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July 3, 2024

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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.  

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SPP Promotes Kelley, Cathey to VP Posts

SPP has filled two vice presidential vacancies, naming David Kelley as its CFO and finance vice president and promoting Casey Cathey to Kelley’s former engineering VP position. 

“I’m very excited to have both of them in these roles as SPP continues to grow, advance and mature in response to our stakeholders’ needs,” SPP CEO Barbara Sugg said in an April 29 statement. 

Kelley was acting as SPP’s interim CFO following Deborah Sterzing’s surprise resignation in March after a little more than a year on the job. (See “CFO Sterzing Resigns,” SPP Board Approves Markets+ Phase 1 Tariff.) 

He will be responsible for developing and executing SPP’s financial strategy. Kelley has more than 20 years of utility industry experience, having served in various engineering and market leadership roles at SPP since joining in 2008. 

“I’m keenly aware [of] how critical it is to consider affordability and financial responsibility in everything we do as a service provider,” Kelley said. 

Cathey will lead SPP’s evolving approach to consolidated transmission planning and will oversee the ongoing development of a transmission expansion plan and the advancement of regional resource adequacy policies. He previously was senior director of grid asset utilization, where he led a group responsible for developing and implementing novel industry policies, tools and procedures aimed at preparing it for the grid of the future. 

“Our industry is navigating an evolving landscape with many challenges and opportunities, and I am eager to work with our stakeholders to develop and implement strategies that will safeguard and prepare our region’s energy future through innovative system planning,” Cathey said.

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Wind Energy Lease Areas Designated in Gulf of Maine, Oregon

Federal regulators are moving ahead with plans to auction wind energy leases with a potential 18-GW capacity off the coasts of Oregon and northern New England. 

The U.S. Bureau of Ocean Energy Management announced the plans April 30 and is seeking comment on the details before finalizing what would be the first such auctions in either location. 

BOEM earlier this year finalized wind energy areas in both locations. (See BOEM Designates Gulf of Maine Wind Energy Area and BOEM Designates Wind Energy Areas off Oregon Coast.) This latest action identifies potential leases within those areas.  

Most of the capacity identified in this plan is in the Gulf of Maine, where eight wind energy areas totaling nearly 1 million acres hold the potential for 15 GW of electrical generation. 

The southern New England coast is the site of heavy wind energy development efforts, with one utility-scale offshore wind farm completed recently, a second under construction, a third about to begin construction and others seeking to rebound from economic setbacks that have delayed construction. 

The water there is shallow enough that wind turbines can be installed with conventional fixed-bottom tower foundations. The Gulf of Maine is so deep in most places that wind energy development there would rely on floating turbine technology, which only recently is being used at scale worldwide.  

Maine is attempting to position itself as an early leader in the floating wind industry, with research programs at the state university and an application with BOEM to place a floating research array off the central coastline. (See Maine One Step Closer to OSW Research Lease.) 

The eight potential commercial lease areas BOEM identified April 30 are farther south in the Gulf of Maine, most of them closer to New Hampshire or Massachusetts than to Maine. 

Speaking at the International Partnering Forum — Oceantic Network’s offshore wind conference April 22-25 — Maine Gov. Janet Mills (D) announced her state has begun the process to procure up to 3 GW of offshore wind energy by 2040. The state issued a Request For Information on April 24 to shape this process. 

Floating wind technology will be needed along the Oregon coast, as well, due to water depths there. BOEM is considering adding lease stipulations that would award bid credits for bidders that commit to help develop the workforce and supply chain for the floating wind industry. 

The two designated Oregon lease areas total nearly 200,000 acres and sit dozens of miles apart off the state’s southern and central coastline. 

The U.S. Bureau of Ocean Energy Management is proposing to auction two wind energy lease areas off the Oregon coast. | BOEM

BOEM’s efforts to site offshore wind off Maine and Oregon have drawn opposition for their feared impact on commercial fishing. BOEM has made changes to draft proposals based on feedback from fishers and other stakeholders, and it said April 30 it would continue to consider their opinions. 

“As we move forward with offshore wind energy in Oregon and the Gulf of Maine, the Bureau of Ocean Energy Management remains dedicated to close collaboration with our government partners and key stakeholders,” BOEM Director Elizabeth Klein said in the news release. “We’re excited to unveil these proposed sales and emphasize our commitment to exploring the potential for offshore wind development from coast to coast.” 

Oceantic CEO Liz Burdock said in an April 30 news release: 

“BOEM’s combined announcement solidifies two new regional markets for floating offshore wind, balancing the development of this industry sector across both coasts. New lease areas in Oregon will support a further buildout of the West Coast’s regional supply chain, adding strength to California projects. And in the Gulf of Maine, this new 15-GW potential will drive the creation of a floating offshore wind supply chain on the East Coast.” 

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RF Levies $30K Penalty for Twin Ridges Oversights

FERC on April 26 approved a settlement requiring the Twin Ridges wind farm in Somerset, Pa., to pay ReliabilityFirst $30,000 over a “litany” of reliability standard deficiencies at the facility.  

The commission said in a filing that it would not further review the settlement, filed by NERC in its monthly spreadsheet notice of penalty March 28 along with a separate spreadsheet NOP concerning violations of NERC’s Critical Infrastructure Protection standards (NP24-6).  

Exus Management Partners, which claims to manage renewable energy assets worldwide with a total capacity of 11 GW, reportedly acquired the Twin Ridges facility in March from global energy developer Vitol. However, the settlement stems from five self-reports submitted to RF in July and August 2021, the year before Vitol purchased the wind farm from a private equity fund managed by BlackRock. 

An operations and maintenance (O&M) company employed by BlackRock informed RF in July 2021 that the plant was in violation of PRC-005-6 (Protection system, automatic reclosing and sudden pressure relaying maintenance). The following month it submitted additional reports of infringements of COM-002-4 (Operating personnel communications protocols) and VAR-002-4.1 (Generator operation for maintaining network voltage schedules). 

According to the first self-report, the Twin Ridge owners did not perform required maintenance on several protection system components, including the facility’s only sudden pressure relay, its battery bank and each of its lockout relays. The violation began Jan. 1, 2016, when PRC-005-6 became enforceable, and ended Oct. 20, 2021, when Twin Ridges finished mitigation activities. These included performing the skipped maintenance and implementing annual reviews of its protection system inventory and maintenance activities. 

Regarding the COM-002-4 violation, the O&M company reported that “there was no formal program for communications training of the entity’s operating personnel under the previous ownership,” or at least no program for which records could be found. The violation lasted from July 1, 2016 — the effective date of the standard — to Dec. 6, 2020, when the owners finished training operating personnel in the relevant communications process. 

The three VAR-002-4.1 infringements similarly involved a lack of records establishing that required maintenance had been performed. Noncompliance began Dec. 22, 2017, the day after RF audited the facility, and ended in January 2022 when the entity adopted new control-room alarm capabilities, a corporationwide VAR-002 procedure and training for operations personnel. 

RF attributed all violations to a fumbled ownership transition, suggesting that records were mislaid during interactions between “multiple owners and O&M companies,” along with a lack of oversight by the facility’s former owners and operators in the case of the VAR-002-4.1 violations. It assessed a moderate risk from all the infringements, noting that the small size of the facility limited “its overall … impact and the potential magnitude of harm.”  

While the regional entity observed that entities “will not be excused from [their] compliance and reliability responsibilities … merely because [they are] small,” it also remarked on the “proactive actions of new owners and a new O&M,” crediting both BlackRock (which it referred to as the “2018 owner”) and Vitol (the “2022 owner”). RF said it decided to limit the penalty in order to “promote the transparent review and self-reporting seen here.”