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November 17, 2024

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Huge Load Growth Propels AEP to Strong 1Q Earnings

American Electric Power said April 30 that 10.5% growth year over year in data centers and other commercial load within its 11-state footprint can be attributed to prior investments in transmission infrastructure.  

“I like to say here at AEP that we’re really wired for growth,” interim CEO Ben Fowke told financial analysts during the company’s first-quarter earnings call. “We’ve been making significant transmission investments over the years, and that’s going to allow us to accommodate this first wave of growth we’re seeing from data centers.” 

Fowke said additional infrastructure and “perhaps even generation” will be needed before the decade is up. The company plans to invest $27 billion in transmission and distribution infrastructure over the next five years to meet service requests that could add an additional 10 to 15 GW of load by 2030. 

“We’ve done a lot of groundwork to put ourselves in this position, and you’re also seeing data center load ramp up at the same time. That’s a natural trend,” he said. “The good news is we believe that the load growth coming on will be fair to all customers and, in fact, will help us keep our rates affordable across all our jurisdictions. That load growth benefits all customers.” 

At the same time, a voluntary severance program announced this month will save about $100 million in labor costs and “mitigate impacts from inflationary pressures and interest rates,” Fowke said. 

AEP told hometown newspaper The Columbus Dispatch that about 7,400 of its 16,800 employees are eligible for the program.  

The Ohio-based company reported earnings of $1.003 billion ($1.91/share) for the first quarter, compared to $397 million ($0.77/share) for the same quarter a year ago. 

Fowke replaced Julie Sloat as CEO in January when she was forced out after 14 months on the job. (See Interim CEO Fowke Explains AEP Leadership Change.) He said the search for a permanent CEO is “well underway” but will take six to 12 months. 

“We will take the time necessary to find the best candidate,” Fowke said. “Based on the talent pool that we’re looking at, we will find the right person to lead AEP.” 

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2023 Flat for Wind Turbine Makers in West, Huge in China

A new report indicates Western wind turbine manufacturers saw demand for their products ease in 2023 amid a stalled market, while Chinese companies saw surging demand due to their country’s rapid buildout of wind energy generation. 

The May 1 report by Wood Mackenzie indicates that for the first time, Chinese manufacturers accounted for four of the top five companies globally by 2023 sales capacity: Goldwind (16.3 GW), Envision (14.1 GW), Windey (10.1 GW) and Mingyang (9.9 GW).  

Denmark’s Vestas was the only Western manufacturer in the top five, coming in at No. 3 with 11.5 GW, the data and analytics company said in its report. 

The four Chinese manufacturers achieved their sales volume almost entirely in China, but competition in that country was intense enough that turbine prices dropped 16% for onshore models and 9% for offshore. 

Wood Mackenzie said Western manufacturers accounted for 93% of wind turbine sales outside of China. The top five in this category were Vestas (28.5% market share), Siemens Gamesa (24.3%), GE (18.1%), Nordex (15.9%) and Enercon (6.1%). 

And 2023 was the sixth year in the top position for Vesta, Wood Mackenzie said. It noted that GE’s ranking was due in part to the strength of its U.S. onshore market. 

GE Vernova, the recent spinoff of the conglomerate’s power business, released its first-quarter financial results April 25. 

During a conference call with financial analysts that morning, CEO Scott Strazik said the onshore segment of the Wind business recorded a positive EBITDA for the third straight quarter despite a lower volume of orders. The offshore segment saw improvement but still recorded a loss. 

The company expects onshore revenue to be substantially higher in the second half of 2024 than in the first, he said, but cannot say exactly when U.S. orders will pick up, due to trouble customers are having with permitting. 

“Importantly, we see North American developers rebuilding their project pipeline as evidenced by the growing onshore interconnection queues,” CFO Ken Parks said. 

Strazik said the company would work through its offshore wind segment backlog and remain “highly selective” on new orders. 

GE Vernova’s offshore segment was in the news April 19, when New York state canceled its entire third offshore wind solicitation because GE Vernova had opted not to bring to market an 18-MW variant of its Haliade-X turbine the company previously said it would develop. (See NY Offshore Wind Plans Implode Again.) 

Provisional contracts for three offshore wind farms totaling 4 GW of capacity had been designed around the 18-MW platform, and the prospect of using lesser-capacity turbines rendered the provisional contracts unworkable, the state said. 

A week later, on the conference call, Strazik did not directly address that issue except to say the company believes offshore wind will play an important role in the energy transition and appreciated the partnership of New York as it pursues its ambitious offshore wind goals amid repeated setbacks. 

However, he did speak about the U.S. offshore wind industry generally, and made no mention of a future 18-MW Haliade-X: 

“With the phase that offshore wind has been in generally over the last few years, it’s been hard to get projects to a point that they’re ready to thrive,” he said. 

“But through our iteration with our customers and where we’re going, I want to tell you, we’re excited about our future product here, a 15.5-MW product that has an ability to have a power boost up to 16.5 MW. We’re working hard to have that prototype running by the end of 2025. And when we look at where we are with our Haliade-X product today, the 14-megawatt product, by the time you get into 2026, we’re going to have somewhere in the neighborhood of 5 million to 6 million operating hours with that product.” 

Strazik appeared to indicate the terms of GE Vernova’s current backlog of orders are unfavorable. 

“We’ve been pretty consistent for a while that we are only going to add to that backlog with materially different economic terms than what is in our backlog today. And that’s a combination of many things: price, other terms and really leaning in on projects that are set to thrive. And there’s a lot of complexity in offshore wind that we’re all learning from, and we’re going to keep working on it every day.” 

Wood Mackenzie Principal Analyst Endri Lico gave an assessment of the wider market: 

“Western OEMs practiced commercial discipline, showing little appetite for price reduction to grow market share. 2023 saw some improvement in financial performance as some of the supply chain disruptions eased, but quality and reliability issues have emerged as another source of instability for western OEMs,” Lico said. 

The never-ending drive toward bigger and better turbines, with their potential of greater return for developers on investment, have been blamed for some of these quality control problems — it prolongs the research and development phase, and it complicates attempts to achieve standardization or economies of scale. (See Big Offshore Wind Plans Face Multiple Major Obstacles.) 

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FERC Approves Changes to SPP’s GI Process

FERC has accepted SPP tariff revisions designed to increase study deposits for generator interconnection requests, add a nonrefundable application fee and clarify the process of evaluating modifications to requests. 

In an order issued April 30 and effective May 1, the commission found the revisions will improve the efficiency of SPP’s GI request process, reduce administrative burdens for both the RTO and its interconnection customers, and clarify modification study procedures (ER24-1362). 

“These revisions will contribute to increasing the overall efficiency of the generator interconnection process, which will help ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner,” FERC wrote. 

SPP said processing costs to study proposals have averaged $7,100 per request and they have exceeded $10,000 per request for two of its three most recent study clusters. The RTO’s GI process has been plagued by developers filing requests to gauge costs or withdrawing those requests, leading to frequent restudies. Staff still are processing study clusters dating back to 2017; the queue numbered 1,139 requests for 221 GW when the backlog-clearing effort began. 

The grid operator will increase the study deposits for new requests to align with the framework required by FERC Order 2023, which ranges from $35,000 to $250,000 depending on the generating facility’s size. Proposed projects of fewer than 80 MW will be responsible for a $35,000 deposit, plus an additional $1,000/MW. Replacement requests will pay $60,000 to $120,000, generating facility modification requests $10,000 to $60,000, and surplus interconnection service requests $15,000 to $60,000. 

SPP said the proposed revisions will streamline the study process and reduce the financial exposure for itself and its members by increasing study deposits. It said requiring a $10,000 nonrefundable application fee for each interconnection request will mitigate the “significant” financial risk between the deposits and actual study costs.  

FERC found that while SPP’s proposed application fee was double that established in Order 2023, the RTO had proved the new fee, to be adjusted every three years for inflation, “reasonably reflects” the costs to process interconnection requests before a cluster’s close.  

The commission said while some tariff revisions deviated from FERC’s pro forma Large Generator Interconnection Procedures, SPP still demonstrated the proposed variations are just and reasonable.

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FERC Approves COD Waiver for EDP Solar Farm in MISO

A FERC-approved waiver of MISO’s commercial operation deadlines for an Arkansas solar farm is a microcosm of the footprint’s struggle to overcome supply chain issues to bring new resources online. 

FERC on April 30 approved EDP Renewables’ request to extend the final COD for its Crooked Lake solar farm from May 1 to Aug. 1 (ER24-1402). EDP said supply chain issues have dogged the project in the northeast corner of Arkansas. 

In MISO, a developer’s interconnection agreement can be terminated if the new generator fails to achieve commercial operation three years after it originally told the RTO it would be operating for profit. MISO is currently reworking the COD policy in its interconnection procedures after becoming aware of several new generation projects held up by supply chain complications. (See MISO to Relax Commercial Operation Deadlines in Interconnection Queue.) 

EDP began developing the 175-MW solar farm in 2016 and signed a generator interconnection agreement with MISO and transmission owner Entergy Arkansas in 2018. It began construction on Crooked Lake at the end of 2022.  

The company said Crooked Lake was impeded by a slower-than-expected delivery of the control building for its high-voltage substation when the project was nearly finished. The company said despite it and its vendor’s best efforts, the building arrived too late to meet its construction schedule. EDP said that “extended time frames for procurement of control building components, such as relay panels, automatic transfer switches and Cisco communications equipment, had a cascading effect” that resulted in a three-month delay. 

EDP said a waiver of the COD would allow it to energize the solar farm “without forfeiting … interconnection service, completed network upgrades or substantial investment.” 

FERC said EDP acted in good faith to seek the limited waiver, which won’t harm third parties. 

MISO late last year reported that it is sitting on about 50 GW in generation projects that have earned stamps of approval to connect to the system but aren’t completed because of supply chain delays. (See MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation.) 

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White House CEQ Finalizes NEPA Changes, Rolls Back Trump Rule

The White House Council on Environmental Quality on April 30 finalized a rule meant to modernize the federal environmental review process under the National Environmental Policy Act (NEPA). 

The “Bipartisan Permitting Reform Implementation Rule” sets clear deadlines for agencies to complete environmental reviews; requires a lead agency; sets specific expectations for lead and cooperating agencies; and creates a unified and coordinated federal review process. The rule implements parts of the Fiscal Responsibility Act of 2023 and provides agencies with other tools to improve the efficiency and effectiveness of environmental reviews. 

It creates new ways for agencies to establish categorical exclusions, the fastest form of environmental review. It is meant to accelerate reviews for projects that agencies can evaluate on a broad, programmatic scale, or that incorporate measures to mitigate adverse effects. 

The rule promotes early public engagement in the review process to cut conflict, speed up project reviews, improve project design and outcomes, and decrease the likelihood that final decisions are overturned in court. The changes apply to a range of projects, including electric transmission and generation, electric vehicle charging, wildfire management and semiconductor manufacturing. 

Agencies will be able to use new and more flexible methods to establish categorical exemptions for “low impact” projects such as solar, storage, electric vehicle charging and transmission. The rule also encourages using shared analysis to avoid agencies duplicating work. 

Projects with long-lasting beneficial impacts, such as environmental restoration activities without significant adverse effects, will not require environmental impact statements under NEPA. The rule clarifies that agencies should consider the effects of climate change in environmental reviews and encourage identification of reasonable alternatives that will mitigate climate impacts. 

“These reforms will deliver smarter decisions, quicker permitting, and projects that are built better and faster,” CEQ Chair Brenda Mallory said in a statement. “As we accelerate our clean energy future, we are also protecting communities from pollution and environmental harms that can result from poor planning and decision-making while making sure we build projects in the right places.” 

The rule rolls back one issued under the Trump administration, which changed how agencies evaluate the significance of a proposed action’s environmental effects. It removes “onerous” requirements on what public comments must contain to be considered by agencies and removes provisions attempting to curtail judicial review. 

It also seeks to advance environmental justice and promote meaningful public input by promoting early engagement with communities and fostering community buy-in. 

The rule received criticism from Sen. Joe Manchin (D-W.Va.), who is working on legislation to speed up federal permitting processes. 

“At a time when everyone agrees that it takes too long to build infrastructure in this country, the administration’s new NEPA regulations will take us backwards,” Manchin said in a statement. “All the White House had to do was implement the common-sense, bipartisan permitting reforms in the Fiscal Responsibility Act that all sides agreed upon; but once again they’ve disregarded the deal that was made [and] the intent of the law that was signed, and are instead corrupting it with their own radical agenda. This will only lead to more costly delays and litigation.” 

Manchin said he plans to offer a resolution of disapproval under the Congressional Review Act so the CEQ can issue a rule that complies with the FRA. 

The Natural Resources Defense Council welcomed the changes. 

“NEPA leads to better decisions — and better outcomes — for everyone, and it is a relief to finally see it revitalized,” NRDC Executive Director Christy Goldfuss said in a statement. “Meaningful community engagement is the key to unlocking our clean energy future. It leads to better projects that face less opposition on the back end.” 

“We are thrilled to see NEPA strengthened and restored,” said Sam Wojcicki, senior director of climate policy for the National Audubon Society. “This new rule is a significant win in protecting communities from environmental harm and [for] ecosystems that birds and other wildlife depend on for their survival.” 

Electric Power Supply Association CEO Todd Snitchler said the final rule “takes reliability efforts backwards.” 

“Integrating more clean energy into the system will require the support of dispatchable generation,” Snitchler said. “If we are serious about meeting our energy reliability and policy needs during a time of rapid growth in electricity demand, we need critical investment in both dispatchable and renewable generation, fuel supply infrastructure, and transmission and distribution assets. 

“The Federal Energy Regulatory Commission, the North American Electric Reliability Corp. and grid operators are all flashing warning signs that dispatchable resources are being retired too quickly and aren’t being replaced with sufficient capacity with similar reliability attributes. In short, the clock is ticking. We need more infrastructure, not less, and it is disappointing that this rulemaking puts politics and aspiration ahead of the operational realities of the electric grid.” 

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DOE: AI Critical to US Clean Energy, Grid Modernization Goals

Imagine developing a big solar project and finding that getting it permitted will involve navigating federal, state and local regulations, each of which uses different terminology and data, making the whole process complex and time consuming.  

Now imagine having an artificial intelligence (AI) program that can organize and consolidate the various requirements of those regulations and identify the information that can be used across all of them.  

Streamlining and accelerating permitting is just one of the potential uses the Department of Energy envisions for AI to accelerate the U.S. power system’s transition to 100% clean energy and the modern, efficient, secure grid needed to reach that goal by 2035, according to two new reports DOE released April 29. 

AI for Energy: Opportunities for a Modern Grid and Clean Energy Economy looks at the near-term potential for AI to speed up, streamline and improve system planning, project siting and permitting, operations and reliability, and resilience.  

The report provides laundry lists of possibilities in each of these areas: for example, using AI to model the adoption of distributed solar and storage projects or virtual power plants to forecast impacts on load and load shape, as well as when and where distribution system upgrades will be needed. 

Other potential applications include: 

    • optimizing the planning, permitting and siting of electric vehicle chargers and supporting vehicle-to-grid charging to provide grid support services; 
    • optimizing energy use in buildings and developing models to predict buildings’ energy load shape, future consumption and coordination with the power system; and 
    • accelerating environmental reviews by extracting information, drafting documents and automating compliance checks. 

The second report, Advanced Research Directions on AI for Energy, explores longer-term opportunities and challenges, such as the information and workforce that will be needed to build the specialized AI models required for “dynamic coupling” of dispatchable generation with renewable and other variable generation.  

“These models must account for the varying and unpredictable nature of renewable resources over time and space,” the report says. “At the plant level, adaptive … models based on real-time measurements are needed to enable rapid adjustments to the system controls, which is essential for managing the changing dynamics of energy supply and demand.” 

The reports are part of a larger DOE drive to develop such AI models and other resources to adapt the uses of the now-omnipresent technology to advance President Joe Biden’s targets for decarbonizing the grid by 2035 and cutting U.S. greenhouse gas emissions across the economy to net zero by 2050.  

Biden issued a broad executive order on AI on Oct. 30, which gave DOE a six-month deadline for producing a public report on the potential uses of AI for energy and for developing applications to streamline permitting and environmental reviews. 

“Artificial intelligence can help crack the code on our toughest challenges, from combating the climate crisis to uncovering cures for cancer,” Energy Secretary Jennifer Granholm said in a press release summarizing DOE’s progress on these and other AI initiatives called for in the executive order.  

DOE is ramping up its work on AI “on multiple fronts to not only keep the U.S. globally competitive, but also to manage AI’s increasing energy demand so we can maintain our goal of a reliable, affordable and clean energy future,” Granholm said. 

Among its other efforts, DOE is providing $13 million in funding for a new VoltAIc Initiative, which aims to develop AI tools for streamlining permitting and environmental reviews of clean energy projects and infrastructure. DOE has partnered with the Pacific Northwest National Laboratory on one such tool, PolicyAI, an AI test bed specifically focused on environmental reviews under the National Environmental Policy Act. 

DOE has also formed a Working Group on Powering AI and Data Center Infrastructure, which could be issuing recommendations in June on meeting the power demands of AI and other data centers, according to the DOE press release. Another upcoming study from the Lawrence Berkeley National Laboratory will analyze the regional energy and water use of data centers across the U.S. 

AI ‘Hallucinations’

From search engines to popular consumer apps — Amazon, Trivago and Airbnb — AI has become inescapable, although the technology is not completely debugged. 

As defined in Biden’s original executive order and U.S. Code, AI is “a machine-based system that can, for a given set of human-defined objectives, make predictions, recommendations or decisions influencing real or virtual environments.”  

AI applications are built on “foundation models,” which are “trained on,” or fed, massive amounts of publicly available data — generated by humans or machines — which can then be tapped for a variety of uses, depending on the prompts used or the questions asked. The drawback is that if an AI model doesn’t have the information to answer a question, it might “hallucinate” and provide an answer that sounds authoritative and convincing but is completely wrong, said Jeremy Renshaw, senior technical executive at the Electric Power Research Institute (EPRI). 

“It’s not like you can take one of the models, say ChatGPT … and just provide a bunch of prompts to it, and it’s going to get the right answer every time,” Renshaw said in an interview with RTO Insider. “It just doesn’t work that way. The tools are very powerful, for sure, but they can’t do everything. If you understand how to use them, and you find the right prompts or input questions, you can get better responses.” 

Given the complexity of the electric grid itself, both Renshaw and DOE acknowledge that building foundation models for the energy sector could be very difficult “and further worsened by the evolving dynamics of climate change,” according to the AI for Energy report.  

“Bridging the gap between the wealth of industry data that exists and the limited ability of the research community to access it remains a difficult task,” the report says. A figure in the report shows the multiple data streams ― on load forecasts, algorithm codes and equations, regulatory standards and risk metrics ― that must be “orchestrated” to create such a model. 

Renshaw explained it in less technical terms. “AI is a data-hungry machine,” he said. “So, the more data you can feed into it, the cleaner, the better, the higher-quality results you can get from the models. We have lots of grid operational data we can feed into models that can then understand the physics or patterns within the grid, and from that we can get … closer to things like optimal power flow or automated grid management. 

“They may still be years away, but that’s something that would be very impactful and very useful for the grid,” he said.  

The Advanced Research Directions report estimates that developing foundation models to support grid planning, operations and security will also mean putting together well-coordinated, interdisciplinary teams. The roster could include about 100 AI and data scientists, another 100 power system engineers and analysts, 200 software engineers and 100 cybersecurity professionals. 

While the size of individual teams could vary “depending on the size and scope of the [model], adopting a comprehensive approach involving these various skill sets is necessary to building confidence and accelerating momentum in the progress being made,” the report says. 

Utilities’ Incremental Path to AI

U.S. utilities are, by nature, risk-averse, so while many are now adopting AI, their initial applications appear to be supporting traditional operations, rather than advancing system decarbonization, for example, by improving renewable energy interconnection processes.  

Speaking at an EPRI seminar in March on demystifying AI, Chris Le, analytics product manager for Exelon, described some basic ways the company and its utilities are using AI. Exelon has developed a machine learning model to crunch the company’s extensive data on power outages and the time it takes to restore power, Le said. 

Machine learning is a kind of AI that uses algorithms and statistical models that can be applied to perform complex tasks without explicit instructions.  

In Exelon’s case, the company has been able to improve its reporting on estimated restoration times “by 900% within the 2-hour window, which is what most customers care about,” Le said. 

Another application has involved training an AI model to identify potential defects on the distribution system from aerial photography, he said. “We’ve trained models to achieve successive capabilities for us — first, just identifying components in the photos … [then] identifying specific defects on those photos and then, finally, determining defect severity based on our internal ranking system.” 

But AI is intruding on utility planning with increasing urgency via the proliferation of data centers across the country and their growing demand for power, largely due to AI. 

The AI for Energy report cites work currently underway at the Berkeley Lab, which indicates “that over half of data center load growth in recent years may have been due to AI, and it is expected to be the biggest driver of U.S. data center-related load growth in the near future.” 

Some utilities have responded to the data center boom by arguing for new natural gas plants to ensure supply and system reliability. The fast growth of data centers in Northern Virginia is a key factor in plans by the state’s largest investor-owned utility, Dominion Energy, to build new natural gas plants, according to coverage in the Virginia Mercury. 

But Renshaw and DOE both note that data centers and AI developers are working on reducing their substantial carbon footprints. Industry leader NVIDIA recently launched its new Blackwell platform, which it says will provide supercharged AI capabilities “at up to 25x less cost and energy consumption than its predecessor.” 

The company is also partnering with Schneider Electric to develop publicly available “data center reference designs” that will provide benchmarks for system performance and efficiency.  

DOE is pushing for further improvements in data center energy efficiency. “In 2020, the average data center used only 37% of its energy for cooling and other needs other than powering the IT equipment,” the AI for Energy report says. “The most energy-efficient data centers in the world use only 2 to 3% of their energy for such purposes.” 

DOE’s own Frontier supercomputer at Oak Ridge National Laboratory “uses advanced liquid cooling and other state-of-the-art techniques to achieve this 3% goal,” the report says.  

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9th Circuit Upholds NRC Decision on Diablo Canyon

Pacific Gas and Electric’s plans to extend the life of the Diablo Canyon nuclear power plant through 2030 remain on track after a federal appellate court rejected environmental groups’ petition challenging an exemption to the license application deadline. 

A three-judge panel of the U.S. Court of Appeals for the 9th Circuit issued an opinion April 29 rejecting the petition from San Luis Obispo Mothers for Peace, Friends of the Earth and the Environmental Working Group (23-852). 

Diablo Canyon, a 2,200-MW nuclear plant on California’s Central Coast, provides about 8.6% of the state’s total electricity supply and around 17% of its zero-carbon electricity. PG&E had planned to retire Diablo Canyon’s two units in 2024 and 2025.  

But in September 2022, Gov. Gavin Newsom (D) signed Senate Bill 846, directing PG&E to run the nuclear power plant until 2030 to improve the reliability of the state’s energy system. 

In their petition, the three environmental groups asked the court to review the Nuclear Regulatory Commission’s decision to allow Diablo Canyon to keep running while the NRC considers its license renewal application. Ordinarily, such an action is taken if a renewal application is submitted five years before a license expires. 

PG&E did not submit the renewal application before the five-year deadline and asked NRC for an exemption to the “timely renewal” requirement. NRC granted the request in March 2023, and PG&E submitted its renewal application in November 2023. 

NRC has said it typically takes 22 months to review a license renewal application. 

NRC regulations allow exceptions to its five-year application deadline under special circumstances if the exception won’t create health or safety issues. 

The appellate panel noted “the highly unusual circumstances of this case,” specifically lawmakers’ direction to postpone Diablo Canyon’s retirement. 

“But for the California Legislature’s determination of a material change in the electrical needs of its citizens, by all accounts PG&E would have terminated operations at Diablo Canyon,” the panel said in its opinion. 

The environmental groups argued that the NRC exemption ignored the environmental concerns of running Diablo Canyon past its 40-year license term. But the appellate panel said the groups hadn’t presented “any specific evidence of concerns with Diablo Canyon.” 

In addition, the panel said, “NRC’s continuing oversight authority assuages safety concerns.” 

In response to the court’s decision, Caroline Leary, COO and general counsel for the Environmental Working Group, said the environmental groups would “explore all avenues to reverse the NRC’s irresponsible decision.” 

“PG&E and California’s leaders are recklessly gambling with Diablo Canyon, endangering the health and safety of countless individuals,” Leary said in an April 29 statement. 

Diablo Canyon Unit 1 has been in operation since 1985 and Unit 2 has been running since 1986. Operating licenses for the units expire in November 2024 and August 2025. 

PG&E at one time planned to keep Diablo Canyon running and submitted a license renewal application in 2009. But the utility decided to retire the units instead, and it withdrew the application in 2018. Plans for Diablo Canyon changed again in 2022 with the passage of SB846. 

In December, the California Public Utilities Commission approved extending operations at Diablo Canyon through 2030. (See California PUC Votes to Extend Diablo Canyon Nuclear Plant 5 Years.) 

And in January, the Department of Energy awarded PG&E $1.1 billion to keep Diablo Canyon running. (See Diablo Canyon Secures $1.1B DOE Award to Support Operations.) 

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New Jersey Opens 4th Offshore Wind Solicitation

The New Jersey Board of Public Utilities has opened its fourth offshore wind solicitation, with a planned capacity of up to 4 GW, as the state seeks to rebound from the sudden dissolution by developer Ørsted of two of the state’s first three projects. 

The solicitation, outlined in an April 30 guidance document, seeks to create a “robust competition” and attract projects with a capacity of between 1.2 and 4 GW, and even larger “if circumstances warrant,” according to the guidelines. The solicitation will close at 5 p.m. on July 10. 

It follows by just three months the BPU’s announcement of the favored projects in the state’s second solicitation. If the three ongoing projects backed by the state come to fruition, the state would have slightly less than half of its target of 11 GW by 2040. (See NJ Awards Contracts for 3.7 GW of OSW Projects.) 

BPU commissioners, who voted 4-0 on the plan, touted the solicitation as a show of the state’s strength in the sector. 

“This solicitation really demonstrates that we are committed to seeing the economic development that offshore wind is bringing to New Jersey, and will continue to bring, as well as the clean energy that is so important for the residents,” BPU President Christine Guhl-Sadovy said after the vote. 

The BPU initially pursued a strategy of holding solicitations every two years, selecting the 1,100-MW Ocean Wind 1 in 2019, and the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores Offshore Wind in 2021. But it has accelerated the process since Ørsted abandoned its two projects in October 2023 and left Atlantic Shores as the only ongoing project. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) 

Commissioner Zenon Christodoulou called the task of preparing the solicitation a “really monumental task that you guys have accomplished in such a short time,” referring to BPU staff. 

“We are admired across the country,” he said. “Other states look to New Jersey and look to what you have done and say: ‘We can do that.’ And they’re learning from us. They appreciate it. And you’ll see many states following our path.” 

The guidance document sets out a schedule in which the BPU would select projects by the end of the year, with an expected completion date of 2032. Developers would submit bids stating the price of the Offshore Wind Renewable Energy Certificates (OREC) — a measure that represents the environmental attributes of 1 MWh — at which they would undertake the project. The BPU then would pick those viable projects that best meet the agency criteria and would be the most financially favorable to the state. 

The document also contains a section that allows projects selected in the first two solicitations to submit a “Re-Bid Project.” The section effectively would allow them to seek to adjust their cost structure to adapt to the rising costs — from the supply chain, material prices and interest rates — that have prompted developers to pull out of OSW projects in the U.S. It would also enable them to seek additional state support. 

Community Solar Capacity Doubled

In a separate action at the April 30 meeting, the BPU also agreed 4-0 to reopen the state community solar program on May 15 and expand its capacity from 225 MW to 500 MW. 

The expansion comes in the first year of the program as a permanent entity after two pilot programs demonstrated the interest of solar developers and ratepayer subscribers. 

The BPU opened the first permanent program solicitation on Nov. 15 with a target capacity of 225 MW, to be allocated in four capacity blocks, one for each territory serviced by the four electric utilities in the state. The board closed the solicitation after applications exceeded the available capacity, but a law signed Jan. 24 by Gov. Phil Murphy allowed it to increase the capacity available to 275 MW if applications exceeded 225 MW. 

The law will allow capacity expansions in the future as well: by 250 MW if applications exceed 500 MW in 2025, and by an additional 150 MW in subsequent years. Under the current guidelines, if the capacity now allocated for community solar in 2024 is not used, it will be rolled over and available in 2025. 

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said he was “pleased to see the program move forward quickly” and added that it “shows that the board and this administration is committed to community solar.” 

State officials see the program as a key element in helping the state reach its goal of 12.2 GW in solar capacity by 2030 and 32 GW of solar by 2050. The state had 4.8 GW of installed capacity as of March 31, according to BPU figures. 

The state enacted its first community solar pilot program in 2019, and a second pilot in 2021. The first program, which attracted 252 applicants, approved 45 projects totaling 75 MW. The second pilot, which attracted 412 applications, awarded 105 projects totaling 165 MW. (See NJ Opens Community Solar and Nuclear Support Programs.) 

The BPU board also approved some program rule changes April 30, including allowing low-income customers to “self attest” to their household income, rather than having to show proof — a change long sought by solar developers who said requiring customers to document their income dissuaded many from applying to participate in community solar. 

Another rule change approved by the board requires utilities to discount a customer’s bill at least 20% for participating in the community solar program. 

Facilitating DER Connections

The board also backed several rule changes designed to help distributed energy resources connect to the grid.  

The BPU based the rules on the short-term conclusions of a Grid Modernization Study released in November 2022. The changes include creating a streamlined process for utility interconnection applications and making “clearer and more consistent distribution system information available to potential project applicants,” according to a BPU statement. Another section would fashion a “pre-application and verification process that will provide interconnection applicants with an early indication of feasibility and costs.” 

Longer-term changes aimed at capacity expansion and further grid modernization will be addressed in an upcoming “grid modernization forum,” the BPU said. 

President Guhl-Sadovy said the ability of the state’s grid to accept new DER resources is critical to its energy future. The development of new rules, she added, “marks a pivotal step toward making the interconnection process more efficient as we prepare to modernize the grid while mitigating impacts on ratepayers.” 

Outlining the rules at the board meeting, BPU staffer Natalie Stuart said they are designed to “remove stakeholder-identified sources of confusion or delay in the DER interconnection process, and to prepare for a broader grid modernization effort that will enable the grid to host more DER capacity.” 

“These rule changes will significantly reduce the uncertainty, inefficiency and delay applicants with viable DER projects seeking interconnection experience, while also clarifying the level of commitment and responsiveness expected from active applicants,” Stuart said. She added that the rules would facilitate the deployment of community solar projects by providing “greater assistance in navigating the interconnection process.”

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Vineyard Wind Opponents Lose Appeals Challenges

The 1st Circuit Court of Appeals on April 24-25 affirmed denial of two challenges to environmental approvals of the Vineyard Wind 1 project under construction off the coast of Massachusetts. 

One of the challenges was brought by a group of Nantucket residents (23-1501), and the other by solar company Allco Renewable Energy and its owner, Thomas Melone (23-1736). 

As the offshore wind industry scales up across the East Coast, opposition groups have filed an array of legal challenges intended to halt its progress. So far, these challenges have failed to stop any projects, with the 1st Circuit’s decisions marking another legal victory for offshore wind developers. (See Opponents Sue to Halt Coastal Virginia Offshore Wind, Another Federal Lawsuit Seeks to Invalidate OSW Approvals.) 

The 806-MW Vineyard Wind 1 project already has multiple turbines in operation and will consist of 62 turbines when complete, potentially by the end of this year.  

The challengers argued that the federal government did not properly evaluate Vineyard Wind’s effects on right whales, an endangered species. Both challenges were denied by the Massachusetts District Court prior to the appeals process. (See Lawsuit Against Vineyard Wind over Threat to Whales Tossed.) 

In biological opinions issued in 2020 and 2021, the National Marine Fisheries Service (NMFS) determined that Vineyard Wind is “not likely to jeopardize the continued existence” of right whales and other endangered species, while determining the project “will have no effect on critical habitat designated” for right whales.  

NMFS did note that the noise associated with pile driving could result in the “harassment” of some right whales but wrote that no right whale injury or mortality is expected from any aspect of the project.  

To mitigate potential impacts, the Bureau of Ocean Energy Management (BOEM) required several mitigation measures in its approval of the project, including restrictions on when Vineyard Wind can conduct pile driving.  

The challenge by the Nantucket residents, initiated in 2021, argued that NMFS’s biological opinion was deficient, and that BOEM’s environmental impact statement violated the National Environmental Policy Act by relying on a deficient biological opinion.  

Allco’s challenge, which also began in 2021, alleged that NMFS erred in issuing Vineyard Wind 1 an Incidental Harassment Authorization. 

Both challenges were heard by a panel of judges on the 1st Circuit entirely nominated by Democrats.  

“NMFS and BOEM followed the law in analyzing the right whale’s current status and environmental baseline, the likely effects of the Vineyard Wind project on the right whale, and the efficacy of measures to mitigate those effects,” wrote Judge William Kayatta in response to the Nantucket residents’ appeal.  

Responding to the Allco appeal, Kayatta wrote “it is clear from the record that NMFS applied its scientific expertise to consider the nature of Vineyard Wind’s activities and the type of harassment expected to occur,” and took no issue with NMFS’s finding that the project would have a “negligible impact” on the right whale species. 

According to the law firm Bracewell, the rulings “mark the first appellate decisions affirming the federal government’s issuance of permits to the Vineyard Wind Project,” and will help set legal precedents that “will shape the trajectory of the emerging offshore wind sector.” 

The 1st Circuit must still hear a pair of pending challenges brought by commercial fishing and seafood organizations, led by the Responsible Offshore Development Alliance and Seafreeze Shoreside, Inc. (23-2051 and 23-1853). 

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MISO to Present Final, $20B 2nd LRTP Portfolio in September

MISO plans to use the summer to polish its approximately $20 billion second long-range transmission portfolio and have it ready for board consideration by mid-September.  

The grid operator last week said its planners will work to debut a draft portfolio by mid-July for a few weeks of evaluation and stakeholder feedback with its Planning Advisory Committee. MISO said it plans to have the PAC’s decision on whether to recommend the portfolio by mid-August.  

By the end of August, MISO is targeting consideration by the System Planning Committee of its Board of Directors. Finally, MISO anticipates presenting the portfolio before its full board for a decision in September during its quarterly Board Week to be held in Indianapolis. 

MISO in early March revealed it’s considering a $17 billion to $23 billion package of mostly 765-kV lines in MISO Midwest as the second portfolio under its long-range transmission plan (LRTP). (See MISO Says 2nd LRTP Portfolio Should Run About $20B, Rate Mostly 765 kV; Members Call for More Tx Expansion Following MISO’s $20B LRTP Blueprint.) 

During an April 26 workshop to discuss the LRTP, WEC Energy Group’s Chris Plante asked if MISO is giving thought to the lower-voltage upgrades MISO will need to support a “superhighway” of 765-kV lines. He said he doubts there’s enough time for MISO to detect all smaller projects needed to accommodate the lines.  

Executive Director of Transmission Planning Laura Rauch said MISO is hard at work identifying smaller upgrades. 

“We think we have a schedule that gets us to September,” she said. However, she added MISO will revisit its timeline if analyses need more time. 

MISO is contemplating including several transmission benefits in the impending business case it will make for the second LRTP portfolio. It is considering: 

    • reduced risks from extreme weather impacts. 
    • capacity and energy savings from smaller transmission line losses. 
    • the lines’ contribution to decarbonization. 
    • avoided transmission investment. 
    • fuel and congestion savings. 
    • reduced transmission outage costs.  
    • avoided costs from adding capacity that otherwise would be necessary without the lines. 
    • mitigation of reliability issues.  

Some stakeholders attending the workshop criticized MISO for attempting to price minimized reliability risks into the benefits of LRTP using the RTO’s value of lost load. They said it isn’t guaranteed the lines will abate reliability issues.  

Bill Booth, consultant to the Mississippi Public Service Commission, said NERC violations are anticipated only five years in advance. Booth asked how MISO is confident poor reliability conditions will occur on its system 30 years in the future absent the lines. He also recommended MISO contrast the price of LRTP versus building incremental reliability projects.  

“How do we know that that is providing the least-cost reliability to customers? This is a speculative metric, and maybe doesn’t belong here,” Booth said.  

Rauch said MISO will pit the LRTP second portfolio’s usefulness against several cases.  

“Reducing risk of load shed is a value, and we can and should continue to talk about it,” she said.  

Sustainable FERC Project attorney Lauren Azar said she supported MISO attempting to monetize the value of regional backbone transmission in avoiding the risk of future load shedding.  

“There’s no precision in this. Just because we’re looking at reliability standard violations 30 years out, doesn’t mean mitigating them isn’t valuable,” Azar said. She pointed out that when transmission is needed to meet NERC reliability criteria, the projects are built no matter the cost benefit.  

American Transmission Co.’s Thomas Dagenais said it’s “a dangerous precedent” to simply bank on real-time operation to avoid load shed and not factor the value of avoided load shed in regional transmission.  

He likened the second portfolio to a decision to obey the speed limit on a morning commute to work. He said while he could go “100 mph and nothing bad could happen,” he’d prefer to follow the speed limit for added protection.  

MISO again pledged to study the impacts of Grain Belt Express and other planned HVDC or major lines on the reliability value of the second LRTP portfolio. (See “The Grain Belt Express Question,” Members Call for More Tx Expansion Following MISO’s $20B LRTP Blueprint.) 

MISO said it will test large projects from its 2023 and 2024 annual transmission expansion cycles, it and SPP’s $2 billion Joint Targeted Interconnection Queue portfolio, and the Grain Belt Express and other merchant HVDC projects with signed transmission construction agreements to see if they handle some of the issues it’s prescribing LRTP lines for.   

MISO said it “may modify, add to or remove transmission facilities” because of its testing.  

WPPI Energy’s Steve Leovy said MISO asked whether it will study a scenario that includes the SOO Green HVDC Link, which is planned to run underground along existing railway corridors from Iowa to Illinois.  

“You’re right that there are multiple HVDC construction discussions in the footprint,” Rauch said, but stressed that MISO will study only the portions of merchant HVDC lines that have signed agreements now. She added that SOO Green’s hypothetical output at the moment appears to be destined for PJM.  

Several MISO stakeholders have asked that MISO include the $4 billion Grain Belt Express in base case models for long-term transmission planning. Multiple MISO state commissioners also have said the model should reflect the system that will exist by the time LRTP projects are built, and tacking on an after-the-fact sensitivity analysis that includes the merchant HVDC line isn’t adequate.