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November 5, 2024

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NERC Board of Trustees/MRC Briefs: Aug. 15, 2024

Board Invokes Standards Authority to Meet IBR Deadline

VANCOUVER, British Columbia — NERC’s Member Representatives Committee and Board of Trustees met Aug. 15 for their final in-person gatherings of the year. 

With a FERC-imposed deadline rapidly approaching for the submission of reliability standards governing ride-through performance of inverter-based resources, the board for the first time invoked its authority to streamline the ERO’s stakeholder approval process. 

FERC ordered NERC in October 2023 to submit reliability standards addressing IBR performance requirements and IBR disturbance monitoring data sharing and post-event performance validation by Nov. 4, 2024. (See FERC Orders Reliability Rules for Inverter-Based Resources.) NERC assigned the development work to three ongoing standards development projects, which produced five draft standards: 

    • PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources; 
    • PRC-002-5 — Disturbance monitoring and reporting requirements; 
    • PRC-029-1 — Frequency and voltage ride-through requirements for inverter-based resources; 
    • PRC-024-4 — Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers; and 
    • PRC-030-1 — Unexpected inverter-based resource event mitigation. 

Four of the proposed standards have met the two-thirds weighted stakeholder approval needed for submission to FERC, but at the time of the board meeting, PRC-029-1 had again failed to receive approval in its most recent formal ballot round that ended Aug. 12. With the deadline less than three months away, board Chair Kenneth DeFontes said “it’s not clear NERC’s usual process can produce a consensus standard.” 

NERC Chair Kenneth DeFontes (left) talks with CEO Jim Robb before the board meeting. | © RTO Insider LLC

“NERC has a regulatory responsibility to file reliability standards addressing [FERC’s order] by Nov. 4, but equally important is [that] it’s the right and necessary thing to do,” DeFontes said. “The board needs to consider taking special action to get [the] IBR ride-through standard done on time.” 

The resolution was recommended to the board by the Regulatory Oversight Committee (ROC) in its meeting Aug. 14. Using the board’s authority under Section 321 of NERC’s Rules of Procedure, it directed the Standards Committee to convene a technical conference Sept. 4-5 in the ERO’s D.C. office. 

NERC will use input from the technical conference to revise the proposed standard, which will be submitted for stakeholder ballot. If it receives a two-thirds weighted stakeholder approval, the standard will be considered approved; the board still may consider adopting the standard if it receives at least 60%, though an additional comment period and technical conference may be needed. 

“Over the years, the board has seen industry rise to the occasion time and time again to address tough issues and FERC directives through NERC’s standard development process,” DeFontes said. “We’ve said before that stakeholder input is essential to the success of the ERO model, and that remains true. The ROC’s recommendation … is to focus our stakeholder efforts for one final push [toward] developing a consensus standard. … I encourage our drafting teams and stakeholders to continue to participate and bring their knowledge and unique perspectives to this process.” 

Budgets Headed to FERC

Additional actions at this week’s meetings include the acceptance of NERC’s 2025 Business Plan and Budget, along with those of the regional entities and the Western Interconnection Regional Advisory Body. The budgets will be submitted to FERC for approval. 

The final business plans and budgets are “materially consistent” with NERC’s three-year projection, CFO Andy Sharp told the Finance and Audit Committee at its open meeting Aug. 14. NERC, the REs and WIRAB will see their combined budgets increase 9.1% over their 2024 levels to $304.6 million, while the collective assessment will grow 12.2% to $270.9 million; NERC’s budget alone is set to grow to $123 million, up 8.2% over 2024, while the assessment will rise 11.8% to $108.4 million. 

MRC Elections to Begin in December

Nominations for the MRC’s officers will open Sept. 18 and close Oct. 17, Chair Jennifer Flandermeyer said during the committee’s meeting. Officers will be elected by current members Nov. 13 at the MRC’s final meeting of the year, which will be held in a hybrid format with only members attending in person. 

Meanwhile, nominations to replace members whose terms expire next February will open Sept. 4 and close Dec. 1. The election will run Dec. 2 to 11. 

Trustee Larry Irving, chair of the board’s Nominating Committee, also shared an update on the search for a trustee to succeed Bob Clarke, who will leave the board at the expiration of his term in February 2025. Clarke has served on the board since 2013, making him ineligible for renomination. 

Irving reported that the Nominating Committee has selected a search firm to assist with the recruitment and “reviewed an initial pool of candidates” that he called “outstanding.” He said the committee plans to recommend a candidate to the MRC in December, with the election to take place next February. 

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SPP Dispels Concerns over Markets+ Deficiency Letter

WESTMINSTER, Colo. — Meeting with potential Markets+ participants for the first time since FERC filed a deficiency letter over SPP’s tariff filing for the proposed day-ahead market, the grid operator’s staff assured the Markets+ Participant Executive Committee that recent developments have not hindered the RTO’s commitment to Western expansion.

“So far as we’re concerned, nothing’s changed,” Carrie Simpson, SPP’s senior director of seams and Western services, told RTO Insider following the MPEC’s Aug. 13 meeting. “We’re creating what we think is a great product for the West and the best product for the West. We will determine over the next several months who participates, but right now, our focus is the tariff approval.”

FERC issued the deficiency letter July 31, directing SPP to respond to a list of 16 questions related to the tariff. It gave the RTO until Sept. 30 to respond. (See FERC Finds SPP Markets+ Tariff ‘Deficient’ in Several Areas.)

SPP’s legal staff pointed out that the commission’s letter is not a rejection or a likelihood of future rejection, but a “routine process” that SPP has participated in over the years.

“None of the questions indicate to me there’s a serious risk to Markets+,” General Counsel Paul Suskie told the committee. “They indicate to me that FERC is just trying to get additional information.”

Suskie said FERC has sent SPP 41 deficiency letters since 2010. The vast majority (32, or 78.05%) were resolved with SPP’s first response. Of those tariff revisions that SPP refiled, all were approved — including its tariff for the Western Energy Imbalance Services market, in operation since 2021 — except one that is still pending, he said. (See FERC Approves SPP’s Western Market Tariff.)

Chris Nolen, SPP | © RTO Insider LLC

“I’ve responded to my share of those 41 deficiency letters. This deficiency letter reads to me like FERC wants education. They’ve asked for an explanation,” staff attorney Christopher Nolen said. “Of course, I would prefer the order, but as deficiency letters go, I’m good with this one.”

Nolen said most of the commission’s questions dealt largely with transmission. He noted there were no questions on governance, seams or market fundamentals, saying, “To me, that’s at least as important as the questions they asked.

“I can’t stress enough that they seem to be especially interested in education on how transmission will work in Markets+. If you step back and think about Markets+, how it’s designed and how it works, that’s perfectly reasonable,” Nolen said. “It’s a number of others, a number of parties, a number of balancing authorities, all bringing transmission together for us to effectuate a day-ahead, first-in-class market.”

Staff said they are working quickly to meet the deadline, using examples from stakeholders to respond to the questions. The effort is not expected to delay the 2027 target go-live date or the overall timetable, as SPP has built in additional time to the schedule to serve as a buffer.

“When I ran through these questions on my first pass-through, I thought, ‘Wow, these are all answerable questions.’ So, we have an idea how to answer all these questions,” Nolen said. “I don’t think it will take 60 days.”

SPP said CEO Barbara Sugg’s pending retirement will do nothing to slow its Western expansion, in which the Markets+ service offering will play a large role.

“Our commitment to the West is the strongest it has ever been,” said Antoine Lucas, vice president of markets, stressing that Markets+’s role in the strategy is “unchanged” by Sugg’s decision.

Director Steve Wright said Sugg has done an “outstanding” job and is “extremely committed” to both the RTO and its Western expansion efforts.

“Having said that, there are nine other board members who have been very actively engaged in this process,” he said. “The [board’s] other members have been very interested in this activity as well and have been kept fully briefed as we move along and understand the status of this project, and have been very supportive of it.”

The MPEC reviews protocols for approval brought by the Markets+ Market Design Working Group. | © RTO Insider LLC

In the meantime, potential Markets+ participants are working on the protocols that will set the market’s mechanics. Three different working groups presented their first batch of protocols for consideration. All were approved unanimously.

The MPEC also approved two chairs to fill vacancies in the stakeholder groups. Puget Sound Energy’s Jessica Zahnow will lead the Markets+ Interim Governance Task Force, and Bonneville Power Administration’s Libby Kirby will chair the Markets+ Operations and Reliability Working Group.

Staff told stakeholders they have board approval to engage with lenders over Markets+’s second-phase funding agreements that will be extended to participants by year-end. SPP expects its administrative costs to run between $65 million and $70 million annually.

Until then, SPP can only wait on FERC’s response to the RTO’s response.

“We anticipate more certainty at that point related to FERC,” Simpson said. “That’ll be the time period when I think parties will decide what they plan to do. We just want them to have choices, at that point.”

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The IRA at 2: A Mixed Record of Achievement and Uncertainty

Money from President Biden’s two signature climate laws isn’t just being used for big clean energy projects to produce zero-carbon hydrogen and suck carbon dioxide out of the air, according to a Department of Energy official.

The Infrastructure Investment and Jobs Act and Inflation Reduction Act are “delivering clean energy upgrades to school children in Selma, Alabama,” for example, and “decarbonizing food production in America’s heartland, one mac and cheese at a time,” said Doug Schultz, chief operating officer at the DOE’s Office of Clean Energy Demonstrations (OCED).

During DOE’s Aug. 14 webinar marking the second anniversary of the IRA, Schultz described how the OCED awarded the Kraft Heinz Co. up to $170.9 million earlier this year to “upgrade, electrify and decarbonize food production” at 10 of its plants, including a Michigan factory producing Kraft’s signature comfort food, Schultz said.

“It takes a whole lot of heat to dry all that macaroni, which produces a whole lot of emissions,” he said. “This project will employ clean tech like heat pumps, electric heaters and electric boilers to slash those emissions 99%.”

Biden signed the IRA into law Aug. 16, 2022. It is the largest federal investment in climate and clean energy action in U.S. history, and in the weeks leading up to the IRA’s second anniversary, DOE and other agencies have been heralding the law’s impact and benefits for Americans across the country.

In opening remarks at the webinar, Kathleen Hogan, principal deputy under secretary for infrastructure, reeled off numbers from DOE’s recent Progress Update, tracking the department’s implementation of IRA and IIJA programs. All of the new programs established in the two laws have been launched, and $48.7 billion has been awarded to thousands of projects, Hogan said.

A DOE video highlighted a new factory in Weirton, W.Va. ― a former steel town ― where startup Form Energy is using IRA tax credits to help it build long-duration iron-air batteries, while paying workers average wages of more than $63,000, according to Ted Wiley, president and chief operating officer.

Figures released by the Treasury Department on Aug. 7 showed that “more than 3.4 million American families had already claimed more than $8 billion in residential clean energy and home energy efficiency tax credits against their 2023 federal income taxes.” The lion’s share ― $6 billion ― went to the 1.2 million households that installed solar panels and batteries and received tax credits averaging $5,000 per family.

A General Services Administration press release announced the agency so far has spent $480 million out of its $3.4 billion in IRA funds for “sustainable improvements to federal buildings across the country” and also has promoted the use of low-carbon building materials on those projects.

But the achievements come after an occasionally rocky two years in which IRA implementation has progressed in fits and starts.

Pain points include the Treasury Department’s still-incomplete efforts to provide guidelines for all of the law’s tax credits, with some companies and their investors waiting on the sidelines because of uncertainty about whether their projects will be able to benefit.

The tax credit for clean hydrogen is a prime example. Treasury released proposed guidelines in December 2023 but has yet to finalize the rules, which will be critical for the development of the seven hydrogen hubs OCED announced last October. They’re intended to build out a clean hydrogen industry. But only three of the hubs have signed contracts with DOE, allowing them to begin planning the projects.

Similarly frustrating, the IRA’s programs providing rebates to help low-income families install energy-efficient appliances — like heat pumps — have rolled out at a glacial pace. Wisconsin and New York are the only states so far that have launched programs.

According to Ward Lenz, deputy director at DOE’s Office of State and Community Energy Programs, 22 states have submitted applications, and he expects more to come in. However, some states are very early in the process. For example, the Maryland Energy Administration (MEA) announced in July that DOE had approved its application to receive “early administrative funds” provided by the law, so it could start planning its program.

The money will be used to hire staff to design and implement the program, MEA said. While acknowledging the high level of public interest in the rebates, the agency has yet to announce any target dates for when the federal dollars might be available.

‘Overly Rosy’ Expectations

The IRA’s impact on clean energy manufacturing has been one of the law’s most widely hailed achievements, with a recent report from the American Clean Power Association noting the law has stimulated $500 billion in private investment in new plants and projects. Of the more than 160 projects announced in the past two years, 42 are online or under construction, the report says.

DOE’s Grid Deployment Office also has been active in awarding IRA funds to expand grid capacity across the country, with its Grid Resilience and Innovation Partnership (GRIP) awards. Most recently, $2.2 billion in GRIP awards were announced for eight projects, including two interregional lines and six that will increase capacity on existing lines with grid-enhancing technologies. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)

Such encouraging numbers don’t always align with public perceptions. A poll conducted by the University of Chicago’s National Opinion Research Center in April asked a series of questions about the IRA, and in almost all cases more than a third of participants said they didn’t know enough about the law to answer.

Further, only 15% to 26% of participants saw the IRA as providing benefits to people like themselves, depending on particular provisions of the law, such as tax credits for electric vehicles or rooftop solar or grants for clean energy projects in low-income communities.

Amy Turner, director of the Cities Climate Law Initiative at Columbia University’s Sabin Center for Climate Change Law, said such polls may not capture a longer view of the law.

“The IRA has programs that are meant to last as long as a decade,” Turner said in a phone interview with NetZero Insider. “Just because we have an anniversary of the law doesn’t necessarily mean that this is the anniversary when everything is meant to be happening all at once, at the same time.”

The billions of dollars in the law have posed a heavy lift for DOE and other agencies, which “have been standing up really massive new programs that are now operational and getting money out the door,” she said. “They weren’t necessarily experienced in the things that they were being asked to do.”

In some cases, like the home energy rebates, expectations of how quickly the money would be available were “overly rosy,” Turner said. “[The] dates that we can expect to see the rebates active in different states across the country have been continually kind of pushed back,” as individual states develop plans that must be approved by DOE.

Turner said she believes the IRA’s provisions that allow for direct pay of its tax credits may have the longest lasting and transformative impacts. “This is a 10-year program,” she said. “It really stands to change the way that states, tribes, local, nonprofits and a range of other non-taxpayers pay for things like renewable energy development and clean vehicles.”

Those entities previously had been unable to take advantage of clean energy tax credits because they don’t file taxes and therefore had no way to use the credits. With limited options, they often had to work with third-party developers who could use the credits.

The direct pay provisions allow them to get the credits as a cash payment but do require them to file complicated paperwork with the Internal Revenue Service, which is slowing uptake, Turner said. Officials in small towns and nonprofit staff members have to learn in real time, she said.

“So, the hope is that by a handful of non-taxpayers going first and figuring out some of these early hurdles, the broader public can learn how to proceed, and the IRS can smooth out some of its processes,” Turner said.

Turner also said the IRA’s direct pay provisions should be unaffected by election results. “Even after all [the law’s] grant money is allocated and goes out the door, this is a program that remains in the tax code until 2032. A president cannot change it on his or her own. It would require Congress to act,” she said.

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Revolution, Sunrise OSW Projects Face New Delays

Ørsted has run into new delays that will push back completion of at least one of the two offshore wind farms it’s building in U.S. waters. 

The world’s largest offshore wind developer said Aug. 15 that complications with the onshore substation for its Revolution Wind will push completion of the project from 2025 to 2026, and the complexity of building the first offshore HVDC system in the United States may push completion of Sunrise Wind from late 2026 to the first half of 2027. 

As it released its first-half 2024 financial report, the company said it will record new impairments due to the Revolution Wind delay and its decision to suspend FlagshipONE, the e-methanol ship fuel production facility it was building in Sweden. Its stock price closed 7.2% lower. 

The announcement was the latest setback for Ørsted in its U.S. offshore wind development portfolio. It booked billions in impairments in 2023 as it canceled Ocean Wind in New Jersey, canceled the offtake contract in Maryland for Skipjack Wind and declared that Sunrise Wind was untenable under terms of its contract with New York. (See Ørsted Cancels Ocean Wind, Suspends Skipjack, Ørsted Cancels Skipjack Wind Agreement with Maryland, NY Rejects Inflation Adjustment for Renewable Projects.) 

Amid all that, Ørsted and its partner Eversource decided in October to move forward with Revolution Wind, a 704-MW wind farm that will feed into the grid in Connecticut and Rhode Island, having determined they could work around supply chain constraints and vessel availability issues that slowed or halted other Northeast projects. 

And in fact, Ørsted CEO Mads Nipper said Aug. 15, offshore construction of Revolution is going well — 44 of 67 foundations are in place and turbine installation will start in the coming weeks. 

The chokepoint now is onshore — a toxic legacy of the past rather than growing pains for the clean energy of the future. 

The substation is to be built on a former U.S. Navy disposal site in Quonset Point, R.I., that turns out to be more heavily contaminated than previously thought. The mitigation requirements therefore are greater than initially projected. 

The situation is unsatisfactory but will not deter Ørsted from its long-term goals, Nipper said. 

Eversource, which also has incurred heavy losses in the offshore wind space, has sold its 50% share of Sunrise to Ørsted and is selling its 50% share of Revolution to GIP. (See Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023.) But it will remain involved with the onshore portions of the projects, including the Revolution substation. 

Meanwhile, the financially untenable Sunrise contract has been replaced with a deal with New York state that carries much higher compensation to reflect the sharply higher costs of building the 924-MW offshore wind farm. (See Sunrise Wind, Empire Wind Tapped for New OSW Contracts.) 

When federal regulators approved the construction and operations plan for Sunrise on June 21, Ørsted said it would start offshore construction this year and that it expected to be done in 2026. (See Sunrise Wind Cleared to Begin Construction.) Onshore construction has been under way for months and officially broke ground in July. 

On Aug. 15, Ørsted said it would start offshore installation in 2025 and that the commissioning date could slip from the end of 2026 into the first half of 2027, due to the pioneering nature of its use of HVDC cable. 

Ørsted reported an impairment equal to $310 million on the Revolution delay but said the potential Sunrise delay is incorporated into planning and would not result in an impairment. In fact, Ørsted reversed $256 million of previous impairments due to Sunrise securing the new contract with New York. 

In a conference call Aug. 15 with financial analysts, Nipper said, “In the offshore business, no project is without challenges and risk. There is no reason with the current knowledge to believe that what we have now is not realistic. It would be speculation to say, ‘What else could go wrong?’ because what we present to you now is a plan that we believe in.” 

He also gave an update on other aspects of Ørsted’s offshore wind business: 

    • It took an $88 million impairment on the diminished value of the seabed lease areas off the New Jersey coast it once targeted for Ocean Wind. 
    • Repurposing the export cable that would have been installed at Ocean Wind for the Hornsea project off the English coast would be financially beneficial, and Ørsted is progressing with plans to do so. 
    • The company has no plans to use Chinese-made wind turbines but does not rule them out; it would consider any product that met specifications and standards. 
    • The Skipjack concept remains in active development — a revised construction and operations plan recently was submitted to federal regulators — but there is no specific plan yet for moving toward construction. 
    • Ørsted has been able to firm up its supply agreements for monopile foundations, one of the more significant pinch points in the supply chain, and it has secured the services of installation vessels, which are in critically short supply. 
    • It has scrutinized other planned substation sites, including for Sunrise, and has not found issues comparable to the problems facing the Revolution site. (Nipper said in November 2023 there was contamination at both the Sunrise and Revolution cable landing sites, enough that both would qualify as brownfields eligible for enhanced investment tax credits.) 
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Mass. Breaks Ground on Salem Offshore Wind Terminal

SALEM, Mass. — State government leaders and project developers ceremonially broke ground on a major offshore wind terminal in the port city of Salem at the former site of a coal plant, kicking off construction on what is set to be the state’s second large offshore wind port.

The new terminal will be used for turbine assembly, staging and storage, and will support the transportation of turbines, according to Crowley Wind Services, the lead developer for the site.

The project “represents an important step forward for this industry,” Gov. Maura Healey said. “We’ve heard a little bit about setbacks lately in this space, and we’ve certainly heard some people try to knock this industry, but make no mistake, we are not going backward; we are going forward.”

Construction on the Vineyard Wind 1 project has been delayed for about a month after a blade collapsed into the ocean, although the U.S. Bureau of Safety and Environmental Enforcement authorized a limited resumption of construction earlier this week.

“Offshore wind is critical to our state; it’s critical to reducing our emissions and meeting our climate goals — which are established by law — and it’s critical for protecting our communities,” Healey added.

While construction on Vineyard Wind has been staged from the Port of New Bedford — located close to the lease area south of Cape Cod — the Salem Offshore Wind Terminal appears to be better situated to serve projects in the Gulf of Maine.

Massachusetts Gov. Maura Healey speaks at the site of the Salem Offshore Wind Terminal. | © RTO Insider LLC

Salem is not the only port looking to get in on the action in the gulf; the state of Maine is pushing ahead with plans to build an offshore wind port facility on Sears Island in Searsport. Salem is located closer to most of the gulf’s lease areas than Searsport. (See Wind Energy Lease Areas Designated in Gulf of Maine, Oregon.)

Because of the water depths in the gulf, projects in these lease areas will likely need to rely on early-stage floating turbine technology.

Speakers at the Salem groundbreaking ceremony emphasized the local labor and economic benefits of the site’s redevelopment. According to Crowley’s environmental impact report — prepared for the state by Fort Point Associates — the project is expected to create up to 123 full-time jobs during construction and up to 200 once in operation. The facility has a planned in-service date of early 2026.

The project is expected to cost about $300 million, funded through a combination of federal, state and private money. It features a project labor agreement and a community benefits agreement worth nearly $9 million.

“Salem’s story for centuries has been written on the sea,” Mayor Dominick Pangallo said. “The climate crisis is here. But we know that while the sea can sink us, it can also save us.”

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Members Want More Features in New MISO Load Tracking

MISO continues to try to get a bead on load growth and took stakeholder suggestions this week on how best to monitor sizable future load additions across the footprint.  

MISO since late June has maintained a list of large load announcements in its footprint.  

At an Aug. 14 Advisory Committee teleconference, Stakeholder Services Executive Director Suzie Jaworowski said MISO envisions the list becoming a dashboard-style feature on its website to track significant new load announcements. 

MISO members asked that the list contain features to make it easier to interpret.  

The Coalition of Midwest Power Producers’ Travis Stewart asked MISO to include a baseline load forecast alongside the load additions list. He said it would be helpful to compare forecasts made before large load announcements.  

“There isn’t a reference point for load forecasts one year, five years and 10 years down the line and how these incremental increases are going to affect [them],” Stewart said.  

However, Jaworowski said the load catalog isn’t meant to serve as a forecasting document or be used for planning purposes.   

“This is just one more channel … that opens our eyes to the potential. It doesn’t mean all of these are going to be built,” Jaworowski said.  

Clean Grid Alliance’s Beth Soholt said the list is “confusing” because it’s not clear which projects load-serving entities already have included in the load projections they submit to MISO.   

“I think the key question is, ‘Are we planning for these?’” Soholt said.  

The Union of Concerned Scientists’ Sam Gomberg also requested that MISO indicate which load entries are planned to host onsite generation.  

Jaworowski said MISO would consider both suggestions.  

“I think as we move forward, this will evolve into something very helpful for everyone,” she said.  

Minnesota Public Utilities Commissioner Joe Sullivan said MISO neglected to add Microsoft’s intentions for the vacant manufacturing space at Foxconn’s facility between Milwaukee and Chicago, as well as Google’s plan for a data center in rural Minnesota.  

Jaworowski said MISO compiled the list after researching publicly announced plans for new or expanded facilities. She said planners will search again for missing plans.  

MISO has said it plans to update its load addition list periodically as more announcements are made. In June, MISO executives said announced load additions in the footprint from manufacturing projects and data centers totaled more than 8 GW. (See MISO Leadership Issues Urgent Call for In-Service Dates, MISO Members Stress Need for Speed to Manage Load Growth, EPA Carbon Rule.)  

The Advisory Committee will have a daylong meeting Sept. 18 in Indianapolis during MISO Board Week. There, members plan to hold a discussion on how to keep costs affordable as the demand for electricity rises and aging infrastructure is traded for new grid technologies. 

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New Jersey Works to Electrify Buses, Heavy-duty Trucks

New Jersey is adding to its efforts to cut medium- and heavy-duty vehicle emissions with plans to spend more than $300 million on electric bus garages and to increase the use of clean cargo handling equipment at ports.

NJ Transit said in July it will build an outdoor charging facility in Secaucus with a $99.5 million grant from the Federal Transit Administration (FTA). The facility, with a price tag of $212 million over two phases, initially will have the capacity to serve 67 buses and include infrastructure for a later expansion to serve 63 more buses. The targeted project completion date is 2028.

In a separate project, the agency, which serves 925,000 bus passengers on 263 bus routes a day, in July hired a designer for a $92 million project to create a 100,000-square-foot facility in Union City that will handle 40 battery-powered buses. It is slated to open in 2030.

The two initiatives are part of NJ Transit’s effort to convert the agency’s entire fleet of 2,300 buses to zero-emission vehicles by 2040. However, the agency has to date put only eight electric buses serving routes.

NJ Transit CEO Kevin S. Corbett, announcing the design contract, said in a release that the “state-of-the-art facility will serve as a model for cost-effective, sustainable bus operations across New Jersey and represents another important step in advancing our Zero-Emission Bus Program.”

The agency said it intends to make the design “standardizable and cost effective so that similar facilities can be easily replicated across the state.”

NJ Transit’s announcement comes as the state Department of Environmental Protection (DEP) this month will collect the final data for a study of cargo handling equipment at the state’s ports and rail yards in an effort to reduce emissions.

The study of yard trucks and other goods-moving equipment used predominantly inside ports will assist the agency in enforcing new rules set to take effect in March. They require all cargo handling equipment newly introduced in state ports and rail yards to meet Tier 4 diesel engine standards, the strictest emissions requirement from the federal Environmental Protection Agency. By 2028, all existing port equipment must meet that standard.

Slow Uptake

Transportation accounts for 38% of New Jersey’s emissions, the state’s largest source, and medium- and heavy-duty vehicles (MHDVs) generate a significant part of that pollution, especially in neighborhoods around ports that already are overburdened with a variety of polluting sources.

Yet the state has lagged in getting electric transit and school buses, and heavy-duty trucks on the road, according to environmental groups. They say the NJ Transit effort is underfunded and well below what is needed, and the effort to encourage electric truck adoption by installing plentiful charging infrastructure has yet to come to fruition.

About 4% of the on-road vehicles in New Jersey are MHDVs, but they contribute 25% of the state’s transportation greenhouse gases, according to a DEP report, “A Roadmap to Zero-Emission Medium- and Heavy-Duty Vehicles in New Jersey,” released in May. The 3,737 transit buses in the state are responsible for 3% of the state HMDV greenhouse emissions, according to the report, which acknowledged the slow uptake of electric MHDVs in the state even as the number of light-duty EVs on state roads jumped 68% in 2023. (See NJ EV Incentives Target Low-income Buyers.)

“While (MHDV) ZEVs are beginning to see increased market share in New Jersey, registrations remain low,” the report concluded.

With 512,500 MHDVs in the state, there were just 2,324 electric MHDVs registered in the state and no MHDVs powered by fuel cell technology, the second category studied in the DEP’s report.

The state has a solid portfolio of state programs to get more zero-emission HMDVs on the road, the report says. They include truck-purchase incentive programs using funds from the Regional Greenhouse Gas Initiative and the state’s Volkswagen Mitigation fund and an incentive program to help replace diesel buses used in school districts with electric vehicles.

The state in 2021 adopted California’s Advanced Clean Truck (ACT) regulations, which require manufacturers to make an increasing number of electric MHDV sales in the state. And the DEP also is trying to prepare truck fleet owners and operators for the transition to electric vehicles with a new program called New Jersey Fleet Advisor. The agency on Aug. 15 closed the initial phase of the application process for fleets of fewer than 10 MHDVs, which, if successful, will receive a roadmap to electrification created by CALSTART, a national nonprofit organization working to decarbonize the transportation industry.

Low Priority

Yet additional strategies are needed, the DEP report states. It suggests new programs to map the additional charging demand from MHDV electrification, fund new charging technologies and establish a workforce development program to create trained technicians well-versed in the new technology.

Pam Frank, CEO of ChargEVC-NJ, a nonprofit coalition that promotes the sustainable growth of the EV market, said the state is behind in getting MHDVs on the road. She cited the lack of progress of a straw proposal to set out the rules and incentives for getting charging infrastructure to serve MHDVs installed around the state. Initially released in 2021, the Board of Public Utilities released a revised version in December 2022.

“We have been sitting in limbo, and this is of their own making,” said Frank. “This is supposed to be a high priority of this administration, and we’re nowhere.”

BPU spokesman Bailey Lawrence, asked about what is happening with the proposal, said “the next step would be board action on the issue.”

Anjuli Ramos-Busot, director of the Sierra Club’s New Jersey chapter, said the NJ Transit electrification projects are a step forward, but the agency is “definitely not moving fast enough, definitely needs to be prioritized.”

“By transitioning into electric buses, you’re going to have more efficiency,” she said. “Prioritizing public transit, the electrification of public transit is not just a benefit in the economic sense for the state and NJ Transit, it’s also an action on public health.”

William Beren, chairman of the NJ Sierra Club’s transportation committee, said a key problem is that the state relies on federal money to fund NJ Transit’s electrification program. And so far, that has not come close to the estimated $200 million a year in capital investment the agency estimates is needed, he said.

Clean Port Equipment

The MHDV emissions at New Jersey’s ports — most notably the Port of New York and New Jersey — have come under scrutiny, in large part due to their proximity to low-income and overburdened communities.

The DEP initiative to electrify cargo handling equipment follows similar rules from the Port Authority of New York and New Jersey in 2022 that require all material handling equipment added after Jan. 1, 2022, to the port to be of Tier 4 emissions standards. As of January 2025, any new terminal tractor added to the port fleet must be a zero-emission vehicle.

The authority says the strategy is working. The restrictions, and related data collection requirements that have helped compile information on the port fleet, have enabled the authority to already meet a 2026 target that all ship-to-shore and rail-mounted gantry cranes be zero-emission equipment, authority spokesman Steven Burns said.

“We’ve seen more zero-emission equipment get introduced at the port, alongside an overall growing interest in alternative fuels and zero-emission technology,” he said.

There are now 190 electric cargo handling equipment vehicles in the port. But the port has yet to make inroads into the 28,800 drayage trucks — trucks that bring containers in and out of the port — that are registered with the authority. In June, only two electric Class 8 heavy-duty vehicles performed drayage duties at the port, along with another nine electric trucks of other types that work there, Burns said.

Authority officials hope those figures will swell when the first two truck EV chargers come online at the port in January.

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Fate of Appalachian Power’s Coal Plants Debated in RPS Proceeding

The fate of two massive coal plants owned by AEP’s Appalachian Power is generating debate in a proceeding to approve the utility’s renewable portfolio standard (RPS) plan at the Virginia State Corporation Commission (PUR-2024-00020). 

While most of the plan is devoted to expanding renewable energy in compliance with Virginia’s Clean Economy Act, the utility is required to study the potential retirements of its John Amos and Mountaineer coal plants, with a combined capacity of 4,235.1 MW. The State Corporation Commission has required the utility to include early retirement of the two plants as a sensitivity to its RPS plans the past couple of years. Appalachian Power now argues it will not retire the plants until 2040 so it should be relieved of that requirement. 

“The prevailing headwinds facing coal-fired generation — headwinds that the company itself has acknowledged — suggest that abandoning the commission-mandated retirement sensitivity would be imprudent in any year within recent memory,” the Sierra Club said in a filing this week. 

Especially with EPA set to unveil final regulations on coal plants that could affect the economics of the John Amos and Mountaineer plants, Sierra Club argued it makes sense to keep planning around their potential retirement. 

EPA’s greenhouse gas rules for power plants under Section 111 of the Clean Air Act and a new, more stringent rule for Effluent Limitation Guidelines could lead to the firm retiring the plants in the 2030s to avoid compliance costs, the Sierra Club said. 

The greenhouse gas rule exempts coal plants that retire by January 2032 from doing anything. Those that retire by Jan. 1, 2039, will have to co-fire with natural gas. Those that want to keep operating past 2039 will have to install 90% carbon capture and storage. EPA has finalized the rule, but Virginia and other states have until May 2026 to come up with compliance plans. 

EPA offered states some flexibility, but they can’t drop below EPA’s minimum requirements and can offer plants delays in compliance for only one year. 

“That will not be an inexpensive endeavor,” the Sierra Club said. “Even if the company chooses to retire by Jan. 1, 2039, it faces the still-substantial costs of retrofitting the plants for co-firing and of securing fuel supply.” 

The ELG rule requires elimination of discharge from three coal plant waste streams: flue gas desulfurization, bottom ash transport water and leachate. Coal plants have to comply by the end of the decade unless they stop burning the fuel by Dec. 31, 2034. 

In litigation against the ELG rule, an AEP executive said it could cost $680 million over the first decade of compliance at the two plants, costing residential ratepayers an average of $42 to $60 per year. 

SCC staff agreed the firm should have to keep studying the plants’ potential retirement given the uncertainty around how the two federal regulations will affect them. Their combined capacity of more than 4 GW means the regulator can’t afford to wait until the rules are finalized and should plan for generation to replace them, staff said. 

Appalachian Power continues to support the request but in its brief this week acknowledged the two EPA rules could affect the plants’ “continued economic viability as coal plants,” though the regulations’ future also is uncertain. 

“It would be of more use to the commission if the company models various scenarios that could result from such regulations,” it said. “Similarly, the company should be able to use the most current and relevant information available for its modeling assumptions.” 

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NJ Awards $4.5M for Local Clean Energy Projects

New Jersey’s Board of Public Utilities (BPU) on Aug. 14 awarded $3.4 million in grants to 18 proposals under a new program designed to help municipalities implement clean energy projects — including funds for one municipality to purchase its first electric police car. 

The awards, to 16 municipalities, made under the first-ever Community Energy Plan Implementation (CEPI) Grant Program, provide support to help implement what the BPU says are “high-priority, high-impact, practical and cost-effective municipal projects supporting energy resilience, renewable energy and energy efficiency.” 

Municipalities can apply for $250,000 under the program. In addition to unanimously approving the $3.4 million, the board also approved nearly $1.15 million for 92 grants in the agency’s Community Energy Plan Grant Program (CEPG). That 3-year-old program awards grants of up to $25,000 for local governments to develop clean energy plans, while the CEPI funds support project implementation. 

Board President Christine Guhl-Sadovy said she was “super excited” to see the awards move ahead. 

“I think it’s really exciting to see this funding going to municipalities to help with their electrification and energy efficiency goals and align with the state’s energy master plan,” she said. She later added in a press release that “as the climate crisis intensifies, every New Jersey municipality must be equipped to face its wide-ranging effects and unique impacts on individual communities.” 

The CEPI funds awarded to seven municipalities will pay for the installation of electric vehicle (EV) charging infrastructure. Two municipalities will spend the money on weatherization or energy efficiency projects. The program awarded $160,000 for Westfield Township to buy its first department EV, according to a list of recipients. 

Atlantic City and Pleasantville City each will receive $250,000 for energy improvements in city hall buildings, and a $250,000 grant will help Maplewood Township install a heat pump at the town’s police and municipal court building. 

BPU Commissioner Zenon Christodoulou welcomed the program awards and noted that 40% of the projects are awarded to overburdened communities. Twenty-nine municipalities submitted 88 projects under the CEPI program. 

“We didn’t have as many applicants as I would have hoped, maybe even would have expected,” he said before voting in support of the awards. “So maybe they feel that they don’t have the technical expertise. Hopefully we could assist them to ease that process so more overburdened communities could apply for these grants and help them directly, which I think is one of the main things we’ve been looking to do with that program.” 

In the CEPG program, the BPU awarded only 15 grants of $25,000, the largest possible grant, which is awarded to overburdened communities. The remaining 77 projects will receive $10,000, the amount awarded to applicants from non-overburdened communities. 

EV Police Pursuit Vehicle

Sgt. Gregory Penn, who helped plan the application for Westfield Township, said the award will fund the purchase of a Chevrolet Blazer PPV, which has a range of about 250 miles and can do 130 miles per hour. It is possibly the only EV model on the market that meets the standards for a police pursuit vehicle, Penn said. 

The township, with 63 officers, has 30 patrol cars, six of which are hybrid Ford Escapes. Since their arrival, the cars have significantly cut department fuel costs and showed how little maintenance is needed compared to vehicles powered solely by an internal combustion engine, he said.  

That helped pave the way to going all electric, Penn said. 

“I own a Tesla myself, so I saw the benefits,” he said. “I commute about 50 miles each way to work, and I have zero maintenance on that car, except for tires and windshield wipers.” 

The township has no EVs or municipal chargers at present, although six public chargers are available in the community, he said. The CEPI funds will pay for the municipality to install the infrastructure for Level 2 chargers, and the department will work out how to plan the vehicle’s use to allow for a charging period each day, he said. 

“I’m not saying that we can maybe completely eliminate our internal combustion vehicles right now,” Penn said. “But we’re definitely, I think, on a good way to incorporate more fully electric vehicles and hybrid vehicles into our fleet.” 

The BPU awarded the Borough of Madison two grants of $100,000 each under the CEPI. One will pay to install air-source heat pumps into the 93-year-old historic Hartley Dodge Memorial Borough Hall. The historic building “will be going through a renovation in our East Wing, which will include new heating and cooling,” and the borough’s Climate Action Committee recommended it include heat pump installation, spokesperson Michael Pellessier said. 

The second grant will fund the retrofit of the Heller Center, a Masonic lodge building that will be 200 years old next May. The borough will bring it up to building code requirements, and the East Wing will be all electric, with a mix of heat pumps and electric water heating, Pellessier said. 

Once renovated, it will be used as a senior center and public community space, he said. 

“Our experts have run numbers and expect that once completed, our heating and other costs should be decreased once the heat pumps are installed and operational,” he said. “Madison is progressive on our green actions and is always looking at ways that we can make for a greener Madison and [is] committed to projects like these. The grants that we have received make these projects even more possible and allow us to allocate funds elsewhere for other green initiatives.” 

Offshore Wind Advance

The BPU also voted unanimously to advance the agency’s fifth offshore wind solicitation and start a search for a consultant to help develop the process. 

The board voted to put out a request for qualification (RFQ) developed by agency staff seeking an expert to help develop and issue solicitation guidance documents and evaluate applications ready for final selection.  

Gov. Phil Murphy (D) in May directed the BPU to advance the fifth solicitation by 15 months to make up time lost when Danish Developer Ørsted abandoned two of the state’s first three projects in October. (See NJ Accelerates OSW Plans Again.) 

The BPU on July 10 said it received three proposals for the fourth solicitation and the agency’s timeline calls for it to award contracts by the end of 2024. The fifth solicitation is expected to open by the end of the second quarter of 2025. (See 3 OSW Proposals Submitted to NJ.) 

The BPU also took steps to conclude business with the two defunct Ørsted projects. The commissioners voted unanimously to vacate the orders approving the two projects — Ocean Wind 1 and 2 — and to set aside approvals for easements on property owned by Ocean City and the County of Cape May. Ørsted had planned to run cable on the easements to a substation sited on a now-closed coal-fired power plant in Upper Township. 

The BPU order explaining the rationale for vacating the approvals said it was part of a settlement between Ørsted and the BPU over the fate of $200 million the developer committed in spring 2023 to put in escrow. The developer pledged the funds to persuade New Jersey to allow the two OSW projects to receive the benefits of federal tax credits that otherwise would go to the state. The state agreed, giving Ørsted the tax credit benefits, then demanded the $200 million when the developer abandoned its two Ocean Wind projects. 

The two sides settled in May, when Ørsted agreed to pay the state $125 million. The agreement, according to the order approved by the BPU on Aug. 14, also stated that “for the avoidance of doubt, Ørsted will move to vacate” the project approvals and permissions for the easements. 

“State consents to such vacation and agrees to take all action reasonably necessary to effectuate such vacation,” according to the order. 

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No Grid Impacts from CrowdStrike Outage, NERC Says

VANCOUVER, British Columbia — Staff from the Electricity Information Sharing and Analysis Center (E-ISAC) said last month’s CrowdStrike outage and the resulting global business disruptions represented a “real world look at what a really bad day” could result from a potential cyberattack on critical infrastructure.

Speaking to members of the NERC Board of Trustees’ Technology and Security Committee during its open meeting, E-ISAC Vice President of Security Operations and Intelligence Matt Duncan said that while the outage caused no threats to grid reliability, it “forced entities around the world to look at how they could operate [during] such an outage.”

Angus Willis, NERC’s director of information technology infrastructure and support, confirmed that “none of [NERC’s] internal or external systems were affected” by the incident.

The CrowdStrike outage began on July 19 after independent cybersecurity firm CrowdStrike released an update for its Falcon software. According to CrowdStrike’s analysis of the incident, the update, which affected “certain Windows hosts,” contained a critical bug that led host systems to crash.

CrowdStrike’s update threw companies around the world into chaos as key systems locked up. Thousands of flights were canceled, with Delta Air Lines alone claiming that it lost $380 million in revenue from refunds and compensation payments to customers. Companies in the health care and banking sectors also reported losses of more than $1.9 billion and $1.15 billion respectively, with the total cost of the incident estimated at more than $5 billion.

All this disruption resulted from an error rather than a deliberate cyberattack, E-ISAC staff noted, with Duncan likening the incident to “a cyber hurricane.” However, the outage still required a response, from which lessons can be drawn. Affected entities spent “a significant amount of time and resources restoring their internal systems,” and in many cases companies had to activate their business continuity plans.

While the electricity sector was not directly affected by the CrowdStrike outage, the E-ISAC was actively monitoring the fallout as it developed, Duncan said. He mentioned the first reports of problems with the Falcon software were received during an unrelated event late at night, but by morning it was clear “that it was something that needed to be dealt with.”

The E-ISAC worked with the Department of Energy, the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and other stakeholders to determine the extent of the outage, and then put out an All Points Bulletin once the incident was known to be “not malicious, but still extremely impactful.” The subsequent weeks gave stakeholders a chance to evaluate their responses and how their plans held up against real stresses.

“I think this was honestly fortunate, if I can be so bold, because much like a GridEx scenario, this gave us a real-world look at what a really bad day [a] cyber, physical or even an IT outage attack would look like,” Duncan said, referring to the E-ISAC’s biennial continent-wide grid security exercise.

Duncan observed that CISA Director Jen Easterly has made similar remarks. At this month’s Black Hat cybersecurity conference in Las Vegas, Easterly called the business disruptions and resulting response a “dress rehearsal” for a potential cyberattack and compared the impact of the outage to the potential effects of the Volt Typhoon malware that the agency has attributed to China. (See CISA Highlights China Threat in 2024 Priorities Report.)

E-ISAC CEO Manny Cancel also credited CrowdStrike’s management for their quick and transparent actions throughout the incident. The company actively engaged with Microsoft early in the outage to make patches available to customers as quickly as possible.

“They took ownership of the problem right way. They said, ‘This was a mistake that we made,’ and then provided corrective action,” Cancel said. “That’s setting the bar for future events, and hopefully we don’t have them. … We’re seeing DHS call for this kind of transparency from software vendors. So we wish it didn’t happen, but really, CrowdStrike handled it very, very well.”