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February 2, 2025

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Ørsted Replaces CEO Mads Nipper

Ørsted CEO Mads Nipper has been replaced by Deputy CEO Rasmus Errboe.

The Danish renewable energy developer announced Jan. 31 that Nipper would leave immediately and Errboe would assume leadership Feb. 1. Errboe, a 13-year Ørsted veteran, formerly was CFO of its global offshore wind business.

Nipper’s four years as CEO were tumultuous for the leading offshore wind developer. The company shed more than 80% of its market capitalization as its investments in the new U.S. offshore wind sector ran into headwinds.

Most recently, the company on Jan. 20 reported $1.7 billion in new impairments on its U.S. offshore wind portfolio. (See Ørsted Takes $1.7B Impairment on US Offshore Wind.)

And that setback did not even reflect the other news that day: the inauguration of President Donald Trump, and his Day 1 executive order targeting offshore wind. (See Critics Slam Trump’s Freeze on New OSW Leases.)

It was a striking juxtaposition for Nipper. He became Ørsted’s CEO in January 2021, just as a strong supporter of wind power was inaugurated as U.S. president, and he departed in January 2025, right after a strong opponent took over.

Former Ørsted CEO Mads Nipper | Ørsted

Lene Skole, chair of Ørsted’s board of directors, alluded to the sea change in the company’s Jan. 31 announcement.

“The renewable energy market has fundamentally changed since January 2021,” she said. “The impacts on our business of the increasingly challenging situation in the offshore wind industry, ranging from supply chain bottlenecks, interest rate increases, to a changing regulatory landscape, mean that our focus has shifted. Therefore, the board has today agreed with Mads Nipper that it’s the right time for him to step down.”

Skole complimented Nipper’s achievements: The company’s installed renewable capacity rose from 11.3 GW to 18.2 GW, and it consistently met its EBITDA projections during his tenure.

The U.S. offshore wind sector, which still has a very significant European component, ran head-on into supply chain shortages, logistics challenges and soaring costs in 2022, just as it was gaining momentum under a supportive federal administration. Most projects, from Maryland to Massachusetts, suffered delays and cost increases, many of them severe enough to cause developers to cancel offtake contracts or ask for more money.

Ørsted went a step further and canceled a mature project outright. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) That move alone caused a $2.83 billion impairment.

The company did enjoy a milestone achievement under Nipper: completion of the first utility-scale offshore wind project in U.S. waters, South Fork Wind, in March 2024. (See First Large US Offshore Wind Farm Complete.) South Fork had its challenges, but it totals only 12 turbines, and the challenges apparently were surmountable.

And Ørsted was not alone in its struggles; its erstwhile development partner was losing money as well.

In September 2024, after a two-year effort, Eversource Energy extracted itself from its joint venture with Ørsted on South Fork and other projects off the Northeast coast. The New England utility took a $1.95 billion impairment in 2023 on its offshore wind ventures, and it projected its 2024 loss attributable to offshore wind will be in the half-billion-dollar range. (See Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023 and Eversource Takes Another Financial Hit with OSW Exit.)

New Ørsted CEO Rasmus Errboe | Ørsted

Ørsted has begun offshore construction of Revolution Wind, which holds offtake contracts in Connecticut and Rhode Island, and onshore construction of Sunrise Wind, which holds a New York contract. Both projects have seen increasing costs and lengthening schedules in the past several months. And both face the potentially serious threat posed by Trump’s Jan. 20 executive order, which directs “a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases, identifying any legal bases for such removal.”

In a Jan. 21 call with financial analysts, Nipper insisted that Sunrise could still be a profitable project, and he declined to speculate on the impact of the executive order. Further information would come with the company’s annual report on Feb. 6, he said.

An analyst asked how Ørsted could do so well in Europe and Taiwan but keep stumbling quarter after quarter in the U.S.

“It is simply the immature and nascent industry of both the supply chain and the execution setup of the U.S. practice,” Nipper replied.

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Stakeholder Soapbox: Preparing for NERC Registration and Compliance with New IBR Rules

By Terry Brinker

As a former manager of registration for the North American Electric Reliability Corporation (NERC) and president and CEO of Reliable Energy Advisors, I have written articles about the risks and challenges of NERC regulations.

In my article “Your Audit Report May Be Worthless,” I warned of falling into the trap of thinking your organization has a strong compliance program because you passed an audit.

Today, I am sounding the alarm about potentially hundreds of facilities being swept up into the NERC regulatory world where fines and penalties can be as high as $1 million a day per violation.

Recently, NERC unveiled updated rules for inverter-based resources (IBRs), which are reshaping the landscape for utilities and energy producers. These new standards aim to enhance grid reliability and security in light of the increasing integration of renewable energy sources, such as solar and wind, into the electric grid.

NERC

Terry Brinker |

For utilities not currently registered with NERC, these changes bring unique challenges and obligations. For entities that are registered and have additional facilities that will meet the new thresholds, more documentation will be needed.

To ensure a smooth transition, nonregistered entities must prepare proactively for NERC registration and adherence to NERC standards. This is no small feat, particularly for newcomers to NERC. In addition, unlike in the past where registration was a voluntary process, NERC has coordinated with reliability coordinators and transmission operators to identify entities that meet this new threshold.

Escaping NERC registration will be unlikely.

Understanding the New NERC Rules for Inverter-based Resources

NERC’s updated rules focus on addressing the operational and cybersecurity challenges posed by IBRs. The new requirements emphasize:

    • Performance Validation: Ensuring that IBRs can withstand and recover from disturbances without jeopardizing grid stability.
    • Data Sharing: Mandating detailed operational data submissions for elective grid planning and operations.
    • Cybersecurity: Strengthening the security framework to safeguard inverter-based systems against cyber threats.

These requirements reflect NERC’s commitment to integrating renewable energy resources while maintaining the reliability and resilience of the bulk electric system (BES).

Steps for Utilities Preparing for NERC Registration

For utilities not currently registered with NERC, the prospect of registration and compliance can be daunting. However, following a structured approach can streamline this transition:

Assess Applicability: Not all utilities are subject to NERC’s rules. Entities must determine whether their operations meet NERC’s criteria for registration. This includes evaluating the size, capacity and operational impact of their resources on the BES. If you have a facility (or facilities) with a 20-MVA nameplate rating and connected at 60 kV or higher, the countdown is on for you to register.

Conduct a Gap Analysis: Perform a thorough gap analysis to identify areas where your operations diverge from NERC standards. This involves:

    • Reviewing the new IBR requirements.
    • Identifying which NERC standards apply to your organization.
    • Assessing current operational, cybersecurity and data management practices.
    • Identifying deficiencies and areas needing improvement.

Develop a Compliance Program: A robust compliance program is critical for meeting NERC standards. Key components include:

    • Policies and Procedures: Develop clear and comprehensive documentation of processes.
    • Training: Educate staff on NERC compliance obligations and the new IBR rules.
    • Monitoring: Implement tools for continuous monitoring and reporting of compliance metrics.

Engage with Industry Experts: Collaborate with NERC-registered utilities or consulting firms specializing in regulatory compliance. Their expertise can provide valuable insights into best practices and help navigate complex requirements.

Prepare for Audits and Registration: Mock audits and readiness assessments are essential for ensuring compliance. These activities simulate NERC’s evaluation processes and allow utilities to address gaps before official audits.

Key Considerations for NERC Compliance

Documentation: Maintain meticulous records of all compliance-related activities, including testing, training and incident responses.

Technology Investments: Upgrade existing systems to meet performance and cybersecurity standards for IBRs.

Stakeholder Engagement: Work closely with regulatory bodies, industry peers and technology providers to ensure alignment with NERC expectations.

Conclusion

The new NERC rules for IBRs signify a pivotal moment for utilities, especially those not yet registered with NERC. By proactively assessing their readiness, addressing operational gaps and implementing robust compliance programs, these entities can position themselves to meet NERC’s standards effectively.

Early preparation not only ensures compliance but also fosters a more resilient and secure grid as renewable energy continues to grow in prominence. As the energy industry evolves, adhering to NERC’s regulations is not merely a regulatory obligation — it is a critical step toward supporting a sustainable and reliable energy future.

Did I mention not adhering to NERC’s regulations can result in fines and penalties up to $1 million a day per violation?

Terry Brinker is a 30-year industry professional with experience leading, facilitating and implementing improvements in power plant operations, control room operations, compliance and regulatory matters.

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ACORE Presses Congress to Order Improvements in TVA Planning, Oversight

The American Council on Renewable Energy (ACORE) says Congress could take steps to establish more comprehensive transmission and generation planning within the Tennessee Valley Authority. 

ACORE published a new report ahead of a Jan. 30 webinar, suggesting Congress ensure the TVA board of directors has access to outside expertise; order TVA to engage in comprehensive transmission planning; bring the utility under FERC jurisdiction; require more transparency; and investigate how it could best plan resources, transmission and interconnection. 

ACORE said projections of increasing load in the Tennessee Valley and TVA relying on imports to manage peak load mean it is time for Congress to consider modernizing the utility’s management. 

Jonathan Geldof, lead author of the report and senior manager of government affairs for ACORE’s Macro Grid Initiative, said that with TVA’s draft integrated resource plan laying out 30 possible portfolios, its board members — who are not required to have experience in the electric industry — seem ill equipped to determine the most realistic path. Geldof said Congress should ensure the board can access independent staff, like at a state public service commission, or use an Independent Market Monitor, akin to those in RTOs, to get advice. 

The webinar occurred a day before TVA CEO Jeff Lyash announced his retirement after about six years with the federal utility. (See related story, TVA CEO Jeff Lyash Announces Plans to Retire.) 

TVA is conducting integrated resource planning through 2035. The draft IRP estimates it will need 9 to 26 GW in new firm capacity, resulting in a 75 to 90% reduction in carbon emissions from a 2005 peak. 

In its report, ACORE said the draft IRP is so broad that it could “serve to justify whatever action TVA chooses to take.” It also said the utility’s board is “woefully ill equipped to provide the kind of feedback [that] would serve as a check on TVA.

“ACORE noted that with TVA set to reach its borrowing limit in the coming years, it’s an opportune time for Congress to condition funding increases on administrative improvements. 

Geldof said the valley is poised for data centers, including an expansion of Colossus, a supercomputer built by Elon Musk’s artificial intelligence startup, xAI. On the other hand, he said, TVA faces 7 GW of retirements over the next few years. 

“What all those scenarios have in common is that TVA is going to need a lot more generation in the coming years,” Geldof said. 

TVA recently set an all-time peak demand record of 35.3 GW on Jan. 22 during a cold snap in which systemwide temperatures averaged 11 degrees Fahrenheit. However, ACORE said TVA was only able to meet demand through 20% imported power. 

Integrated Transmission Planning

Additionally, TVA is undergoing an integrated transmission plan for the first time in its history. But Geldof said any ensuing transmission portfolio will not be as valuable as it could be unless it is planned in concert with the IRP. TVA is tackling the two under independent processes. 

“When you consider generation and transmission separately, that’s not really an integrated plan,” he said. 

Geldof said that like much of the Southeast, TVA also needs interregional transmission. He pointed out that while TVA was initiating rolling blackouts during the December 2022 winter storm, neighbor SPP was curtailing excess wind generation in its footprint. 

Congress should also order a relaxation of TVA’s “fence,” Geldof said, which suppresses competition. He was referring to a 1959 addition to the TVA Act that prohibits the utility from selling its electricity into wholesale markets outside of its territory and prohibits its local power companies from purchasing power from its neighbors. 

“They could open a ‘gate,’ to expand the metaphor … or they could take down the fence altogether,” Geldof said of Congress, though he added that large utilities in the valley would likely resist removal of the wheeling restriction. 

Southern Renewable Energy Association (SREA) Executive Director Simon Mahan said the group applied to be a stakeholder in TVA’s integrated transmission process but was denied and shut out of meetings. 

From what he can tell, Mahan said, TVA’s transmission planning is “radically different” than that of nearby MISO, where planners hold consistent public meetings, are available for discussion and do not gatekeep planning information. He said SREA is concerned that TVA is “just now stepping into” long-term, scenario-based transmission planning but is seemingly refusing help from those that have contributed to comprehensive planning in RTO footprints. 

“It’s a missed opportunity from public power to take feedback from some of the areas that have best practices and really kind of shut down those discussions before they get started,” Mahan said. 

Mahan also said the TVA board receives limited information and currently does not get the “gut check” that analysis from independent third parties provides. 

“It’s not that we’re criticizing the board for making bad decisions. It’s just that they are not given enough information to know, ‘Is this truly the best decision at the right time?’” he said.   

Maggie Shober, research director at the Southern Alliance for Clean Energy, said TVA should settle on the most probable path forward in an IRP instead of simply using its lowest-end and highest-end estimates, which have it installing anywhere between a few hundred megawatts and several gigawatts of solar capacity. 

“TVA’s past IRPs have been overly broad.” The public should reach out to the TVA and its board to urge more specific resource planning, she said. Many in TVA’s leadership come from C-suites in investor-owned utilities that are accustomed to meeting load growth with natural gas plants. Shober said it’s incumbent on her organization and others to “break them out of that.” 

Myra Sinnott, of solar developer Silicon Ranch, said more transparent oversight would make building generation in TVA easier. 

Sinnott said trying to develop in TVA is a “chaotic” process, with requirements continually changing with no clear indication. 

“It’s like Whac-A-Mole sometimes. … You feel a little hamstrung working in a black hole,” Sinnott said. “It tends to be a more complicated process working in TVA than in other regions. … It would be easier if things were a little more consistent.” 

ACORE’s panel, ‘TVA’s Transmission Troubles’ underway on Jan. 30 | ACORE

Finally, panelists agreed that the Trump administration’s efforts to bolster fossil fuels would not grind the clean energy transition to a halt or render renewable generation an unsafe bet. 

Mahan said TVA’s resource needs are coming fast through a combination of load growth and aging generation. He said scuttling renewable energy plans in favor of fossil fuel generation does not make economic sense and would strain the supply chain for natural gas components. 

“If we’re going to be building big stuff again on the load side, we have to have as many tools in our toolbox as possible,” he said. 

“I feel like the cow is already out of the barn,” Sinnott said. “It’s going to take a lot more than four years to slow it way down.” 

Shober said she thinks TVA has an overreliance on gas already given its current generation portfolio. She argued that TVA’s increasing reliance on gas will not help it become more reliable and could introduce volatility into rates through oscillating fuel prices. 

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WEIM Q4 Benefits Exceed $374M

CAISO’s Western Energy Imbalance Market (WEIM) provided participants $374.25 million in benefits during the fourth quarter of 2024, down about 4% from the same period a year earlier, according to an ISO report released Jan. 30.

Cumulative benefits since the 2014 launch of the WEIM grew by 31% in 2024, to $6.62 billion. Last year saw no new participants join the market, which includes balancing authority areas accounting for 80% of load in the Western Interconnection.

NV Energy earned the largest share of benefits at $73.08 million, followed by the Balancing Authority of Northern California ($57.99 million), PacifiCorp ($46.58 million) and Los Angeles Department of Water and Power ($34.21 million).

CAISO’s benefits fell by half to $12.65 million, and the ISO was by far the market’s largest exporter (1,060,806 MWh) and importer (877,127 MWh). PacifiCorp came in second in both categories, with its East and West BAAs exporting a combined 839,781 MWh and importing 540,163 MWh.

The ISO was also the location of the largest volume of wheel-throughs (814,970 MWh), followed by the Western Area Power Administration-Desert Southwest region (401,898 MWh) and Arizona Public Service (356,176 MWh). WEIM members gain no financial benefit from facilitating wheel-throughs, with only the sink and source benefiting.

Vancouver, Canada-based Powerex earned the smallest share of benefits, at $840,000, down 98% year-over year. The company’s imports fell by 73%, to 336,184 MWh, while its exports rose 25-fold to 16,902 MWh. Powerex will withdraw from the WEIM after confirming last month that it plans to join SPP’s Markets+, although no date for the changeover has been announced. (See Powerex Commits to Funding, Joining SPP’s Markets+.)

The report said WEIM operations prevented curtailment of 30,462 MWh of renewable generation during the fourth quarter, helping to avoid the emission of 13,038 metric tons of CO2. The ISO estimates the market has been responsible for reducing carbon emissions by 1,043,034 MT since tracking began in 2015.

In a press release accompanying the report, CAISO said the benefits “emphasize the value of the ISO’s Extended Day-Ahead Market (EDAM), which promises to further build upon the benefits of WEIM for participants in the day-ahead market, where the vast majority of energy trading occurs.”

The ISO expects to launch the EDAM in 2026 and noted that WEIM members PacifiCorp and Portland General Electric have already begun onboarding activities to participate in that market.

The WEIM currently has 22 participants, including the ISO, but it is likely to eventually lose a portion of those to Markets+, which SPP plans to launch in 2027.

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Day-ahead Seams Issues Could Take Years to Resolve, BPA Staff Says

The Bonneville Power Administration would have to strike several types of agreements, many of which are complex and could take years to implement, to tackle seams that could arise if BPA joins a day-ahead market, agency staff said during a workshop Jan. 30. 

BPA has generation and load all over the Pacific Northwest that will be impacted by market seams irrespective of whether the agency chooses to join SPP’s Markets+ or CAISO’s Extended Day-Ahead Market (EDAM). With 38 balancing authorities and over 30 transmission service providers, the Western interconnection is already complex, Todd Kochheiser, senior electrical engineer at BPA, said during a presentation on the seams issue. 

“Anybody that’s operated in the Pacific Northwest, either commercially or [in a] more traditional sense, knows that a lot of the BAAs in the Northwest are non-contiguous,” Kochheiser said. “They’re sort of stitched together using a collection of native transmission and third-party transmission service providers. It’s a fairly messy landscape when you look at it from that perspective.” 

BPA’s own BAA is similarly non-contiguous and located in six states while adjacent to 18 BAAs, Kochheiser noted. 

The creation of day-ahead markets and associated real-time markets “will change existing market and [reliability coordinator] footprints in the [Pacific Northwest] and introduce new seams on top of those that already exist,” a BPA staff presentation stated.  

For BPA, this means ensuring seams agreements and their implementation “address concerns that are unique and specific to Bonneville,” Kochheiser said. 

But getting there is tricky. BPA must strike complex agreements with multiple parties that can take years to negotiate and implement. Agreements between RTOs can range from 200 to 400 pages, according to the presentation. 

However, staff pointed out that BPA has experience negotiating agreements that can guide the agency. For example, the agency already has a Coordinated Transmission Agreement (CTA) with CAISO, Kochheiser said. 

Still, it took a long time to get BPA and CAISO to agree on terms for the existing CTA contract, and it took even longer to implement it, according to Kochheiser.  

“It probably took twice or three times longer to implement than it did to negotiate and sign it,” he said, adding that “signing an agreement isn’t the touchdown. You’re at the 50-yard line.” 

Proponents of both Markets+ and EDAM have each argued that their respective preferred market choice provides a better solution for resolving seams.  

‘Difficult Headache’

A study published in February 2024 by the Western Power Trading Forum (WPTF) and Portland, Ore.-based Public Generating Pool found that a seam between EDAM and Markets+ likely would create challenges beyond those seen at the boundaries of the full RTOs in the Eastern U.S., given that each market still would contain operating seams within them.  

Fred Heutte, a senior policy analyst at the Northwest Energy Coalition (NWEC), has pointed to this study to argue that, given BPA’s size, the agency’s positions would be even more complicated if it joins Markets+ while many of its neighbors join EDAM because both markets effectively would be running on top of its balancing authority area.  

Heutte reiterated those concerns during the Jan. 30 workshop, saying splitting the West into two major markets will “be a permanent, expensive, difficult headache, just on the agreement side.” 

Actual implementation will not be any easier, Heutte said. There’s a risk that seams agreements cannot identify unforeseen issues, “and we see distortion in the market system operation that costs a lot of money and a lot of time.” 

“There’s been a sort of free-floating thing ‘Oh, we can just deal with this with the seams agreement.’ It’s not going to be so easy, and it’s going to be expensive,” Heutte added. 

But proponents of Markets+ have a different view. For example, Jeff Spires, director of power at Powerex, argued in September that Markets+ provides a much more equitable solution to tackling market seams than EDAM. Spires warned about joining EDAM, saying participants would be subject to the whims of CAISO and its purported preference toward California. 

During the Jan. 30 workshop, Laura Trolese with The Energy Authority said she understands the concerns about BPA joining Markets+ as it “might seem like it’s creating many more seams than if BPA were to join EDAM.” However, she added it appears that EDAM still has “a lot of seams that are pretty complex.” 

Libby Kirby, BPA’s market initiatives policy lead, said BPA is not solely responsible for creating seams. 

“The decision of all of us ultimately resulting in two markets creates an additional seam,” Kirby said. “It is not only BPA that has made a decision. I want to make sure that’s clear.” 

BPA has said it will issue a draft day-ahead market decision in March and a final decision in May. 

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TVA CEO Jeff Lyash Announces Plans to Retire

Tennessee Valley Authority CEO Jeff Lyash announced plans to retire “no later than the end of the fiscal year” after running the federal power authority for nearly six years.

“For the past six years, it’s been my privilege to serve with an experienced, talented team at TVA,” said Lyash. “TVA truly is a special place — created more than 90 years ago to improve the quality of life for more than 10 million people across this region. That mission of service continues to be our focus today.”

President Donald Trump criticized Lyash’s high salary back in his first term and the announcement comes less than two weeks into his second, but TVA’s press release was a standard retirement announcement and the end of the fiscal year means he could stay on until this fall. TVA is not taxpayer funded and gets its revenue from power sales.

“I grew up in the small coal-mining town of Shamokin, Pennsylvania, and I cannot think of a better place than TVA to close out my career serving people just like those in my hometown,” Lyash said. “While I’m looking forward to my next chapter, spending more time with family, grandchildren, and friends, I will miss our TVA team and the relationships we’ve built across this region.”

Before joining TVA, Lyash was the CEO of Ontario Power Generation and worked for years at Duke Energy and Progress Energy.

Lyash was appointed to the job in April 2019 and since has run the country’s largest public utility with a focus on building strong partnerships, including with the TVA region’s 153 local power companies, and managing sustained growth.

“Jeff’s knowledge and experience make him one of the top leaders in the energy industry,” said TVA Board Chair Joe Ritch. “Jeff has done more than lead one of the nation’s top power providers, he has helped drive an industry forward. His vision has positioned TVA well for the future, and he has built a legacy that will endure.”

TVA has below average electricity rates and it has been meeting ever-growing demand, with more than 3,500 MW of new generation under construction or online as of early 2025. The authority saw its all-time peak this January when demand hit 35,319 MW.

Lyash positioned TVA to be a leader on new nuclear power, with the authority winning approval for an early site permit from the Nuclear Regulatory Commission to possibly build a small modular reactor. TVA is leading an application with 11 industry partners and the state of Tennessee for an $800 million grant from the U.S. Department of Energy to build that SMR.

“Nuclear is the most reliable and efficient energy the world has ever known, and TVA is uniquely positioned to help drive this forward,” Lyash said. “Advanced nuclear technologies will play a critical role in our region and nation’s drive towards great energy security.”

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FERC Approves Annual Megawatt Cap for MISO Interconnection Queue

FERC has given MISO an all-clear to cap project hopefuls lining up for its overflowing generator interconnection queue at 50% of the RTO’s peak load.

FERC said MISO’s plan to impose a yearly cap of 50% of the non-coincident peak per study region is fair considering the footprint’s 309-GW, backlogged interconnection queue (ER25-507). The commission said in the Jan. 30 order that the cap “will allow MISO to conduct its study cycles more effectively… which will ultimately benefit interconnection customers.”

The megawatt cap would take effect beginning with the grid operator’s 2025 cycle of queue submissions.

MISO late last year made a second attempt to instate a megawatt cap on its annual queue cycles after FERC rejected MISO’s first attempt based on concerns over too many cap exemptions, the formula to establish the cap being unrealistic and potential resource adequacy deficits from limiting new generation onto the grid. (See MISO Queue MW Cap to be Filed Sans Regulator Exemption for RA Generation Projects; MISO Stakeholders Debate Usefulness of MW Queue Cap Pending Before FERC.)

With the cap in place, MISO said it will reopen acceptance of a new queue cycle at the end of this year. MISO had paused processing new queue cycles for more than a year and skipped a 2024 cycle altogether. (See MISO Unveils Later Timeline for Queue Processing Restart.)

MISO said a jump in interconnection requests beginning in 2020 has made it nearly impossible to create accurate models to study the new interconnections.

It fielded 52.4 GW of requests in 2020, 76.8 GW in 2021, and 170.8 GW in 2022. The queue currently contains nearly 1,700 interconnection requests totaling about 309 GW. By comparison, MISO’s peak load holds at about 127 GW, and the footprint boasts a total 191 GW of functioning installed capacity.

FERC agreed with MISO that “the large number of interconnection requests submitted into MISO’s interconnection queue would cause MISO to make unrealistic modeling assumptions, producing study results with inaccurate network upgrade cost estimates.”

“Such inaccuracies, in turn, would drive withdrawals from the queue, further affecting study results and causing delays,” FERC wrote.

The commission said MISO’s 50% methodology is reasonable based on MISO’s explanation that it represents a cliff before studies begin showing that major transmission upgrades are necessary, which is “typically indicative of voltage collapse.” FERC also said MISO this time explained how the cap still would allow sufficient generation capacity to be developed to meet resource adequacy standards.

MISO has said that even with a cap in place, it could achieve a total 310-GW queue throughput through 2042.

“We agree with MISO that the proposed queue cap formula strikes a reasonable balance between limiting the volume of requests to a level that can be processed efficiently and avoiding unnecessary barriers to entry that will delay the development of the generation capacity needed to meet growing supply shortages within the MISO region,” FERC said.

FERC decided MISO’s thinning of cap exemptions was appropriate and took care of concerns that MISO would have “unbounded” exceptions to the cap. It disagreed with MISO South regulators that removal of an exemption for projects deemed necessities by state public service commissions treads on states’ authority. FERC said if a public utility wants to modify its generator interconnection procedures on file, it must file with FERC.

Exemptions to the cap now are limited to generators with provisional generator interconnection agreements; generators seeking to replace retiring counterparts and in need of extra interconnection service; and those generators wanting to convert their unguaranteed energy resource interconnection service with the higher-quality network resource interconnection service.

FERC dismissed clean energy groups’ concerns that the cap method doesn’t feature a “first-ready, first-served” approach for generation projects. The commission said projects entering the queue still must meet MISO’s commercial readiness requirements to advance into the queue. It also said MISO’s recently raised fees, automatic withdraw penalties and requirements that developers show proof they secured land should winnow out speculative projects. FERC declined to consider Shell Energy’s recommendation that MISO impose a per-developer limit on project submission based on similar reasoning.

FERC also rejected some stakeholders’ arguments that the cap isn’t reasonable because it didn’t resemble approved caps like CAISO’s and wasn’t limited to a specific amount of time like SPP’s. It said it wouldn’t go down the road of deciding whether the cap was “more or less reasonable” than other possible rate designs.

“MISO, CAISO, and SPP have chosen to address interconnection queue management problems caused by an overwhelming number of interconnection requests through different approaches based, in part, on regional needs and characteristics,” the commission said, while pointing out that MISO has committed to reviewing the effectiveness at the cap in about three years.

The commission refused utilities and MISO South regulators’ recommendation that FERC tie approval of the cap to a resource adequacy express lane MISO is working to build into the queue, saying the future filing is a separate issue and not yet up for consideration. (See Generation Developers Ask for Scoring System on MISO Queue Fast Track.)

However, Commissioner Mark Christie wrote separately to encourage MISO to try again at developing exceptions to the cap for generation facilities that are labelled indispensable to resource adequacy by public service commissions. He said FERC “wrongly” rejected exemptions for state-designated generators in MISO’s first filing.

Christie said he was “disappointed in MISO’s failure to include a state exemption in its second filing, as the membership of the commission has changed significantly since last January and already has shown much more acknowledgement of the critically important role played by state utility regulators in ensuring reliable power to their states’ consumers.”

“MISO should have stuck to its guns and vigorously restated its reasons for including a state exemption,” Christie wrote.

While FERC said it was in favor of MISO’s cap, it encouraged the RTO to “continue considering other avenues to manage its interconnection queue” and said MISO’s efforts to automate its studies appear promising.

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Shell Quits Atlantic Shores Offshore Wind Project in NJ

One of the partners behind New Jersey’s Atlantic Shores Offshore Wind has bailed out of the long-running project, taking a billion-dollar impairment in the process. 

Shell announced the news Jan. 30 with its fourth-quarter 2024 earnings results. 

The offshore wind project was not specifically mentioned in material prepared for investors, or in prepared remarks by the CEO and CFO. Instead, the company referred to the $996 million in impairment charges “mainly relating to renewable generation assets in North America.” 

Similarly, in its first-quarter 2024 reporting, Shell offered few details about its divestment from SouthCoast Wind, off the Massachusetts coast. 

Shell New Energies US had partnered with Ocean Winds North America on SouthCoast and with EDF-RE Offshore Development on Atlantic Shores. Ocean Winds has continued with SouthCoast since Shell’s departure.  

In a Jan. 30 statement, Atlantic Shores said it, too, will continue working to deliver the project. 

“Business plans, projects, portfolio projections and scopes evolve over time — and as expected for large, capital-intensive infrastructure projects like ours, our shareholders have always prepared long-term strategies that contemplate multiple scenarios that enable Atlantic Shores to reach its full potential,” the company said. 

Both projects have secured their key federal permits, which will provide at least short-term protection from the Trump administration’s attempts to halt offshore wind development in U.S. waters, which include a freeze on leasing. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

But under Trump’s Day 1 executive order, Atlantic Shores and SouthCoast are subject to a review that could result in their leases being amended or terminated. 

Furthermore, Atlantic Shores and SouthCoast both have critical gaps in their balance sheets. 

Atlantic Shores won a 1,510-MW contract from New Jersey in June 2021. But in July 2024, it submitted a bid in New Jersey’s fourth solicitation for two projects — one new, but one a rebid of the original project, presumably with higher costs attached. (See 3 OSW Proposals Submitted to NJ.) 

New Jersey still has not finalized contracts from that solicitation. 

Massachusetts and Rhode Island selected SouthCoast in early September in a three-state solicitation but have not been able to complete negotiations on power purchase agreements. They are now targeting a March 31 execution date — a full year after developers submitted bids. 

New Jersey has some of the largest offshore wind goals in the U.S., and its shore region has been the scene of some of the loudest opposition to development of offshore wind farms. Opponents cheered in late 2023 as Ørsted abruptly canceled the Ocean Wind 1 and 2 projects it had contracted with the state. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) 

And opponents cheered again as word spread of Shell’s pullout. 

“Another major blow to the offshore wind scam! Shell is pulling out of the Atlantic Shores project, writing off nearly $1 billion as the industry collapses under its own weight,” U.S. Rep. Jeff Van Drew (R), who represents much of the shore region, posted Jan. 30 on X. 

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‘Green’ Steel Mill Gets Financial Boost from CEC Grant

San Diego-based Pacific Steel Group (PSG) is planning a zero-carbon-emission steel mill near Mojave, Calif., in a first-of-a-kind project that will set an example for industrial decarbonization.

While there have been other electric steel mills, the Mojave Micro Mill project would be the world’s first fully electric, zero-carbon-emission steel production facility, according to Lin Planchard, a utilities engineer with the California Energy Commission. Electricity for the steel plant will come from on-site solar and the grid, and the plant will be equipped with a carbon-capture system.

The $630 million project will recycle steel to produce rebar for use in California’s construction industry. Currently, scrap metal from California is sent to facilities in Washington, Oregon, Utah, Arizona or even Asia for recycling and rebar production. The rebar then must be transported back to California.

“By building a new rebar mill, California can fill this gap in the market by localizing our scrap recycling and rebar production and thereby reducing emissions from transporting steel by approximately 118,000 tons per year,” Planchard said.

The CEC on Jan. 21 approved a $14 million grant to PSG for long-duration energy storage (LDES) to support about 50 MW of solar power at the steel plant. The storage will be connected to the solar photovoltaic system and a microgrid.

“It will optimize the use of on-site solar energy, support critical operations during outages and contribute to the overall energy management strategy of the facility,” according to the grant request form.

The 32 MWh LDES system will be non-lithium-ion; PSG is exploring multiple chemistries including zinc that are capable of discharging for at least eight hours, company spokeswoman Michelle D’Alonzo told NetZero Insider.

D’Alonzo said the Mojave Micro Mill will electrify processes that traditionally use natural gas. Steel will be recycled at the facility by melting it in an electric arc furnace.

Nearly 90% of the mill’s carbon emissions, which already are low, will be captured, according to a project fact sheet. Captured carbon dioxide will be purified, liquified and used in applications that require CO2.

Kern County certified an environmental impact report and a statement of overriding consideration for the project in March 2024. PSG expects to break ground on the steel mill in March and start operations in early 2027.

When completed, the Mojave Micro Mill would be the only operational steel mill in the state, which hasn’t seen a new steel mill in more than 50 years.

“I love this project,” CEC Chair David Hochschild said during the Jan. 21 meeting. “This marries many of the things that we’re trying to do together: industrial decarbonization, new manufacturing, assembly and recycling facilities, and cutting-edge clean energy technologies and grid reliability.”

In addition to the CEC grant award, the Mojave Micro Mill got a boost Jan. 16 when Generate Capital announced a $200 million secured loan to PSG for the project. Generate Capital is a San Francisco-based sustainable infrastructure investment firm.

“PSG’s innovative approach demonstrates how we can significantly reduce emissions in the industrial sector while meeting the rising demand for greener building materials economically,” Generate Capital President Bill Sonneborn said in a statement.

As the most widely used metal in the world, steel is one of the largest single sources of carbon emissions, accounting for 7% of global and almost 30% of industrial emissions, Generate said in a release.

“Decarbonizing the steel market, therefore, is vital to achieving the transition to net-zero emissions,” the investment firm said.

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Texas RE Calls ITCS Recommendations ‘Very High Level’

Fulfilling the recommendations from NERC’s Interregional Transfer Capability Study will not be a simple task, a speaker said at a webinar Jan. 29 hosted by the Texas Reliability Entity. 

“I don’t expect that we’re going to have a mandate from Congress to build anything at a certain level, particularly with the administration we have now, but I don’t know for sure. Nobody does,” Mark Henry, Texas RE’s chief engineer and director of reliability outreach, said at the regional entity’s “Talk with Texas RE.” 

Henry took part in writing the ITCS as part of the ERO Executive Leadership Group; he told attendees that industry stakeholders from Texas also contributed through the ITCS Advisory Group. 

NERC filed the ITCS with FERC in November 2024 as ordered by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.) The commission posted the report for a 12-month public comment period Nov. 26 and will submit a report on its conclusions to Congress after the comment period concludes, along with recommendations for statutory changes, if any (AD25-4). 

The three parts of the ITCS submitted last year include a transfer capability analysis summing up the current transfer capabilities between transmission planning regions in North America, recommendations for prudent additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability. A fourth document is planned in the second quarter of 2025 covering transfer capabilities and prudent additions from the U.S. to Canada and between Canadian provinces. 

NERC recommended 35 GW of additional transfer capability across the North American grid, while noting that it still was not possible to resolve all the potential energy deficiencies identified over the 10 years of the study. 

Henry observed that these additions included a significant amount of added capacity — 14,100 MW — in ERCOT across the existing SPP-South connection (4,100 MW) and two new connections to Front Range (5,700 MW) and MISO-South (4,300 MW). These still hypothetical new connections do not represent any specific projects or locations, he said, because identifying such opportunities would be outside the ITCS’ scope. 

Henry emphasized that the ITCS should be seen as a jumping-off point for further studies and planning work, rather than a blueprint for solving the grid’s transmission problems. He pointed out that the study only posited transfer additions between neighboring regions and added that even if such additions are constructed, there is no guarantee the regions will be able to use the full capacity, because severe weather or other conditions that lead to energy shortfalls in one region could easily affect a nearby one. 

In addition, Henry reminded listeners of the constraints imposed on the team. The FRA set NERC a deadline of just 18 months to complete the first-of-its-kind study, and the ERO had to choose its focus carefully to ensure it could finish on time. 

“With the time and resources allowed for this, we kept this at a very, very high level,” Henry said. “The first part of meeting and maintaining is just to recognize that you’re going to have to do a lot of additional work. You’re going to have to study the system in more detail and identify where you might actually accomplish some of these transfers.” 

Henry promised that NERC will continue to study the topics raised in the ITCS and refine its findings. He also urged listeners to “offer some insight” and reactions to the report through FERC’s comment process.