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November 16, 2024

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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.”

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CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan

A proposal to elevate the Western Energy Markets (WEM) Governing Body’s authority over CAISO energy markets was approved unanimously by the Governing Body and ISO Board of Governors Aug. 13.  

The proposal by the West-Wide Governance Pathways Initiative is “Step 1” in a two-step effort to establish an independent regional organization to govern CAISO’s Extended Day-Ahead Market (EDAM) and Western Energy Imbalance Market. (See CAISO Advances Pathways Initiative ‘Step 1’ Proposal to Board Vote.) 

“In a little over a year, we’ve moved from the regulator letter to a full proposal that is before us today that will enhance and reinforce the capabilities of the Western energy markets,” Scott Ranzal, director of portfolio management at Pacific Gas and Electric, said during the meeting. 

“A celebration of today’s vote and hope for the approval is certainly warranted, but it should quickly follow with additional action and effort to address the growing needs of the Western energy markets and that continued need for regional collaboration,” Ranzal said.  

The proposal received wide support, with 22 entities participating in the Step 1 stakeholder process expressing approval, six remaining neutral and one member of the public opposing.  

Before the proposal went up for a vote, Adam Schultz, manager of regional coordination at CAISO, provided an overview of stakeholder comments received in the process, placing them in two primary categories.  

The first category included stakeholders’ desire for more clarification of “exigent circumstances” that the straw proposal states are necessary if dispute resolution between the ISO board and the Governing Body is exhausted before a FERC filing.

The second concerns the trigger mechanism requiring that the FERC tariff filing needed to establish the Governing Body’s primary authority over EDAM/WEIM issues wait until the EDAM obtains implementation agreements from a “set of geographically diverse” EDAM participants representing load equal to or greater than 70% of CAISO’s balancing authority area annual load in 2022. The category also included concerns related to the scope of “primary authority” and with public interest language in the charter.  

Schultz reiterated that issues in the first category were “exhaustively considered” by the Pathways Launch Committee. Topics in the second category included ensuring continuing collaboration between the board and the Governing Body, logistical details for the dual filing mechanism and the process for implementing Step 1.  

Schultz said the second category of comments represented issues at a level of implementation detail not considered in depth by the Launch Committee and that will be considered later in a different stakeholder process.  

‘Hang in There’

Several officials spoke in support of the proposal and applauded the quick work it took to develop it.  

“I believe the best governance is created by stakeholders through a broadly representative process,” WEM Governing Body member Andrew Campbell said. “The universe of stakeholders needs to include the market participants, as well as the state government representatives and nongovernmental organizations that represent the public interest. Today’s proposal is consistent with that principle.”  

Other CAISO officials saw the success of implementing Step 1 as a boost of confidence for the challenge ahead.  

“Step 2 is going to be a heavier lift and a challenge, and I just want to encourage everyone to hang in there,” said ISO board Vice Chair Severin Borenstein. “This showed a lot of cooperation and willingness to work together. We’re going to need that for Step 2, which I think is where the real value will be unlocked.” 

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Markets+ Backers Highlight Reliability in 2nd ‘Issue Alert’

The integration of Markets+ with the Western Resource Adequacy Program (WRAP) would be among a handful of key reliability benefits of SPP’s Western day-ahead offering, according to an “issue alert” published Aug. 13 by 10 entities that backed development of the market.

The alert, sent to the Markets+ States Committee (MSC) on Aug. 13, is the second in a series of seven such notices intended to highlight the purported advantages of Markets+ over CAISO’s Extended Day-Ahead Market (EDAM) and Western Energy Imbalance Market (WEIM). The first covered differences between how the two markets would be governed. (See Governance is ‘Key Consideration’ for West, Markets+ Backers Say.)

The Markets+ Phase 1 Funding Parties include Arizona Public Service, Powerex, Public Service Co. of Colorado, Salt River Project, Tacoma Power, Tri-State Generation and Transmission Association, Tucson Electric Power, and the Chelan, Grant and Snohomish public utility districts of Washington state. The alerts aren’t vetted by the MSC and don’t represent the positions of the committee or of the staff for the Western Interstate Energy Board, which hosts both the MSC and the WEIM’s Body of State Regulators.

“Market design elements that support electric system reliability must be considered prior to joining a market, as reliable service is not only expected by consumers; it is also essential to the safety and wellbeing of the general public,” the alert said. “As evidenced by the impact of extreme weather events over the past several years, reliability risk is elevated.”

The alert contends Markets+ will address that risk because its “robust, stakeholder-driven governance framework” produced a market design with a “strong focus” on reliability. The parties to the notice also point out SPP has a “long track record” as a reliability coordinator in both the Eastern and Western interconnections and through operation of the SPP RTO and Western Energy Imbalance Service (WEIS).

But the integration of Markets+ with the Western Power Pool’s (WPP) WRAP, which SPP operates on behalf of the WPP, gets top billing in the alert. Under the Markets+ tariff, market participants must join the program “because a common and rigorous resource adequacy structure is foundational to reliability and critical to achieving equitable outcomes within a market footprint,” according to the alert.

“WRAP applies a common approach for calculating resource capacity values and determining each participant’s minimum obligation for resource adequacy, which, in the context of Markets+, will prevent market participants from being over-reliant on others’ resources,” the parties wrote, adding that the arrangement will ensure that capacity obligations — and the benefits of regional diversity — are “distributed equitably.”

The parties also contend the WRAP component of Markets+ will provide visibility into how various resources perform during critical hours “in a way that does not currently exist” and enforce resource deliverability requirements that will incentivize development of new transmission, “supporting reliable service to customers and the efficient integration of clean energy resources.”

The alert further said Markets+ “builds upon” WRAP’s forward resource procurement requirement — an explicit commitment to make resources available during a specific time frame — that ensures the market has sufficient generation on hand during real-time intervals through use of a must-offer requirement that can only be satisfied by WRAP supply or other “specified resources.”

“This approach improves reliability in the West by addressing those instances where historically some energy commitments have not been backed by reliable physical supply (and ultimately did not deliver to load),” the alert said.

The WRAP originally was scheduled to begin its “binding” penalty phase in summer 2026, but this spring program stakeholders requested that step be delayed until summer 2027, saying supply chain delays, rapid growth in regional peak load and extreme weather events affect participants’ ability to procure enough capacity to meet RA requirements. (See WRAP ‘Binding’ Phase Delay Finds Stakeholder Support.)

‘Fundamentally Different’

Non-California participants in CAISO’s WEIM and EDAM are not required to participate in a resource adequacy program, but California utilities are subject to one overseen by the state’s Public Utilities Commission. To prevent participants from leaning too heavily on the WEIM/EDAM to meet forecasted demand, CAISO instead administers a resource sufficiency evaluation ahead of each market interval to gauge whether each member is prepared to cover expectations for that interval.

The alert singles out that practice for particular criticism.

“Resource sufficiency tests applied in the operating time frame without the underpinning of a common resource adequacy program are inherently challenging for several reasons,” the alert contended. “These reasons include challenges in accurately applying such a test, insufficient failure consequences to prevent deliberate leaning and insufficient notice of a deficiency due to the late timing of the test.”

The alert called the tests “flawed,” saying there have been “numerous examples of inaccurate outcomes” stemming from differing treatment between WEIM balancing authority areas and the CAISO BAA, although no specific examples were cited.

“This experience has reduced some stakeholders’ confidence that an accurate resource sufficiency test will be applied in the day-ahead time frame for the Extended Day-Ahead Market,” the parties to the alert wrote.

The alert additionally criticizes the WEIM/EDAM approach for resulting in “inadequate consequences.”

“Regardless of whether a resource sufficiency test is applied accurately, a standalone resource sufficiency test does not provide adequate time to resolve supply deficiencies that may be identified,” it said. “As a consequence, such a test necessarily relies on failure consequences that are known ahead of time to create incentives for participants to procure sufficient supply in advance to avoid failing.”

The alert also argues that the lack of a common RA framework in the WEIM/EDAM could reduce liquidity in the day-ahead market because participants might hold back supply “in order to manage unforeseen risks in their individual areas through real-time operations.”

“Such voluntary holdback actions for local reliability further diminish available resources in the market, diminishing the market’s overall reliability and efficiency,” it said.

The alert also cautions that utilities participating in both the WRAP and WEIM/EDAM could incur additional costs for having to meet two “unlinked” requirements: the WRAP’s forward-showing obligation and WEIM’s sufficiency test.

“Ensuring reliability is an essential priority that Markets+ and EDAM seek to address in fundamentally different ways, resulting in material differences in the reliability risk that will prevail in each market,” the alert said.

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Dominion and Equinor Win OSW Lease Auction

Two Central Atlantic offshore wind areas drew a combined $92.65 million in high bids Aug. 14 during the region’s first federal wind lease auction in a decade. 

The U.S. Bureau of Ocean Energy Management declared Equinor Wind and Dominion Energy the provisional winners among six bidders for the two leases off the Delaware and Virginia coastlines. 

Equinor beat out other bidders in multiple rounds of bidding with a $75 million final offer to lease OCS-A 0557. The Norway-based energy company has a worldwide offshore wind portfolio that includes Empire Wind off the New York coast. 

OCS-A 0557 totals 101,443 acres with a potential installed generation capacity of 1.2 GW to 2.3 GW. 

Dominion, bidding as Virginia Electric and Power Co., submitted the only bid to lease OCS-A 0558 and offered the minimum price: $17.65 million. Dominion currently is building Coastal Virginia Offshore Wind, a 2.6-GW project that is the largest yet approved for construction in U.S. waters. 

OCS-A 0558 totals 176,505 acres, with a potential installed generation capacity of 2.1 GW to 4.0 GW. 

In a news release, Interior Secretary Deb Haaland noted how far offshore wind has come: 

“At the start of the administration, our nation had approved zero offshore wind energy projects. Today, we have nine — enough to power nearly 5 million homes. This is what developing a clean energy transition looks like.” 

The U.S. offshore wind sector has grown greatly during the Biden administration yet has struggled mightily with local and global headwinds. 

The 2024 Central Atlantic auction attracted far higher bids than the 2023 Gulf of Mexico auction ($5.6 million) but far lower than BOEM’s 2022 auctions in the New York Bight ($4.37 billion), North Carolina ($315 million) and California ($757 million). 

BOEM plans offshore wind lease auctions this year off the Oregon coast and in the Gulf of Maine. It canceled a planned Gulf of Mexico auction for lack of competitive interest. 

Dominion provisionally won the OCS-A 0558 lease without competition at a substantially lower price than OCS-A 0557 commanded, even though OCS-A 0558 is substantially larger and potentially can site many more wind turbines. 

The final sale notice flagged some potential complicating factors for wind energy development in OCS-A 0558, including NASA launch operations and extensive military activity in the region.  

BOEM warned prospective bidders, for example, that conflicts with the U.S. Navy’s advanced radar system at Naval Air Station Patuxent River could force up to 1,750 hours of wind turbine curtailment per year. 

A third wind energy area in the region presents even more potential conflicts and was removed from consideration for this auction.  

A Dominion spokesperson told NetZero Insider it’s too early to say how these restrictions would affect the utility’s planning but that potential future wind energy development would engage all stakeholders. 

OCS-A 0558 is 35 nautical miles east of the mouth of the Chesapeake Bay, directly east of and contiguous to OCS-A 0483, which Dominion acquired for $1.6 million in a 2013 auction. It is building Coastal Virginia Offshore Wind (CVOW) there. 

Nearby, off the northernmost coast of North Carolina, Dominion has agreed to buy OCS-A 0559 from Avangrid, which had planned to develop it as Kitty Hawk North and ran into local opposition with its plans for an export cable making landfall in Virginia Beach. 

If the sale is finalized, Dominion may develop the area as CVOW-South. (See Dominion to Buy Kitty Hawk North Offshore Wind Lease.) 

A proposal was floated this year to bring competition to offshore wind development in Virginia waters. Senate Bill 578 called for a competitive procurement process in which Dominion could submit bids but not evaluate them or select awardees. The measure was pushed back to the 2025 legislative session. 

The provisional winners were happy about the result of the Central Atlantic auction. 

Molly Morris, president of Equinor Renewables Americas, said in a news release, “Equinor’s interest in this auction is consistent with our approach to pursue attractive offshore wind opportunities in the United States. The Central Atlantic region has … rapidly growing demand for electricity, with widespread support for adding renewable sources of energy into the power mix.” 

Dominion said the move would expand options for an all-of-the-above approach to meeting unprecedented electric demand in Virginia. “Winning this lease area gives us another low-cost option to meet that growing demand while providing our customers with reliable, affordable and increasing clean energy,” CEO Robert Blue said. 

Trade association Oceantic Network hailed the auction results and cast an optimistic eye to the future, noting there is bipartisan support in the region for offshore wind even as wind energy foe Donald Trump fights to return to the White House.

“Today’s successful auction demonstrates that offshore wind will continue to play a leading role in the region’s energy future,” Oceantic CEO Liz Burdock said. “The resulting leases will strengthen an emerging manufacturing hub in the mid-Atlantic, creating a dependable pipeline of contracts well into the next decade. Despite the general uncertainty around the upcoming presidential election, this is a vote of confidence for an American industry that has already received more than $2 billion of new supply chain investment in the first half of 2024.” 

The Mid-Atlantic Renewable Energy Coalition, a nonprofit advocacy group, hailed the auction results for their impact on the region. Executive Director Evan Vaughan said, “Today’s auction for the right to develop offshore wind farms off the coast of Mid-Atlantic states makes clear that a combination of state policies in Maryland, Delaware, New Jersey and Virginia, along with rising electricity demand, are attracting major interest from our growing industry. MAREC Action congratulates Equinor and Virginia Electric and Power Co. on their winning bids today — consumers will be the ultimate winners of this new source of reliable clean energy.” 

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Grid Storage Launchpad Opens at Pacific Northwest Lab

The U.S. Department of Energy is looking to supercharge research, development and deployment of advanced and long-duration energy storage (LDES) technologies with the Aug. 13 ribbon cutting at the Grid Storage Launchpad (GSL) ― a high-tech lab and testing facility ― at the Pacific Northwest National Laboratory (PNNL) in Richland, Wash.

The 93,000-square-foot facility includes 30 “specialty” labs where a team of about 100 researchers will use “artificial intelligence to discover new energy storage materials and [test] their performance on the grid using digital twins, smart data models based on physics and high-speed experimentation,” according to the GSL website.

For example, one of the labs will have “pilot-scale prototyping equipment” that will allow researchers to quickly design, produce and test prototypes of emerging storage technologies, while another lab will simulate real-life grid conditions to test the performance of new batteries, first up to 10 kW and then up to 100 kW.

Estimated cost for the GSL is $75 million, with $35 million of the total coming from Washington state, PNNL and Battelle, a science R&D firm that operates the lab for DOE.

Kevin Schneider, a lab fellow and manager for DOE, said having all the research and testing facilities in one building will help accelerate the development of new battery technologies.

“Right now, we have many of these capabilities spread across the [PNNL] campus; so, you complete work in one area, it has to be transported somewhere else. … It takes time and effort,” Schneider said during a phone interview with NetZero Insider. “In the new facility, it’s been laid out in such a way that there are three research corridors, starting with basic chemistry and working its way [to testing], so that there are workflows within the building that allow us to move from one lab to the next very quickly. Those types of structures allow for a surprising kind of increased productivity.”

Schneider also pointed to the lab’s six testing bays, which will test new storage chemistries up to 100 kW, a level specifically requested by industry partners, who told the lab if a technology works at 100 kW, they can begin commercialization.

“So, there’s no need for us to be able to test 1 MW or 10 MW,” Schneider said. “It’s very large and expensive. If it proves out at 100 kW, then they’re ready for deployments.”

The GSL is the only national lab facility with this level of storage testing capability, he said.

Speaking at the ribbon cutting, Sen. Maria Cantwell (D-Wash.) also stressed the importance of the industry partnerships that will be built at the new facility.

“If we want to make the next generation of batteries, we need the energy storage advancements that are here, with the brightest minds at PNNL … just really working together and discovering new and more efficient materials that are faster, cheaper by going from computing, modeling to prototyping to testing and under realistic grid conditions,” Cantwell said.

“This facility will help ensure the advancements in energy storage really do translate to the private sector, creating new innovative battery products as well as dependable manufacturing jobs,” she said.

Geri Richmond, DOE under secretary for science and innovation, spoke of the impact of storage she’s seen while visiting remote tribal communities in Alaska.

“In this job, I’ve had the opportunity to go to places that have been underserved for way too long,” Richmond said. “Having access to storage … allows those tribes in Alaska to not just burn that [fossil] fuel 24/7, that stinks up the town, and it’s loud. I’ve seen what a difference it makes to have storage capacity there. There is so much for us to do and to reach, again, every possible community that we can.”

The facility also will provide technical training for a range of stakeholders, from workers and utility planners to regulators, as well as safety training for first responders.

Cheap, Abundant ‘Local Dirt’

The GSL is a critical part of DOE’s efforts to accelerate the development of new energy storage technologies at commercial scale and at a competitive cost.

The industry’s reliance on lithium-ion batteries has become a political flashpoint due to China’s dominance in the processing of lithium and manufacture of battery cells. The goal for GSL is to develop technologies that use “local dirt,” that is, cheap and abundant materials that come from local sources, Schneider said.

For the United States to achieve its goal of a net-zero economy by 2050, DOE estimates the country will need between 225 GW and 460 GW of LDES, defined as storage with anywhere from 10 hours to more than 160 hours of duration.

Developing these technologies will require more than $330 billion in private investments, while saving $10 billion to $20 billion per year in operating costs and avoided capital spending.

The Energy Storage Grand Challenge was announced in December 2020, with the goal of developing domestic supply chains and manufacturing that could provide all the storage technologies needed to meet U.S. market demand by 2030.

The department launched its Long Duration Storage Shot in 2021, with the goal of reducing the cost of LDES by 90% within a decade. As part of the initiative, DOE awarded $15 million in April to three projects aimed at overcoming technical barriers to the commercialization of long duration storage, such as testing the use of zinc for battery electrodes.

Deployment of grid-scale storage is spreading. As the amount of renewable solar and wind on the grid continues to grow, storage has become vital for time-shifting that intermittent power, storing electricity from mid-day hours, when excess is generated, to be used in the late afternoons and evenings when extra power is needed.

In the past four years, California has deployed 9,000 MW of storage, which has helped CAISO manage extreme heat and high demand, CEO Elliot Mainzer said at a recent online forum sponsored by USEA. (See Demand Growth and Extreme Weather: The Grid’s New Normal.)

Similarly, solar and storage provide ERCOT with the flexible capacity it needs to ride through the late afternoon drop-off of solar energy, CEO Pablo Vegas said at the forum. “This may be the last year that we have real significant risk at solar sunset,” he said. “If we continue to see that trajectory by 2025 into 2026, we could see the summer risk period significantly mitigated because batteries are picking up some of the transition solar ramps as we see the wind come on in the evening.”

But echoing speakers at the GSL ribbon cutting, Schneider said, accelerating the development of new storage technologies remains a high priority. It took decades to develop the lithium-ion batteries powering today’s electric vehicles and grid-scale storage, he said.

“We don’t have another 30 years for the next chemistry to come out,” he said. “We need to be able to do what took 30 years in the next five to 10.”

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2023 Queue Cycle Delayed into 2025 as MISO Seeks Software Help on Studies

MISO said its 123-GW collection of projects in the 2023 queue cycle will be subject to another delay into early 2025 as it pauses to see if a tech startup can help it better scale interconnection studies.  

In an email to stakeholders Aug. 13, MISO announced it will hold off on starting the definitive planning phase for the 2023 interconnection until February. The RTO said the extra time will allow it to enlist the help of Pittsburgh-based Pearl Street Technologies to better manage interconnection studies.  

MISO previously said it solicited help from Pearl Street Technologies to see if the company’s SUGAR (Suite of Unified Grid Analyses with Renewables) software can speed up interconnection studies. Pearl Street has claimed its software can model more generation projects for transmission operators and drastically cut back time spent on engineering analysis.  

MISO said the delay in conducting studies ultimately will help it “process more interconnection applications in a timely manner.” It also said it would expand Pearl Street’s assistance from model development to power flow analysis and network upgrade identification.  

“MISO would like to take this opportunity to reassure customers that we are committed to processing interconnection requests in a timely manner,” the RTO said to its stakeholders.  

In a statement to RTO Insider, MISO said it’s working with Pearl Street to establish some automation in the queue study process that will allow it to complete the first phase of studies more quickly. The RTO said it would begin studies on the 2023 cycle after it can implement automation and after the 2022 cycle of projects clears the first study phase of the three-part interconnection queue.  

If it deems all the 2023 applications valid, MISO has said its queue could grow to nearly 350 GW.  

MISO told stakeholders more discussion on the 2023 queue class will take place at upcoming meetings of the Planning Advisory Committee and Interconnection Process Working Group.  

The 2023 queue cycle already was delayed last year, as MISO sought permission from FERC for steeper penalties, higher fees and more binding proof of land use as a means to get a handle on the sheer number of projects lining up annually for grid treatment. The grid operator ultimately didn’t begin certifying the 2023 class until spring of 2024.  

The 2024 cycle also is destined for delays. While it’s unclear if the current software delay will affect when MISO begins processing 2024 entrants, MISO already planned to postpone this year’s cycle while it tries again to win FERC approval of an annual megawatt cap on projects that may enter. (See MISO Sets Sights on 50% Peak MW Cap in Annual Interconnection Queue Cycles.) 

MISO said it doesn’t “anticipate closing the window for the next queue cycle until after a cap filing is submitted and accepted by FERC, which is currently on track for 2025.” MISO pointed out it’s currently accepting online applications for the next cycle of interconnection requests, though it’s waiting to kick off any studies.  

Meanwhile, clean energy developers’ interest in queueing up appears full steam ahead. Last week, developers Ørsted and Mission Clean Energy announced their intent to join forces to build 1 GW of battery storage in MISO Midwest. Mission Clean Energy plans to submit applications for four projects across MISO’s North and Central regions and give Ørsted the option to buy an ownership stake later in the process.  

Ørsted said the storage plans are its first-ever standalone battery storage partnership, in the U.S. or globally.  

“Continuing to invest in and build out storage solutions is critical for ensuring a resilient and reliable grid, and this partnership with Mission advances this important goal,” Ørsted Chief Commercial Officer James Giamarino said in a release.

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FirstEnergy Pays Ohio $20M to End Bribery Scandal Litigation

FirstEnergy has reached an agreement with the Ohio Attorney General and the Summit County Prosecutor to resolve all outstanding proceedings on the firm’s bribery scandal. 

The $20 million deal with the state and the county prosecutor comes three years after the firm agreed to pay a $230 million fine to the U.S. Department of Justice in a deferred prosecution agreement. (See DOJ Orders $230 Million Fine for FirstEnergy.) 

In addition to sinking the careers of leadership at FirstEnergy, its $61 million in bribes and dark money campaign contributions brought down former Ohio House Speaker Larry Householder and former PUCO Chair Sam Randazzo, who committed suicide this year. (See Scandal-ridden Former PUCO Chair Sam Randazzo Found Dead.) 

“We are pleased to have reached a resolution with the Ohio Attorney General’s Office and the Office of the Summit County Prosecutor, which recognizes the substantial actions FirstEnergy has taken to establish a highly effective compliance program and instill a culture of ethics and integrity at every level of the organization,” FirstEnergy CEO Brian X. Tierney said in a statement. “FirstEnergy, led by a new Board of Directors and executive team, is a stronger organization today, energized by our commitments to our stakeholders and well positioned for the future.” 

The scandal involved trying to get the Ohio Legislature to pass subsidies for nuclear plants FirstEnergy used to own, which it since has spun off into Energy Harbor. That firm was purchased by Vistra Energy in a deal that closed early this year. 

FirstEnergy filed the settlement with the Securities & Exchange Commission, which credits the firm with cooperation and says the state will not pursue any charges against it for the conduct covered by the deferred prosecution agreement it signed with DOJ in 2021. 

In addition to paying $20 million, FirstEnergy agreed to set up a new Office of Ethics and Compliance and to develop a compliance program designed to prevent violations of U.S. and Ohio regulations and law. The program will include companywide campaigns to get employees and contractors to report any concern about potential violations. 

Of the $20 million, $500,000 is set aside to fund the compensation and expenses of an independent consultant to review the efficacy of its compliance programs. 

The deal covers only the firm FirstEnergy and specifically does not cover any litigation against former employees or executives. The state has indicted former CEO Charles Jones and former Senior Vice President of External Affairs Michael Dowling. (See Ex-PUCO Chair, Ex-FirstEnergy Execs Indicted in Ohio.)