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November 15, 2024

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LPO Announces $1.52B Loan to Restart Palisades Nuclear Plant

Michigan’s 800-MW Palisades nuclear power plant, which was decommissioned in 2022, could become the first nuclear plant in the U.S. to be restarted, helped by a $1.52 billion loan from the federal Department of Energy’s Loan Programs Office (LPO). 

The agency’s conditional commitment for the loan to Florida-based Holtec International would also be the first offered under the Energy Infrastructure Reinvestment program, which is funded by the Inflation Reduction Act, according to the March 27 announcement. The program aims to “finance projects that retool, repower, repurpose or replace energy infrastructure that has ceased operation,” LPO said. 

Once restarted, the plant would protect “600 good-paying, high-skill jobs and clean, reliable power for 800,000 homes,” Michigan Gov. Gretchen Whitmer said in a statement. “Palisades will be the first successfully restarted nuclear power plant in American history, driving $363 million of regional economic impact and helping Michigan lead the future of clean energy.” 

Whitmer has been pushing for the Palisades restart, and the Michigan Legislature last year provided $150 million in state funding for the project. 

Holtec also intends to build two small modular reactors on the site, according to LPO. 

Holtec CEO Kris Singh called the loan “a triumph for the United States in our collective pursuit of a clean and dependable energy future. … The repowering of Palisades will restore safe, around-the-clock generation to hundreds of thousands of households, businesses and manufacturers.” 

LPO expects the project to avoid close to 4.5 million tons of carbon dioxide emissions per year and 111 million tons of CO2 in 25 years of operation — the equivalent of taking 970,000 gasoline-powered cars off the road per year. 

Holtec has signed two long-term power purchase agreements with two electric cooperatives for the plant’s output. Wolverine Power Cooperative provides electricity for five co-ops in Michigan, and Hoosier Energy, an alliance of 18 co-ops, serves customers in Indiana and Illinois. 

Speaking at an industry conference last year, Wolverine COO Zach Anderson said the Palisades PPA met all the co-op’s top priorities for new power. “It’s a long-term, stable, 100% carbon-free, 24/7 power supply, so it’s decarbonized and reliable,” as well as cost competitive, Anderson said. 

Reactions

Doug True, senior vice president and chief nuclear officer at the Nuclear Energy Institute, said the loan signals the Biden administration’s “willingness to explore opportunities to preserve our existing nuclear fleet,” as well as support for “the pivotal role nuclear energy plays in our nation’s clean energy future.” 

Patrick White, research director at the Nuclear Innovation Alliance, sees the loan as an indication of LPO’s willingness to fund more nuclear projects going forward. The office previously helped fund the long-delayed and costly Vogtle Units 3 and 4 in Georgia with $12 billion in loans. 

But White cautioned that the restart likely will be a one-off project, rather than the first of many. Repowering Palisades is not “something that’s generally applicable to plants that have been decommissioned,” White said in an interview with RTO Insider. 

“I believe when Palisades was being kind of shut down and moving from its previous life in operation into decommissioning, there was an idea that the plant [might] be restarted,” he said. “So, the owner took a lot of steps to make sure the plant was kept in essentially ready-to-go condition.” 

In a statement provided by the American Nuclear Society, Keith Drudy, a Michigan native and nuclear engineer who worked on Vogtle 3 and 4, said, “Restarting Palisades from its current state is really no more complicated than returning from a significant maintenance outage ― something that nuclear plants do every 18 to 24 months. The nuclear industry knows how to do maintenance, implement upgrades and enhancements, and … keep these plants running for 60 years and beyond. 

“The unique challenge here is that, until now, there has been no regulatory process or precedent for declaring that a licensee intends to cease operations of a plant and then return that plant back to operating status from a regulatory perspective,” Drudy said. “That process is now being developed, and I have no doubt that the [Nuclear Regulatory Commission] and other impacted regulatory agencies can and will ensure the restart of these units meets all standards and requirements.” 

Holtec began the relicensing process for Palisades with the NRC in October 2023 and is targeting a final decision by the end of 2025, according to Patrick O’Brien, the company’s director of government affairs and communication.  

Anderson said Wolverine expects to start receiving power from the plant by 2027. 

Holtec’s History

Located on the southeast shore of Lake Michigan, the Palisades nuclear plant began operation in 1971. It was originally owned by CMS Energy and its primary utility, Consumers Energy, and was acquired by Entergy in 2007. 

Consumers continued to buy power from the plant, but changing market conditions led to Entergy’s decision to close Palisades in 2022, citing the availability of cheaper power from renewables and natural gas. Power from the plant could cost 57% more than other generation, according to a report by Bridge Michigan. 

Even before the plant ceased operation in May 2022 and was sold to Holtec for decommissioning, Michigan officials began looking at options for restarting it. Holtec made an unsuccessful application for funding from DOE’s Civil Nuclear Credit Program, which received $6 billion in funding from the Infrastructure Investment and Jobs Act to help plants at risk of closure. 

The company began its application process with LPO in 2023. The announcement of the conditional commitment begins a negotiation process under which Holtec will have to reach specific technical and financial milestones before the loan is finalized. 

But the decision could prove controversial for a number of reasons, first and foremost the company’s history of financial missteps. In January, Holtec agreed to a $5 million settlement with New Jersey to avoid criminal prosecution over allegations that it provided inaccurate information to obtain $1 million in state tax credits in 2018. While accepting the settlement, the company denied any wrongdoing. 

Holtec has a large campus in Camden. As part of the settlement, it agreed to hire a state-approved independent reviewer to monitor any future applications it makes for New Jersey state benefits. 

The company was also barred from doing business with the Tennessee Valley Authority for 60 days in 2010, after it was implicated in a scandal involving kickbacks to a TVA official from a Holtec contractor, according to a report from InsiderNJ. 

Another concern is that Holtec’s business is focused on decommissioning nuclear plants; it has never actually operated one. 

O’Brien acknowledged that the company’s lack of operational experience is “generally true. … But with the decommissioning, we retained qualified staff, including operators, maintenance, radiation protection and other craft [workers] that have years of experience in plant operations. The Palisades team is comprised of a hard-working team that safely operated the facility for over 50 years. In addition, we will be partnering with a licensed operator for restart.”

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SERC Board of Directors/Members Meeting Briefs: March 27, 2024

Phillips Praises SERC for Leadership in ERO

NASHVILLE, Tenn. — In remarks to SERC Reliability’s Annual Members Meeting on March 27, FERC Chair Willie Phillips applauded attendees for their work as “the tip of the spear” in the struggle to maintain grid reliability. 

Phillips, who attended the meeting along with FERC Chief of Staff Ronan Gulstone and Critical Infrastructure and Resilience Adviser Kal Ayoub, said he originally planned to remind members they are critical to advancing the work of the ERO Enterprise and encourage them to pursue greater efforts. But he continued that “after hearing your leadership talk [over the last two days], you don’t need to hear that from me.” 

Phillips explained that it was clear that SERC’s members understood their role, along with the problems and opportunities facing the grid. He praised the regional entity for repeatedly showing its willingness to participate in ERO efforts and urged it to continue its leadership as the industry engages rapidly evolving threats like extreme weather and cyber and physical attacks. 

“I was in Brussels just about a week and a half ago, and I met with many of … our colleagues in Europe. And I’m telling you, we are the envy of the world with our fuel resource mix, our grid [and] our reliability regime. But we have more work to do,” Phillips said. “At FERC we’re focused on that work. … You’ve heard me talk about my priorities a million times: reliability, transmission reform [and] environmental justice. … Those are my three top priorities for 2024.” 

FERC Chair Willie Phillips (left) talks with SERC CEO Jason Blake. | © RTO Insider LLC

Members Approve New Directors

Also on the agenda at SERC’s Members meeting — which preceded the quarterly Board of Directors meeting — was the election of directors to serve two-year terms beginning June 1 and ending May 31, 2026. Nominating and Governance Committee Chair Tim Lyons presented the slate of director nominees, all of whom were approved: 

    • Cooperative sector: Denver York, East Kentucky Power Cooperative 
    • Federal-state sector: Vicky Budreau, Santee Cooper 
    • Investor-owned utility sector: Lee Xanthakos, Dominion Energy South Carolina, and Beth McFarland, LG&E and KU Energy 
    • Marketer sector: Eric Laverty, ACES 
    • Merchant electricity sector: Venona Greaff, Occidental Chemical 
    • Municipal sector: Doug Lego, MEAG Power 
    • Independent: Lonni Dieck 

Most of the directors are returning after a previous term, but York, McFarland and Budreau will step into the seats held, respectively, by Roger Clark of Associated Electric Cooperative Inc., Adrianne Collins of Southern Co. and Virgil Hobbes of the Southeastern Power Administration. 

In addition, members approved Paul McGlynn of PJM to replace Stacy Dochoda, formerly of the Florida Reliability Coordinating Council, as the RTO/ISO/Reliability Coordinator sector representative. Dochoda joined the board last year for a term to end May 31, 2025, but retired effective March 27. (See “Members Approve Director Slate,” SERC Board of Directors/Members Briefs: March 29, 2023.) As a result, McGlynn will serve out the remainder of her term. 

SERC’s directors passed a resolution honoring Dochoda at their meeting, along with similar resolutions for former Director Manny Miranda — who stepped down from the board last year — and Barbara Ecton, who recently stepped down as senior executive assistant to join the office of the president at Duke University. 

Budget Set to Grow in 2025

The board also approved SERC’s draft 2025 business plan and budget, which will be presented to NERC. 

SERC’s Finance and Audit Committee will continue to review the draft and submit a final package to the board at its June meeting, following which it will be submitted to FERC for approval along with the budgets for NERC and the other REs. 

CFO George Krogstie said in a presentation to members that next year’s budget is expected to grow by $3.3 million to $35.3 million, driven by rising costs in areas like personnel and rent for a new office the RE will move to in 2025. However, he emphasized that “there are no surprises” in the coming year’s budget. 

“We’ve been talking about all of these over the last couple of years; we knew our lease was expiring in January of 2025, [and] that rent was going to increase whether we stayed where we’re at or … relocated,” Krogstie said. “Fortunately, we found a really good facility to relocate [to]; that is going to bring us a lot more benefits to what we’re doing than what we currently have.” 

Krogstie also said that “a real success story” underlies the personnel costs, noting that the RE has been carrying a 95% vacancy rate for several years. Although personnel costs were under budget, the organization was understaffed. With SERC expanding its staff recently — Krogstie claimed a vacancy rate of less than 1% for the second half of 2023 — it will be better able to meet the challenges of the evolving grid, the CFO said. 

SERC’s remaining board meetings for 2024 will be held at its current office in Charlotte on June 12, Sept. 18 and Dec. 11. The next meeting of the RE’s members will take place March 26, 2025, in New Orleans. 

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Bumps on the Road to Net Zero Highlighted at EPSA Summit

WASHINGTON — While their net-zero emission targets might not kick in until the 2030s, the power industry already is dealing with the issues they create, panelists said at the Electric Power Supply Association’s Competitive Power Summit on March 26. 

New York has seen the Indian Point Nuclear Plant, its coal fleet and a number of peaking plants around New York City shut down in recent years, cutting a once-thick reserve margin to near the required target, NYISO CEO Rich Dewey said. With other thermal generation retirements expected in the rest of this decade, new supply is going to need to come online to replace them.

“I have grave concerns about the winters of 2030, 2031, 2032; that’s when we’re going to need to see some of that new supply to come online,” Dewey said. 

NYISO already has seen improvements in the speed of its interconnection queue, Dewey said, having embarked on changes before Order 2023 was issued last July. While that is less of a barrier, new development faces other issues.  

“So, we’ll solve the interconnection problem, but I’m not sure that there aren’t other problems right behind that,” Dewey said. 

For example, the state has made a big bet on offshore wind, but it faces higher interest rates and supply chain constraints, which are affecting projects all along the East Coast, he added. 

“Everybody kind of giggled when Rich said, ‘My concern is eight years away,’” said Competitive Power Ventures Senior Vice President Tom Rumsey. “If I started tomorrow, I couldn’t build him a combined cycle in that time frame. Right? You can’t. And that’s why he’s worried. I think people sort of think that it’s a three- to four-year process. It isn’t.” 

Construction takes about that long, but from conception through the regulatory process to actual construction makes the total time to build a new gas plant longer than eight years, he added. 

That ignores the politics around natural gas, as NYISO is looking for “dispatchable emissions-free resources,” for which it has coined the widely adopted acronym of “DERF.” 

NERC has placed policy as one issue that threatens reliability. CEO Jim Robb said at the conference that has started to change some minds. 

net zero

NERC CEO Jim Robb (left) and EPSA President Todd Snitchler | © RTO Insider LLC

“I think I read that New York has now either approved, or is considering approving, adding compression to some of the pipelines serving the state there,” Robb said. “So again, kind of counter to the political winds. So that’s great news, right? That we’re getting a little bit more acceptance of the importance of gas in the in the mix.” 

That comes after the “politically courageous” decision in California to extend the life of the Diablo Canyon Nuclear Plant after it started running into resource adequacy issues during heat waves, and the deal to keep the Everett Marine Terminal open, which is a vital source of LNG imports for New England in the winter, Robb said. (See Constellation Reaches Agreement to Keep Everett LNG Terminal Open.) 

ISO-NE has dealt with energy issues in the winter for 20 years; it was 2004 when it had “8 GW of natural gas generators call in sick one Monday and say, ‘We don’t have any fuel,’” CEO Gordon van Welie said. While the issue is longstanding, van Welie said some notable changes have occurred in the past couple of years. 

ISO-NE has developed a “probabilistic energy adequacy tool” to assess adequacy, van Welie said. “And that has given us a much better analytical framework for assessing these risks, both of the near term and the long term.”

That has led to conversations in New England about adding an “energy adequacy standard” to the common resource adequacy standard, he added. ISO-NE also has worked on capacity accreditation.That’s been happening around the country as other regions face similar issues, if not the same acute winter reliability threats. 

New England has moved forward on gas-electric coordination. But it still faces issues there, as fuel will continue to be important, though used much differently than today, van Welie said. Electrification is going to mean higher demand as other resources retire.

“The balancing energy source is going to be natural gas,” van Welie said. “And all the studies we’ve done, [and] studies I’ve looked at, show that the dynamic is [that] the average demand for gas is going to drop because of all the renewables on the system, but the peak demand is going to spike up.” 

That raises the question of how the market can solve that issue: If natural gas plants run rarely, it will be even less economic for them to get firm service from pipelines, van Welie said. To find the answer, he said the industry needs analytics to gauge how to use natural gas to balance a higher share of renewables. 

Texas is ahead of New England when it comes to renewables, though as the country’s largest producer of natural gas, it does not have the same issues, ERCOT CEO Pablo Vegas noted. He said he’s seen some of the same studies as van Welie, and he expects gas plants will run less overall but have much higher peak demands. 

The growth of solar in Texas has made it easier to meet those high peak demands in the summer, but ERCOT still can face tight conditions in the winter when that resource is far from peak production, Vegas said. 

While the state benefits from plentiful energy supplies, Texas’ role as an energy capital is contributing to large demand growth, as the oil and gas sector continues to electrify its operations.

“In the Permian area of Texas, we saw … a new set of load expectations that were far above what our historical plants anticipated for that area,” Vegas said. “And to put [that] into context, just in the next five, six years in the Permian area, we saw new load forecasts upwards of 25 GW.”

That’s the equivalent of adding another entire Dallas-Fort Worth area to the Texas grid in the next half a decade, he added. About half of the demand is expected to come from the oil and gas industry, with other sources of demand from new hydrogen production, manufacturing and cryptocurrency mining. 

While EPSA effectively was set up for firms that build natural gas plants, some of its members also are in the renewable development business, American Clean Power Association CEO Jason Grumet said. He noted that two-thirds of the renewables deployed last year were from firms that also own fossil and nuclear assets. 

ACP pushes for the transition to clean energy, but Grumet said the No. 1 priority for anyone who works in the energy industry is reliability.

“If we have interruptions of power supply, that … interrupts the trajectory of our energy policy goals, right?” Grumet said. “So, it is obviously not in the interest of the individual, nor is it in the interest of the policy debate.” 

ACP shares the same goals as much of the rest of the energy industry around changing the rules for permitting because, Grumet said, it’s needed for the U.S. to meet its net-zero goals. Permitting reform for “linear infrastructure” can help get renewables built and ensure they have the gas needed to balance them. 

“If you have any affinity to engineering or math, you’d say that we are not on target to achieve a zero-carbon grid in 11 years,” Grumet said. “I think people get confused when you tell the truth; they think you’re either being courageous, or you’re suggesting complacency. It’s just the truth.”

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Last Remaining Coal Resources in New England Set to Retire

Granite Shore Power has reached an agreement with EPA, the Sierra Club, and the Conservation Law Foundation to retire New England’s last coal plant by 2028, the company announced March 27.  

Along with the 482-MW Merrimack Station, the company agreed to retire Schiller Station, a 155-MW unit that can burn coal, by 2025. Both generators are in southern New Hampshire.  

“This historic victory is a testament to the strength and resolve of those who never wavered in the fight for their communities and future,” said Ben Jealous, Sierra Club executive director. 

Jealous applauded both the climate and public health benefits of retiring coal resources, noting that air pollution from coal significantly increases risks of asthma and heart disease in nearby communities. 

Granite Shore plans to replace both power plants with clean energy resources, including a large battery at the Schiller station site and co-located solar and storage at the Merrimack site.  

“The New Hampshire Seacoast is an area of high energy demand and through the repowering of Schiller Station, we will provide carbon-neutral power to support the businesses and families of New Hampshire,” said Granite Shore CEO Jim Andrews. “Our facilities are ideally situated near the infrastructure necessary to transition the region to the next generation of energy resources.” 

Climate and environmental organizations in the region have long advocated for closing New England’s remaining coal plants. Coal generation in the region has fallen dramatically over the past two decades. According to ISO-NE, coal accounted for just 0.5% of the region’s generation in 2023, compared to about 40% in 2000. The decline has coincided with a substantial increase in natural gas generation. 

“The transition that Granite Shore Power has announced is a testament to the continued commitment to invest and support the many needs of electricity consumers both today and in the years to come,” said Dan Dolan, president of the New England Power Generators Association. 

“As some older, less-efficient power generation gives way to newer sources, it is incumbent on industry and policymakers to continue the hard work to enhance the electricity market to get reliability, affordability and a clean energy future right,” Dolan added. 

In recent years, the writing has appeared on the wall for the region’s remaining coal plants. Schiller Station has not operated since summer 2020 but has not officially retired. Merrimack Station remains in operation but failed to win capacity supply obligations in the forward capacity auctions for the 2026-27 and 2027-28 procurement periods. (See FCA 17 Shows Clean Energy Boost, Endgame for Coal in New England.) 

Merrimack also exceeded federal emissions limits in a February 2023 stack test and has had to abort multiple attempts to retake the test over the past year. The New Hampshire Department of Environmental Services has said the plant is not in compliance with federal standards, which could make the facility subject to fines.  

“It was clear that this day was coming,” said Nathan Phillips, a member of the No Coal No Gas campaign and a professor of ecology at Boston University. “But yet, when you see them say it themselves, it’s still monumental … it’s a shock but not a surprise.” 

Phillips added that the announcement is “a shot in the arm to all of us to escalate our campaign to every other dirty peaker plant going forward.” 

The Sierra Club and the Conservation Law Foundation also emphasized their aim to retire all remaining fossil fuel generators in New England.  

“Now we must vigorously push for the phaseout of other polluting fuels like oil and gas,” said Tom Irwin, vice president of the Conservation Law Foundation in New Hampshire. “New England is positioned to be a leader in building a future where our energy comes from 100% clean sources, and fossil fuels no longer pollute the climate and threaten the health of our communities.” 

Along with the Merrimack and Schiller Stations, the Mystic Generation Station, a 1,413-MW combined-cycle plant, is set to retire in May. While the New England states have ambitious clean power goals for the coming decades, some energy officials have expressed concern about retirements outpacing deployment.  

“We cannot remove conventional generation before we stand up its replacement,” said Charles Dickerson, CEO of the Northeast Power Coordinating Council, at an event March 22. “We need to have renewable resources that we can control.” 

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BOEM Approves NY’s Sunrise Wind OSW Project

The U.S. Bureau of Ocean Energy Management has approved the Sunrise Wind offshore wind project sited off the end of Long Island, greenlighting a 924-MW project that could power 320,000 New York homes and become the state’s second offshore farm. 

BOEM’s approval March 26 comes about two weeks after the state’s — and the nation’s — first OSW project, the 130-MW South Fork Wind, began generating power. The state on Feb. 29 announced conditional contract awards to Sunrise Wind and the 810-MW Empire Wind project, which could be the next OSW projects to come online in the state. Together they would generate about one-fifth of the state’s 9-GW goal for 2035. (See First Large US Offshore Wind Farm Complete.) 

In the wake of the approval, known as a Record of Decision (ROD), Ørsted and Eversource — the two partners in Sunrise Wind — said they’ve taken a final investment decision and will move ahead. The two companies also developed South Fork Wind. 

“We are poised and ready to start constructing the transmission system to connect Sunrise Wind’s clean power to the New York electric grid,” said Joe Nolan, CEO of Eversource Energy. “We promised to put New Yorkers to work building the energy of the future, and now we’re ready to deliver on that promise.” 

The partners said in a release that the decision “precedes the anticipated approval of Sunrise Wind’s Construction and Operations Plan (COP)” in the summer. Ørsted in January agreed to acquire Eversource’s 50% ownership share in Sunrise Wind, though the company will lead the project’s onshore construction. 

The New York State Energy Research and Development Authority is finalizing agreements with Sunrise Wind for the project’s Offshore Wind Renewable Energy Certificates contract. Sunrise Wind had planned to cancel its previous contract as construction costs increased, and the developer said the project had become untenable under the financing offered in the earlier contract. (See Sunrise Wind, Empire Wind Tapped for New OSW Contracts.) 

Capacity Reduction

BOEM said it reduced the size of the project, which is located 26 nautical miles east of Montauk and 14 nautical miles off Rhode Island, from 1,024 MW, shrinking the capacity by about 10% as well as cutting the number of turbines to 84, in response to stakeholder and public comments. 

The reduced project would meet the state’s capacity requirement, “would protect the environment” and would satisfy more than 10% of the goals of the Climate Leadership and Community Protection Act (CLCPA), which was established to combat climate change, according to BOEM’s ROD. 

The agency’s decision includes measures aimed at “avoiding, minimizing and mitigating” effects of the construction and operation of the project, and includes “a commitment by Sunrise Wind LLC to establishing fishery mitigation funds to compensate commercial and for-hire recreational fishers for any losses directly arising from the project.” 

As part of its project, Sunrise Wind pledged to create a new operations and maintenance hub in Port Jefferson that would be a “key anchor point for New York’s offshore wind future and use facilities in the state’s capital region to fabricate “key components” for the foundations and turbines. 

BOEM Director Elizabeth Klein said the agency’s approval — the Department of the Interior’s seventh — is another step toward reaching President Biden’s goal of 30 GW of OSW capacity by 2030. 

“Through constructive, broad-based engagement, we are navigating potential conflicts and advancing the responsible growth of offshore wind. As we propel this industry forward, we eagerly anticipate further cooperation and progress with our partners,” she said in a release. 

The Sierra Club of Massachusetts welcomed the approval, saying it would bring the region “closer to a future where every home in the northeast is powered by clean energy.”

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CEC, Caltrans Solicit Feedback on New Program for EV Charger Repair

The California Energy Commission and Department of Transportation (Caltrans) are seeking feedback on the structure of the state’s Electric Vehicle Charger Reliability and Accessibility Accelerator (EVC RAA) grant program, designed to replace and repair more than 1,300 chargers at 300 sites statewide. 

In January, the U.S. Department of Transportation awarded Caltrans $63.7 million of Infrastructure Investment and Jobs Act funds to develop the program, which sets aside 10% of funds from the National Electric Vehicle Infrastructure (NEVI) Formula Program; $58.4 million is available for solicitation, with the remainder being used for CEC and Caltrans administrative costs. 

“The purpose of the EVC RAA program is to repair or replace broken — or not operational — publicly accessible electric vehicle chargers to improve the reliability and accessibility of the existing network,” Emily Belding, zero-emission vehicle infrastructure coordinator at Caltrans, said at a joint CEC and Caltrans presolicitation workshop March 27. 

Stations eligible for funding are those listed as “temporarily unavailable” as of Oct. 11, 2023, by the Federal Highway Administration, Belding said. There are more than 3,500 eligible ports in California, and EVC RAA funding will support the repair or replacement of more than 1,300. 

Each site must be NEVI-compliant, meaning it should contain a minimum of four Level 2 or DC fast-charging ports. At sites located within 1 mile of a designated alternative fuel corridor, chargers must deliver at least 150 kWh of power. (See Calif. Looks to Streamline Process for Issuing NEVI Funds.)  

Additionally, EVC RAA is part of the federal Justice40 Initiative, meaning at least 40% of eligible ports must be in communities marginalized by underinvestment or overburdened by pollution, and a minimum of 50% of deployed chargers must be in disadvantaged or low-income communities in general. 

For replacement projects, CEC is estimating it will cost $12,500 for Level 2 ports — those able to offer at least 6 kW of continuous power delivery — and $300,000 for DCFCs, said Ben De Alba, zero-emission vehicle infrastructure specialist at CEC. The agency will not award more than the cost per port for replacement projects. 

Eligible applicants must be private entities, including EV charging and service providers, third-party installers, and charging station operators. Ineligible projects include those for which costs would exceed the cost to replace the broken or nonoperational equipment, EV chargers currently under warranty or an existing service-level agreement, and those that don’t meet the definition of “publicly available.” 

Projects must be completed in 12 months, and because of the limited time frame, funds cannot be used for operations and maintenance. Chargers must maintain an average uptime of 97% over five years, and applicants are required to submit a five-year operations and maintenance plan.  

CEC and Caltrans will score each application on factors including project readiness, the benefit to Justice40 communities and cost effectiveness. 

John Schott, director of public-private partnerships with ChargePoint, questioned the decision to limit eligibility for funds to private entities. 

“If you look at the list of eligible charging stations, there definitely are some public entities and some cities and towns who have quite a number of broken chargers that I know they’re interested in fixing. So, if they weren’t able to find either an installer, network provider or one of the identified eligible applicants, that certainly might hinder their ability to take advantage of this funding,” Schott said. “I understand your interest in trying to minimize the scope and not have tons of individual grant awards to manage. But I think in the spirit of this federal solicitation and really trying to fix those broken chargers out there, I would respectfully request that you would reconsider that.” 

Comments on the EVC RAA program structure are due April 15. The solicitation is expected to be released in August, and applications are due in September.  

“This has been a very complex program from the start,” De Alba said. “We’re moving as quickly as we can to award the funds and get these stations repaired or replaced.” 

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EIA: Western Hydro Output Hit 22-year Low Last Year

Despite record winter precipitation in California, hydroelectric generation in the Western U.S. fell to a 22-year low in the 2022/23 water year, largely due to droughts in Washington and Oregon, a new analysis found. 

Since the 2016/17 water year, Western hydropower generation has been diminishing except for a 13% uptick in 2021/22, according to a March 26 report from the U.S. Energy Information Administration (EIA). A water year runs from Oct. 1 to Sept. 30. 

The 2022/23 water year resumed the downward trend, with an 11% drop compared to the previous year. The 141.6 million MWh of Western hydropower generation in 2022/23 was the lowest since 2001. 

Previously, the record low was in the 2020/21 water year. 

The EIA attributed last year’s drop to drought conditions leading to “historically low” hydropower generation in the Pacific Northwest. Annual hydropower fell by 23% and 20% in Washington and Oregon, respectively. 

hydropower

Western U.S. hydropower output for water years from 2001 until 2023. | EIA

The 2022/23 water year for the region started with near-normal to below-normal precipitation, EIA noted. But in May 2023, a heat wave in the Pacific Northwest caused temperatures to spike as much as 30 degrees above normal, rapidly melting the snowpack.  

“Water flows in May were high, but much of the water supply needed for generation during the summer months melted during the May heat wave,” EIA said. Water supply in the PNW then stayed below average for the rest of the water year, reducing hydropower generation. Tight supply conditions became evident during a five-day cold snap in January when the region was forced to import large volumes of power to meet near-record demand and avert rolling blackouts. (See NW Freeze Response Shows WEIM Value, CAISO Report Says and Powerex Report Expands NW Cold Snap Debate.) 

California weather in 2022/23 was dramatically different than in the Northwest. A series of atmospheric river storms dropped record rain and snow on the state from December 2022 to March 2023. 

The wild winter left California with its largest snowpack since records began in the mid-1980s. Drought-depleted reservoirs were replenished, and hydropower generation for 2022/23 reached 30.0 million MWh, nearly twice that of the previous year. 

The 11 states in the Western region produced about 60% of the nation’s hydropower last year, roughly the same as in the 2021/22 water year.  

Washington, Oregon and California produced the most hydropower in the region; Washington and Oregon combined contributed 37% of the U.S. total. The other Western states are Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah and Wyoming. 

Elsewhere in the region, Southwestern states had above-normal precipitation in 2022/23. Hydropower generation at Glen Canyon Dam was up 27%. But output was down 11% at Hoover Dam due to water conservation, EIA said. 

California’s snowpack appeared to be in good shape March 26, at 102% of the state’s April 1 average, according to the California Department of Water Resources. 

Still, EIA is forecasting a 12% drop in hydropower production this water year in the Western market region of California. Similar decreases are expected in the Northwest and Southwest, according to EIA’s short-term energy outlook. 

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Report Shows Uneven Burdens of Power Infrastructure in Mass.

As the Massachusetts legislature gears up to address permitting and siting challenges for clean energy infrastructure, a new report shows how the state has disproportionately sited electricity infrastructure in environmental justice communities. 

Authored by a coalition of climate and EJ organizations, the analysis found that more than 80% of polluting generation facilities and nearly 70% of substations are located within 1 mile of a state-designated EJ community. 

Massachusetts defines EJ populations based on income, race and language barriers. The state has classified about 50% of its neighborhoods as EJ communities. 

“This analysis shows yet again that environmental justice communities in Massachusetts have suffered for decades from inequitably sited energy infrastructure, bringing unhealthy and unsafe conditions like air pollution to their neighborhoods,” said lead author Paula García, senior energy analyst at the Union of Concerned Scientists. 

As the state prepares for significant electricity demand growth, Massachusetts’ electric distribution companies have proposed major investments in new substations, while the state is also planning for a massive increase in solar, wind and utility-scale battery resources. (See Mass. Utilities Submit Grid Modernization Drafts.) 

The state’s investor-owned utilities have proposed installing 50 new substations by 2034. Based on the available data about the location of the utilities’ new substation investments, the analysis indicated that “new substations will likely aggravate this historic trend, with seven of the 11 mapped projects proposed for siting within EJ neighborhoods.” 

“The little information that is available suggests that proposed electric infrastructure will yet again disproportionately burden environmental justice communities,” said co-author John Walkey, director of climate justice and waterfront initiatives at GreenRoots. “Decision-makers must recognize this harmful pattern and establish a formal avenue for community needs to be centered in decisions happening in their own backyard.” 

The authors wrote that the clean energy transition will bring climate and public health benefits to the region but stressed that clean energy projects can still have detrimental local effects. They noted that substations can impact local communities through noise pollution and risks of fires and explosions, while poorly sited renewables can impact public spaces and wildlands. 

Future siting processes must do a better job incorporating the perspectives and concerns of host communities into project planning and consider the cumulative impacts of existing energy infrastructure, the authors wrote. 

The analysis also called on the state to add two public members to its Energy Facilities Siting Board to represent EJ and Indigenous communities and to add climate, EJ and public health to the board’s statutory priorities. 

These recommendations mirror those included in a bill in the state legislature that is supported by the organizations behind the analysis. (See Mass. EJ Groups Rally Behind Permitting, Siting Reforms.) 

Co-author Sofia Owen, senior attorney at Alternatives for Community and Environment, said some lawmakers have expressed concern that adding these EJ protections to the state’s siting processes could slow the deployment of infrastructure necessary for decarbonization. 

“It actually will speed things up if you have buy-in from the community,” Owen said. “I am hopeful that the administration will take to heart the things that EJ and climate justice advocates have been saying for a long time.” 

Aspects of the bill supported by the organizations, H.3187, were included in a combined bill passed out of the House side of the legislature’s Joint Telecommunications, Utilities and Energy Committee. 

Rep. Jeff Roy (D), co-chair of the committee, has highlighted permitting and siting reform as one of his top priorities for this legislative session. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.) Roy has introduced his own bill, which was also included in the package that was reported out of the committee. 

Along with bills from the House, the state’s Commission on Energy Infrastructure Siting and Permitting is due to make recommendations to Gov. Maura Healey by the end of March, which could lead to an additional permitting and siting proposal from the administration, while the Senate could also produce its own bill. 

Amid all the moving parts, top legislators are targeting the passage of an omnibus climate bill by the end of the session in July. If previous climate bills passed in the state are any indication, the negotiations could come down to the wire. 

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MISO, PJM Stakeholders Call for Interregional Transmission Overhaul

MISO and PJM are deliberating whether to embark on an interregional transmission study this year as they field more calls from stakeholders to revamp their joint planning framework.

Last month, state regulators and several environmental and consumer advocacy groups called on the RTOs to improve their cross-border transmission planning so it considers reliability, economics and public policy over a longer horizon. (See OMS, OPSI Urge MISO, PJM to Invigorate Interregional Planning and Enviros, Consumer Advocates Join Regulators Urging PJM-MISO Interregional Planning.) 

“Certainly, all the feedback we get is considered,” Jarred Miland, MISO senior manager of system planning coordination, said during a meeting of the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC) on March 25. “Interregional planning is important to MISO and PJM. … MISO and PJM have been in joint, active discussions regarding the feedback.” 

Miland promised “more to come” on the interregional planning front. 

The RTOs have 45 days following the IPSAC meeting to determine the need for a Coordinated System Plan study, which may produce interregional projects. The Joint Planning Committee, composed of MISO and PJM staff, makes the final call on whether an interregional study is warranted. 

MISO and PJM delayed their March IPSAC teleconference by about a month after the calls for more thorough and proactive interregional planning. 

Iowa Utilities Board Member and newly minted Organization of MISO States (OMS) President Josh Byrnes has characterized the joint letter from OMS and the Organization of PJM States Inc. (OPSI) as a “polite nudge” to get the ball rolling on substantial interregional planning. 

PJM’s Jeff Goldberg said the RTOs are currently reviewing interregional congestion issues that could be the focus of either a targeted market efficiency project study or a more intensive interregional market efficiency project study. 

Planners opened the IPSAC meeting by emphasizing their separate, ongoing regional planning efforts. Representatives of both RTOs spoke about their respective plan for long-range regional planning. 

Miland said MISO is coordinating with PJM on some of its recently unveiled second portfolio of long-range transmission plan (LRTP) projects, some of which cut across PJM’s ComEd territory. Miland said that although some lines will cross into the PJM system, the LRTP lines will be considered regional. 

However, multiple stakeholders continued to press for better interregional solutions at the seams. 

Michigan Public Service Commission Chair Dan Scripps reminded the RTOs that regulators, who review projects for affordability on cost containment on behalf of customers, are asking for new infrastructure. 

“‘Our regional grids are undergoing significant changes that merit consideration of joint planning activities,” Scripps said, quoting a letter from OMS and OPSI sent in February. 

Scripps said national studies and increasingly severe weather show “major opportunities for interregional progress.” He said MISO and PJM can use their existing long-term transmission planning processes to holistically plan interregional facilities. 

WEC Energy Group’s Chris Plante said he worried that MISO and PJM may miss an opportunity to show they are taking FERC’s potential rule on minimum interregional transfer capability seriously. 

MISO Director of Economic and Policy Planning Christina Drake assured stakeholders that the RTOs “are taking this very seriously.” However, she said the two “don’t have anything concrete to release” in terms of a timeline for responding to calls for a reworked interregional process. 

RMI’s Claire Wayner said MISO and PJM could have a more comprehensive planning process that considers reliability, public policy and congestion-relieving benefits. She said it is unsurprising that the RTOs’ process, with its limitations on who can propose a project when and for what purpose, hasn’t produced needed transmission projects. 

“As a former state regulator, I feel like we are witnessing a remarkable moment, where you’re seeing a confluence of forces who want … MISO-PJM interregional lines,” the Sustainable FERC Project’s Lauren Azar said. She advised MISO and PJM to get a jump on interregional planning so that by the time more severe weather strikes the regions, they are not perceived as inattentive. 

Grid Strategies Vice President Michael Goggin appeared before the IPSAC to reiterate the value of more interregional capacity. He used his 2023 report showing that expanded interregional transmission between the RTOs could offer more than $1 billion in annual energy market savings, as they often experience peak demand at different times. MISO and PJM experienced $1.7 billion in congestion in 2021-2022, he said. (See New Report Finds MISO, PJM Could Save Billions Through Interregional Tx Expansion.) 

“These are sizable quantities of market congestions that are causing real costs to customers,” he said. “As a nation, we are failing at building interregional transmission.” 

Goggin called for “proactive, multivalue” interregional transmission planning. For that to happen, PJM must move on from its siloed transmission planning that considers benefits individually, he said. 

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New OSW Project Advances as NJ Gears up for 4th Solicitation

The developer of New Jersey’s most advanced offshore wind project, Atlantic Shores, is pushing ahead with a second project as the state prepares to launch a new solicitation — its fourth — that could add as much as 4 GW in wind-generating capacity to help meet the state’s goal of 11 GW. 

The Bureau of Ocean Energy Management (BOEM) on March 18 posted a Notice of Intent (NOI) to prepare an Environmental Impact Statement (EIS) on the Atlantic Shores North Project proposed by the developer, Atlantic Shores Offshore Wind. The plan would create an 82-acre sea tract eight miles off the New Jersey coast and 60 miles from New York. 

The project would occupy the second half of the tract leased by the developer. The first half is the planned location of the 1,510-MW Atlantic Shores project — also known as Atlantic Shores South — that the New Jersey Board of Public Utilities (BPU) approved in its second solicitation, in 2021. 

The Atlantic Shores North Project, with 157 wind turbine generators, would send electricity through cables that would make landfall in Sea Girt, N.J., and either Asbury Park, N.J., or New York City. The developer says it will consider submitting applications to future solicitations launched by either New York or New Jersey. 

Terence Kelly, head of external affairs for Atlantic Shores, said the company is forging ahead despite the problems that in November prompted Danish developer Ørsted to withdraw its two New Jersey projects — the 1,100 MW Ocean Wind 1, the state’s first project, and the 1,148-MW Ocean Wind 2. 

Atlantic Shores is “bullish” on producing power off the New Jersey coast, in part due to the commitment from New Jersey Gov. Phil Murphy (D) and New York Gov. Kathy Hochul (D), Kelly said in an interview with NetZero Insider. 

“You see all the progress made. You can’t, can’t help but be a little bit bullish,” he said. “It’s a nascent industry that — getting through some challenging moments in the last year or two — sets us up to have a breakthrough moment where we can overcome the obstacles of the past.” 

Accelerated Solicitation Schedule

BOEM posted the NOI on the Federal Register two days before the BPU on March 20 held a hearing to gather public input on the guidance document for the state’s fourth offshore wind solicitation, which seeks to secure new wind capacity of between 1,200 MW and 4,000 MW. The approved capacity could be even larger, “if circumstances warrant,” according to the guidelines. 

The BPU expects to launch the solicitation during the second quarter, with applications in the third quarter and a decision on which projects to back by the end of the year. 

If that timeline holds, in a sign of the state’s determination to demonstrate its commitment to offshore wind, the BPU would announce the endorsed fourth solicitation projects less than a year after picking the winners of the third solicitation in January. The agency at that time backed two projects — Leading Light Wind and Attentive Energy Two — totaling 3,742 MW of capacity. (See NJ Awards Contracts for 3.7 GW of OSW Projects.) 

The state had planned to solicit new projects every two years, but it accelerated the process after Ørsted’s departure to make up for lost ground. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)  

The developer’s withdrawal left Atlantic Shores, a 50/50 joint venture between EDF-RE Offshore Development and Shell New Energies US, at the helm of the state’s leading offshore wind project. 

“The compounding challenges of the interest rate environment, of inflation and the supply chain bottlenecks, those are all things that are real, they remain real,” Kelly said. But he added that “we are sizing them up in a way that we say, you know what, cautiously we can proceed, because these are great markets.” 

Going through the NOI process is part of the company’s strategy to get as much of the permitting and regulatory issues out of the way early on, he said. That way, when the company submits a solicitation bid it can present a “mature” project with a solid foundation that can persuade state officials selecting projects that Atlantic Shores is ready to bring the project successfully to fruition.  

Although the lease area is close to New Jersey, it sits in federal waters, so the power generated by the project would go to the state that strikes a finance and power agreement with the developer, Kelly said. 

“We remain committed to New Jersey,” he said, noting that New York also will have a solicitation in the near future. He added that the developer is ready for opposition from New Jersey stakeholders to the Atlantic Shore North Project. 

“Stakeholder concerns are valid, and we should take them into consideration,” he said. “And they should be weighed appropriately against the public policy goal to get to 100% clean energy by 2035.” 

Project Evaluation Criteria

New Jersey’s wind projects have faced opposition from commercial fishermen, businesses that fear fewer visitors will come to the shore if wind turbines are on the horizon, and residents and property owners who fear the projects will diminish their quality of life. 

BOEM’s announcement that it would initiate the environmental review of Atlantic Shore North prompted an opposition group, Save Long Beach Island, to denounce the plan in a fundraising email that day. 

As well as its proximity to shore communities, the project would “add insult to injury” by potentially sending power to New York, the message said. 

“This is truly inequitable because LBI (Long Beach Island) and New Jersey would bear the adverse property value, rental, tourism and other impacts of the turbine projects, while New York would get the benefit of the power,” said the email, from organization President Bob Stern. It added that the organization would need “new financial support” to oppose the project in the environmental process and to file litigation against the Atlantic Shores North Project. 

Opposition surfaced at the hearing for the fourth solicitation guidance proposal, where there was little presence among the 10 speakers of either the OSW industry or the environmental groups that see OSW as essential to cutting carbon emissions and helping mitigate the effects of climate change. 

Opposing the projects, Jeff Platenyk, who said he is a longtime resident of New Jersey, expressed concern at the weighting of different factors the BPU uses to decide which projects to approve. The agency said the purchase price of an Offshore Renewable Energy Credit — which represents the environmental attributes of one megawatt-hour of electric generation from an offshore wind project — and other ratepayer impacts will carry 60% of the evaluation factors. 

Economic strengths and the proponents’ guarantees to make them happen will account for 20% of the factor weighting, and an additional 10% will rest on the likelihood the project would yield a successful commercial operation. 

Platenyk questioned why “environmental and fisheries impacts” carry only a 10% weighting, calling it “quite disturbing” given that the projects could reap “serious destruction” of ocean aquatic life. 

Supporting the OSW projects, Monmouth County fishing charter business owner/operator Paul Eidman said he sees “the negative impacts of the climate crisis every day out on the water” and offered a suggestion for improving the guidelines. Eidman suggested the BPU take measures to ensure the turbines are decommissioned after 25 years in such a way as to create an “artificial reef underneath these turbines.” 

Erica Bosak, an attorney for Clean Ocean Action, which opposes OSW projects due to their possible damage to whales and other marine life, criticized the “voluntary nature of many of the solicitation guidance documents.” 

She said the guidance says developers submitting project proposals “should … avoid impacts to sensitive seafloor habitats, including shellfish habitat, prime fishing areas, submerged aquatic vegetation and wetlands.” 

“But it is not mandatory for them to do so,” she said. 

Transmission Cost Reductions

The BPU, on the same day as the fourth solicitation, approved changes in the scope and cost of the infrastructure through which the power would be brought to the shore. BPU officials said the changes to the transmission system created under the State Agreement Approach approved by the board Oct. 26, 2022, would save ratepayers about $29 million. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)  

The order said the changes stemmed from regular meetings between BPU staffers and representatives of PJM. The changes included cancellations of a transmission line and circuit breaker that were not needed, revised cost estimates for equipment and conclusions that certain projects no longer were needed, the order said.