISO’s Extended Day-Ahead Market (EDAM) than SPP’s Markets+ even if neighboring Arizona’s three largest utilities — Arizona Public Service, Salt River Project and Tucson Electric — were to join Markets+. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.) 

The Brattle study shows, in that scenario, that PNM would reap $20.5 million in projected benefits by participating in EDAM versus $8 million in Markets+, while EPE would earn $19.1 million and $9.1 million, respectively. 

Aguilera answered in the affirmative when asked whether he thought the Brattle study provided the kind of insight needed to measure customer benefits. He acknowledged again the importance of independent governance for an electricity market, but he also expressed confidence in the ability of the West-Wide Governance Pathways Initiative to bring independent oversight to the EDAM and that an immediate solution to the governance issue shouldn’t be necessary for making a market decision. 

Aguilera declined to comment on whether the PRC will have final say over the decisions by New Mexico’s utilities. He also hesitated to provide a timeline for when the commission would release its “guidance document” regarding market decisions, saying only that he’d completed his contribution to that document. 

The PRC’s next open meeting is scheduled for Oct. 31. As of Oct. 22, the posted agenda for that meeting contained no mention of electricity market issues. 

The New Mexico utility decisions became increased objects of speculation in the Western day-ahead market competition after NV Energy in late May announced its intent to join the EDAM, three months after a Brattle study showed the Nevada utility stood to earn more than nine times the benefits in that market compared with Markets+. (See NV Energy Confirms Intent to Join CAISO’s EDAM.)  

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2 Huge Solar-plus-storage Projects Planned in California

Intersect Power is seeking approval for two 1.15-GW solar-plus-storage projects in California using a streamlined permitting process available through the California Energy Commission.

If built as planned, the projects individually would surpass in size the Edwards & Sanborn solar-plus-storage project that was completed in January in California’s Mojave Desert. That project’s 875 MW of solar capacity was the most of any facility in the United States, NASA reported in January. And its 3,287 MWh of storage made it the largest energy storage facility in the world.

The Perkins Renewable Energy Project, proposed by Intersect Power subsidiary IP Perkins LLC, would be a 1.15-GW solar facility in Imperial County. It also would include up to 1.15 GW of four-hour battery storage, or up to 4,600 MWh of storage.

The Darden Clean Energy Project would consist of a 1.15-GW solar facility and 1.15 GW of four-hour battery storage. Proposed by Intersect subsidiary IP Darden I LLC, the project would be built on about 9,500 acres in Fresno County in the state’s Central Valley region.

If completed, the two projects would put a sizable dent in California’s battery storage needs — projected to be 52 GW of storage capacity by 2045. The state announced recently it had hit a milestone of 13,391 MW of battery storage. (See California Hits Milestones for Batteries, DR Grid Support.)

Streamlined Approval Process

The Perkins and Darden proposals are seeking approval through the California Energy Commission’s opt-in certification process — a voluntary process intended to streamline permitting of renewable energy projects.

Under the opt-in process, the CEC becomes the lead agency for permitting and state environmental review. The CEC certificate is in lieu of any permit that normally would be required through the local land-use review process and most state permits.

The CEC has the authority to license thermal power plants of 50 MW or larger. Assembly Bill 205 of 2022 expanded the agency’s authority to include opt-in certification for renewable energy projects such as solar, onshore wind and energy storage systems.

The Perkins project, which will sit partially on federal land, also will receive federal permitting assistance through the FAST-41 program, officials announced Oct. 15. FAST-41 is an initiative to streamline permitting through a predictable and transparent process.

Unlocking Renewables

The Darden Renewable Energy Project was discussed Oct. 16 during an environmental scoping meeting hosted by the CEC. An Intersect Power representative said the project would be on retired agricultural land that is “highly disturbed” due to its past use.

And the project has the potential to unlock more solar development in the region. Development there has been slow due to a lack of interconnection opportunities, according to Intersect.

“The Darden project would create a vital new point of interconnection for future renewable energy generators in western Fresno County by building and transferring a new 500-kV switching station to PG&E,” the company said in a presentation.

The Perkins project also would create “a vital new point of interconnection for renewable energy” in the Imperial Valley for future projects as well as Perkins, according to the project application.

Although the Darden project previously included an 800-MW green hydrogen facility, that component was removed this month. Removal of the hydrogen facility reduces the project’s operational water demand from 1,039 acre-feet per year to 35.

Opt-in Timeline

Under the opt-in certification process, the CEC is required to post a draft environmental impact report within 150 days of the date the application is deemed complete, followed by 60 days for public comment. A final EIR is due within 270 days from the application completion date.

Other state agencies that retain permitting authority over the project, such as state water boards, must decide on the application by day 360.

The Darden and Perkins projects are two of six proposals under review under the CEC’s opt-in certification process.

The other opt-in projects are:

    • Compass Energy Storage Project: a 250-MW battery storage system in the city of San Juan Capistrano.
    • Fountain Wind Project: up to 48 wind turbines, each with a capacity of up to 7.2-MW, in Shasta County.
    • Potentia-Viridi Battery Energy Storage Project: a 400-MW battery storage system in eastern Alameda County providing up to 3,200 MWh of storage.
    • Soda Mountain Solar Project: up to 300 MW of solar and 300 MW of battery storage in San Bernardino County.
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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.