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November 6, 2024

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ISO-NE Planning Advisory Committee Briefs: Oct. 23, 2024

NESCOE Seeks Feedback on LTTP Solicitation Structure

The New England States Committee on Electricity (NESCOE) remains “open to various ways to structure the scope” of the first transmission solicitation of the new longer-term transmission planning (LTTP) process, NESCOE’s Sheila Keane said Oct. 23.

NESCOE recently announced the states’ intention to focus the first LTTP solicitation on increasing the region’s north-south transmission capacity, with a particular focus on unlocking renewables in northern Maine. (See New England States Seeking Increase of North-South Tx Capacity.)

Keane asked for stakeholder feedback on how to structure the solicitation, adding that the states are trying to balance the need for strong minimum requirements for proposals while also leaving enough room for a wide range of potential solutions.

Northern Maine is not currently connected to the ISO-NE grid, but Maine is planning solicitations for renewable generation and associated transmission in this part of the state. (See Long Road Still Ahead for Aroostook Transmission Project.)

Phil Bartlett, chairman of the Maine Public Utilities Commission, said the state’s request for proposals (RFP) will be “at least somewhat dependent” on the LTTP solicitation.

“As we’re thinking about our northern Maine procurement, we are watching this very closely,” Bartlett said, adding that he is “hopeful that this process will provide some of those downstream upgrades that increase the likelihood of [a state-selected] project.”

However, there remains a long road ahead before any project is selected through the LTTP process. ISO-NE indicated that it expects to issue an RFP around March, followed by an approximately six-month application window and up to a year for ISO-NE to evaluate and develop a cost-benefit analysis for all the proposals.

Keane stressed that there is a lot of work to be done before ISO-NE can issue an RFP and said NESCOE is planning to continue discussions about the RFP with stakeholders at the PAC in the coming months.

Asset Condition Projects and Updates

Dave Burnham of Eversource Energy, representing the six major New England transmission owners (NETOs), provided an update on the asset condition project process guide, which the NETOs are developing in response to concerns from the states about a lack of oversight and transparency in the development and selection of projects.

He said the NETOs now require transmission owners to consider a “base alternative” representing the “minimum solution which addresses the identified asset condition problem.”

Additional changes to the process guide include standardized grading categories for asset condition evaluations and more transparency into how the decisions are made, Burnham said.

Eversource also provided an update on its proposal to rebuild the X-178 transmission line in New Hampshire, which cuts through the White Mountain National Forest. The project has proven to be particularly controversial, receiving pushback from NESCOE and the New Hampshire Office of the Consumer Advocate, and is the subject of a lawsuit from two local property owners.

The company previously told the PAC a full rebuild of the line would be the most cost effective way to address degradation on its wood poles, while NESCOE has expressed concern that the company has not adequately justified the project, threatening action with FERC. (See New England States Raise Alarm on Eversource Asset Condition Project.)

The states ultimately have little oversight over asset condition projects – the transmission owners are responsible for assessing the condition of their lines, determining whether upgrades are needed and selecting the most cost-effective solution. The transmission owners’ spending on the lines is FERC jurisdictional under the cost-of-service model.

As the costs associated with maintaining the region’s aging grid have accelerated in recent years, this process has drawn increased scrutiny into whether the transmission owners are doing enough to minimize the price of these upgrades.

Chris Soderman of Eversource said the cost projection of the full X-178 rebuild has decreased from $384.6 million to $360.6 million since the company presented the project in June “based on bids received.”

Soderman stressed that upgrading the line in a more piecemeal fashion would ultimately increase costs for ratepayers, with the estimated price tag ranging from $467 million to $614.1 million.

Kris Pastoriza, a property owner who has sued to stop the project, said Eversource’s proposed construction methods and overly impactful and “unethical.” Pastoriza argued the photo evidence of the pole degradation provided by the company is unconvincing and called on the company to release its pole inspection reports.

Meanwhile, some stakeholders, including a representative of Wagner Forest Management and Abigail Krich of Boreas Renewables, expressed support for Eversource’s proposal to address all the asset condition needs at one time, instead of addressing the needs through multiple project phases that could cause repeated disturbances.

Representatives of the Vermont Electric Power Company (VELCO) and National Grid also presented asset condition projects to the PAC:

    • National Grid is proposing to replace all structures, reconductors and install optical ground wire (OPGW) on a line in eastern Massachusetts, with a projected cost of about $74 million.
    • The company is also proposing to spend about $9 million to refurbish a substation in Worcester, Mass.

    • VELCO outlined a project to replace 41 structures on a line in northern Vermont, with a total estimated cost of about $6 million.

Boston 2033 Solutions Study

Andrew Kniska updated the PAC on the status of the Boston 2033 Solutions Study, which aims to address issues identified in the Boston 2033 Needs Assessment, published earlier in 2024.

While the needs assessment initially found several time-sensitive overload issues, a combination of modeling error corrections and new asset condition projects have eliminated all peak load time-sensitive needs, Kniska said.

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DOE Challenge Sends New Cold Climate Heat Pumps to Market

The U.S. Department of Energy is not deterred by a slump in heat pump sales in the U.S. market. 

Winter is coming. While heat pumps sales are down, they still outstrip sales of gas furnaces. And DOE has a new generation of cold weather heat pumps field-tested and ready for market to keep homes warm and comfortable, even in subfreezing weather. 

The eight companies taking part in DOE’s Residential Cold Climate Heat Pump (CCHP) Challenge have completed rigorous laboratory and field testing on their new models, which can keep a home warm and comfortable at 5 degrees Fahrenheit (-15 degrees Celsius) or even lower, according to an Oct. 23 press release. (See DOE Partners with HVAC Industry on Cold Climate Heat Pumps.) 

One of the eight, Carrier, started manufacturing the CCHP it developed for the challenge in September and expects to start shipping to its distributors in December, said Michael Carter, associate director of outdoor product management. 

The company has a full range of CCHPs on its website, but Carter said the standards required for the DOE challenge made the company stretch. While many CCHPs lose some heating capacity as temperatures fall, operating at 40% to 70% at 5 degrees F, DOE wanted 100% capacity at that temperature, he said. 

To hit that target, the company fine-tuned its systems so the indoor and outdoor components of the heat pump “communicate seamlessly,” Carter said in a phone interview with NetZero Insider. Larger coils also were a key change, he said. “[The] more coil, the more heat you’re able to generate or trap from the outdoor system and then compress more [efficiently].” 

Both Carrier and Lennox International, another challenge participant, stressed the role of variable speed components. “Variable speed drive technology optimizes compressor and fan speed to provide the demanded capacity at any given temperature with optimized efficiency,” Ajay Iyengar, vice president of advanced technology, said in an email.  

Lennox also expects to bring its new model to market in the coming months, Iyengar said. 

The other companies participating in the challenge included Bosch, Daikin, Johnson Controls, Midea, Rheem and Trane Technologies.  

Heat pumps are seen as a core technology for cutting greenhouse gas emissions from the U.S. building stock, where space and water heating and cooling account for 40% of the country’s primary energy use, according to a DOE fact sheet. 

Ram Narayanamurthy, deputy director of DOE’s Building Technologies Office, said when the department launched the challenge in 2021, the initial goal was to get as many of the major companies in the HVAC industry as possible onboard to improve the performance of residential cold climate heat pumps. 

While the companies did not work together, “they all came out with products that they can get into the market,” Narayanamurthy said. 

Next up, DOE is going to tackle cold climate heat pumps installed on the rooftops of commercial buildings, again drawing in leading companies, including AAON, Addison, Carrier, Daikin, Johnson Controls, Lennox, LG, Rheem and Trane. 

Working with DOE and the National Laboratories, the companies will create prototypes to be tested in the lab for performance and durability, followed by field testing on rooftops owned by major corporations — like Amazon, General Motors and Ikea — according to the DOE press release. Dubbed the Commercial Building Heat Pump Accelerator, the initiative is slated to run through 2027. 

Happy with Heat Pumps

In lab testing, all the new heat pumps were capable of full operation at 5 degrees F (-15 degrees Celsius), with some operating at temperatures as low as -15 degrees F (-26 degrees C), DOE says.  

The field tests put 23 prototypes from the companies at 23 sites in northern states and Canada, according to Vrushali Mendon, a senior mechanical engineer at the Pacific Northwest National Laboratory and principal investigator for the tests. 

Surveys with the homeowners participating in the test found that most were satisfied with the heat pumps, Mendon said. “They did not [have] any issues with either the heat pump not being able to provide enough heat or any kind of comfort issues, any kind of noise issues.” 

For Carrier, the field tests provided critical feedback on potential problems with installing their new model in homes with older duct systems, Carter said. Older homes “may not have been built for these types of systems. … One of the lessons learned from that is that we are really targeting this product more toward the residential new construction market.” 

DOE’s push on heat pumps comes as U.S. sales have hit a slump, falling about 16% in 2023, although gaining back some ground this year, with sales up about 5.4%, according to August figures from the Air Conditioning, Heating and Refrigeration Institute.  

Various analysts have pointed to high electricity prices and high interest rates as two factors that have cooled the market, along with a lack of contractors who are well trained in installing and maintaining CCHPs.  

But Carter says Carrier has not seen any drop in sales, and Narayanamurthy says the 2023 drop could be part of normal sales cycles.  

“This is an industry where sales can go up and down,” he said. “It’s an industry that’s very driven by consumer sentiment.” 

The figures to look at are heat pump sales versus gas furnaces, and heat pumps have led the market for the past three years, he said. “I think that’s really what we are looking at, and … we expect that trend to continue.” 

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GridSecCon Speakers Cite Threats, Opportunities of AI

MINNEAPOLIS — With the annual GridSecCon security conference in its 13th year, Electricity Information Sharing and Analysis Center (E-ISAC) CEO Manny Cancel said the event was “incredibly important” for the electric industry and encouraged attendees to use the opportunity to strengthen their bonds. 

In his opening remarks on the first day of the conference, Cancel observed this was his first time attending GridSecCon in person, despite having headed the E-ISAC for nearly five years. The first two conferences during his tenure at NERC were held remotely because of the COVID-19 pandemic. Scheduling conflicts kept him away last year, and in the years when he worked at Consolidated Edison, the conference always conflicted with the company’s Board of Directors meeting. 

Cancel later added he was glad for the chance to finally attend the event before his planned retirement early next year. (See NERC’s Cancel, Hoptroff to Retire in 2025.)  

GridSecCon allows stakeholders “to share our subject matter expertise [and] open up new doors, new connections, collaborations and ways of thinking, especially in the face of … a very complex and challenging cyber and physical security threat environment,” Cancel said, citing a “maturity of cyber attacks [that is] probably at a point that it’s never been at in history.”   

“We see threat actors with goofy names or crazy names like Volt Typhoon and Fancy Bear, [but] don’t be fooled,” he continued. “They’re very concerning [and] very sophisticated. … And then, to add insult to injury, we see attempts at ransomware all the time. Our networks are scanned and reconned every single day, billions and billions of times.” 

Cancel’s fellow keynote speaker, Sara Patrick, CEO of GridSecCon co-host the Midwest Reliability Organization, agreed that the industry is “witnessing a paradigm shift,” with load growth “larger than anything that we’ve anticipated or seen in decades.” She described how the electric grid had changed just in the time since she joined MRO 16 years ago. She quoted the author April Rinne, saying, “The pace of change has never been as fast as it is today, and yet it is likely to never again be this slow.” 

E-ISAC CEO Manny Cancel speaks at GridSecCon in Minneapolis. | © RTO Insider LLC 

“We’re living in a world where there’s so much more uncertainty than we’ve ever experienced,” Patrick said. “And I think we, everybody in this room, is a testament to that. We managed our way through a … pandemic, and I like to think that, perhaps as a silver lining from that … was that it brought the world together a bit, and today we have a higher tolerance for uncertainty.” 

Cancel joined a panel later in the day examining the risks that artificial intelligence and other technological advances could pose to grid reliability. Along with his fellow panelists, Cancel spoke to concerns about the rapidly expanding capabilities of technology to harm the grid but also noted the opportunities it could present to aid in utilities’ defense strategies. 

Adam Lee, chief security officer at Dominion Energy, warned that recent advances in technology have given criminals and extremist groups “tool sets that only nation-state actors have had before.” 

Lee was echoing Avangrid CSO Brian Harrell, who said on the same panel that tools like AI could give threat actors the ability to compile immense amounts of information to use against individuals and their employers, or even to impersonate them. 

But Lee also observed a danger from businesses using AI tools internally, for example to prepare summaries of information for executives or the public. He said machines reviewing internal data may not notice discrepancies that could point to problems. 

“That’s something that we’re really thinking hard about at Dominion,” Lee said. “We built a series of policies around not just the use of AI, but how we manage our internal, proprietary data … what tools are we making available to manipulate that data, and then what are we enabling our work force to [do with] that internal data?” 

CPS Energy CSO Jonathan Homer agreed with these concerns, but also suggested companies can benefit from AI to create insights that would have taken much longer in earlier days.  

“AI significantly advances the ability to sort through data and find what you’re looking for, even if you can’t accurately describe it,” Homer said, invoking the familiar analogy of a needle in a haystack. 

Lee chimed in, suggesting “AI will help you find not only the needle in the haystack, but all the other haystacks you didn’t know existed. … In fact, sometimes you find needles that you weren’t aware existed before you started.” 

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Transmission Security Floor Discussion Causes Consternation at NYISO

Long-simmering frustration came to the surface during NYISO’s Installed Capacity Working Group discussion of the transmission security floor Oct. 22 as stakeholders raised questions about NYISO’s plan to update its methodology for the 2025-2026 capability year. 

“We proposed the following enhancements to account for the coincident peak load, and an update to the five-year derating factor for intermittent resources,” said Keegan Guinn of NYISO ICAP Market Operations.  

He began outlining the updates to the floor calculations, including using the ICAP Manual Attachment N methodology for intermittent derating factor calculation and continuing to use the average five-year EFORd (a measure of historical performance) minus outages caused by transmission issues (termed 9300 events).  

Stakeholders began questioning the process before Guinn could finish his first slide. Stakeholders have been raising concerns about how NYISO values transmission security and what they see as a disconnect between how different NYISO departments handle transmission security. Many stakeholders seemed to want this fixed by next summer.  

“Given that the ISO has acknowledged that the current planning framework that includes the 9300 events is improper, and is searching for how to come up with a better approach that excludes that data, why are we still struggling to adhere to something that the ISO itself concedes is not the right approach?” asked Howard Fromer, director of regulatory affairs for Bayonne Energy Center.  

Fromer said he didn’t think NYISO was going to update its process to exclude the transmission-related outage data from how generator reliability was assessed in time for the upcoming capability year.  

“We are going to be left with the same problem we’ve had for the prior couple of years, where you’re going to set a requirement here for the capacity market that is going to be an inflated reliability need that the ISO is going out and solving through out-of-market actions” Fromer said.  

At this point, Yvonne Huang, NYISO’s senior manager of installed capacity market operations stepped in, saying NYISO was still working on a solution. The problem, Huang said, was that planning assumptions use the NERC class average reliability data, which includes the 9300 events.  

“9300 events should not be a part of the framework, and how do we back that out from the NERC class average,” Huang said. “That action item is still ongoing at this point. I don’t think there’s any conclusion at this point.”  

After some back-and-forth, Doreen Saia of Greenberg Traurig suggested that NYISO could come up with two sets of numbers for the TSL floor. One calculation could use the current methodology. The other could remove the 9300 events data under the assumption that the planning department could devise an alternative source of reliability data for generators. 

“I hear you that it makes it more complicated, but there’s nothing that prevents you from doing both tracks,” Saia said. “While it is more difficult and time consuming, we are where we are. It is absolutely the case that this issue has been raised for some time now and has yet to be resolved. “ 

Mark Younger, of Hudson Energy Economics proposed that NYISO use local data on the impact of 9300 outages on New York generators.  

“I encourage the ISO to be back next week with a plan to get it resolved in, I don’t know, six weeks? Four weeks?” said Younger, addressing the data substitution plan. “We shouldn’t be retaining capacity that’s not necessary because of an inflated number and then turning around to have market results that are consistent with us not having any reliability need at all.” 

Later in the discussion, Younger said some of the contributors to NERC class average data came from areas that weren’t good proxies for New York because they didn’t have a capacity market and might also feature market and environmental elements that were not representative of local conditions.  

Operating Reserves Performance Penalty

As the grid becomes more reliant on intermittent resources, NYISO and various stakeholders have become concerned that the market is not designed to compensate generators for their actual performance in response to NYISO dispatch.  

Under current market rules, when a generator’s day-ahead operating reserve schedule is converted to real-time energy, the generator must buy out its day-ahead reserve schedule. If it does not perform, it also buys out the energy not provided. But there is no defined operating reserve penalty for failure to perform, i.e. actually deliver promised energy.  

NYISO presented its proposed penalty mechanism for generators that don’t perform during “reserve pickups.” It would apply a monetary penalty to generators or other resources that fail to perform. The intent is to recover costs to consumers for operating reserves that were paid for but not provided, while incentivizing reserve generators to perform as promised and scheduled.  

“This project will seek to assess methods for evaluating the performance of an operating reserve provider and also develop a proposal for improving the market rules, creating financial consequences for resources that misstate their operating reserves capability and or perform poorly when called upon to convert operating reserves to energy,” said Katherine Zoellmer, market design specialist for NYISO. 

Zoellmer said NYISO intends to finish this market design and the associated tariff updates and votes this year.  

“The penalty proposal will apply in two different scenarios,” Zoellmer said. The first instance, she explained, is if the resource is “out-of-merit” for failing to follow basepoints from dispatch. The penalty can also be triggered if three conditions are met: The resource is operating below what they were committed to day-ahead, the resource’s day ahead reserve schedule is greater than zero and the resource is undergenerating relative to the real-time energy schedule by at least 3% for 15 minutes.  

“Effectively, we’re capping the penalty at that day-ahead reserve schedule,” Zoellmer said. “A resource would not be penalized more than the day-ahead reserve schedule.”  

Some stakeholders were skeptical of the penalty and said it didn’t take into account real-time schedules, meaning that if the real-time a resource was dispatched down, they could be penalized.  

“It’s not the generator’s fault that, going into the real-time reserve pickup, they were scheduled by the ISO for the energy to be 10 [MW] or 20 MW below what they had offered to sell on the day ahead and been scheduled for on the day ahead,” Younger said. “It just doesn’t work.”  

NYISO responded that it heard the concern and would welcome proposals to hone the penalty equation.  

Kevin Lang, a lawyer at Couch White LLP representing large energy consumers, asked whether the penalty project was going to still include a procedure for removing resources that consistently fail to perform. Zoellmer replied that that was still a part of the project and that details would be forthcoming.  

Multiple stakeholders brought up that the penalty structure might miss poor performers that were infrequently called on due to their high prices.  

“It’s always going to be a less expensive source that would be asked to convert to energy sooner,” Fromer said. “We don’t want to disincentivize the less expensive unit, for them to say, ‘Hey this is crazy, I’m the only one getting whacked here.’” 

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SPP, MISO Await FERC’s Approval of JTIQ Project

LITTLE ROCK, Ark. — SPP and MISO are coordinating responses to the August FERC filings to facilitate their Joint Transmission Interconnection Queue (JTIQ) process and cost-allocation methodology.

Clint Savoy, SPP’s manager of interregional strategy and engagement, told the RTO’s stakeholders Oct. 16 that the comment period for the filings closed Sept. 19. The RTOs have asked for an order by Nov. 14.

“There were some comments in support, some protests, some limited protests,” he said. “We’re looking to file those responses as soon as possible so that we give FERC enough time to issue a ruling in the time that we requested.”

SPP filed tariff revisions related to the JTIQ on Aug. 21 (ER24-2825) and MISO did the same Aug. 26 (ER24-2871). SPP and MISO also submitted matching modifications to the commission for their joint operating agreement (ER24-2798 and ER24-2797, respectively).

The tariff revisions have drawn nearly 50 intervenors in each docket. Six regulatory bodies have intervened, primarily over cost allocation.

The RTOs expect a grant of up to $464.5 million in matching federal funds under the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships program to offset about 25% of the $1.7 billion portfolio’s capital costs that would have been charged to interconnection customers. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.)

The grid operators told FERC that JTIQ transmission owners will be “fully compensated” for capital costs associated with their respective upgrades through the portfolio subscription methodology. The costs will be covered through a combination of GRIP funding, charges to interconnection customers benefiting from the portfolio and, if necessary, temporary or permanent backstop funding from load.

The Arkansas Public Service Commission filed clarifying comments in MISO’s docket, saying it opposes the JTIQ backstop proposal. Saying it was concerned that the backstop “fails to allocate costs commensurate with the benefits received,” the APSC asked the RTO to either make the interconnection customers pay the backstop funding or allocate the costs to the subregion where the projects will be built.

The JTIQ portfolio, centered on the RTOs’ northern seam, is expected to enable 28 GW in generation additions through its backbone net. The backbone of network upgrades consists of five projects, cut down from the original seven identified by SPP and MISO:

    • Bison-Hankinson-Big Stone South, 147 miles of new 345-kV lines in the Dakotas (MISO).
    • Lyons Co.-Lakefield Junction, 80 miles of new 345-kV lines in South Dakota and Minnesota (MISO).
    • Raun 345/161-kV project, new 345/161-kV double circuit, and rebuilt 161-kV lines near Omaha, Neb. (MISO, SPP)
    • Auburn-Hoyt, new 345-kV lines in Nebraska (SPP).
    • Expanding and rebuilding a 345-kV substation in Sibley, Iowa (SPP).

The DOE reached a cooperative agreement with Minnesota’s Department of Commerce in September. The department is responsible for administering the federal money, which will be awarded to the RTOs, TOs and other parties involved should they meet their objectives.

“That sets us up to begin establishing the processes that we need to be able to take advantage of this program,” Savoy said.

Responding to an SPP member’s question during the Oct. 16 meeting as to whether Minnesota would be able to influence the disbursement of funds, a spokesperson for the commerce department said the state won’t be “putting its thumb on the scales.”

“That would not be appropriate with federal funds,” the department’s Jessica Burdette said. “That’s not a thing people need to worry about.”

The RTOs said in their FERC filings that board approval is a “major decision point” in whether the GRIP funds can be disbursed and is based on whether the commission approves their tariff revisions and JOA updates.

Assuming FERC approval, the grid operators’ staff members plan to take the JTIQ portfolio to their respective boards’ upcoming meetings for their approval. SPP’s board meets in December and February and MISO’s in December and March.

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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.