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December 13, 2025

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CAISO Monitor Sees ‘Gaming’ Potential in Battery Storage Bid Cost Recovery

CAISO’s Market Monitor is concerned about potential gaming and inefficient bidding behavior in CAISO’s bid cost recovery (BCR) process for battery storage resources. 

The current BCR design creates gaming opportunities for battery storage units, “especially through manipulation of various biddable parameters used to manage [a battery’s] state-of-charge,” CAISO’s Department of Market Monitoring (DMM) said in its annual market performance report, published Aug. 7. 

“Gaming concerns are exacerbated by the fact that bid cost recovery payments are partly driven by submitted bid prices, meaning that inflated bids can cause BCR payments to drastically exceed any economic losses caused by reversal of day-ahead schedules,” DMM said in the report. 

Battery storage capacity in California has grown from 500 MW in 2020 to almost 14,000 MW as of August. An additional 14,000 MW of battery storage capacity is planned to be online by 2030, pushing CAISO’s total to about 28,000 MW by that year. 

In 2024, battery storage facilities received about $18 million in real-time bid cost recovery — about 11% of all bid cost recovery in the year. However, battery storage resources are different from conventional resources: They do not have start-up, shut-down, minimum load or transition costs — the primary drivers of BCR, the report says. 

Historically, BCR has applied to generation facilities as a method to reduce their risk of receiving insufficient revenue to cover start-up and minimum load costs, the report says. As opposed to conventional thermal resources that are incentivized to bid their marginal energy production costs, storage resource bids do not solely represent the costs to discharge or charge energy in a given interval, CAISO said in a November 2024 letter to FERC on the issue. 

“As a result, bid cost recovery payments to storage resources may result in compensation exceeding the resource’s costs,” CAISO said in the letter. 

In its Aug. 7 report, DMM recommended that battery storage resources should be, in general, ineligible for BCR, with a limited number of conditions in which they would be eligible for BCR. The report notes that batteries do have certain limits that can result in BCR payments, specifically state-of-charge constraints that limit a battery storage unit’s charging and discharging behavior. 

But, as a general principle, when batteries are constrained by operational parameters set by unit operators to manage battery operation, “batteries should be ineligible for BCR payments,” the DMM’s report says. 

Additional Revisions

In November 2024, CAISO filed a tariff amendment to address the battery storage BCR gaming concern. The tariff amendment caps battery bids when calculating bid cost recovery payments, which will mostly address the ability of batteries to inflate unwarranted BCR payments, DMM’s report says. 

However, unwarranted BCR payments will continue after the policy change is implemented because batteries with day-ahead schedules will continue to have distorted bidding incentives in real time, DMM’s report says. This is because the largest driver of real-time battery BCR is due to lost revenues of buying or selling back day-ahead schedules, the report says. 

The current BCR design “essentially removes the economic incentive for battery operators to bid in a way that is likely to ensure that batteries are fully charged up at the start of the peak net load hours when prices are highest and batteries are most needed for system reliability,” the report says. 

Responding to questions from RTO Insider, a CAISO spokesperson said the ISO and stakeholders developed market design changes in 2024 to eliminate the potential for strategic bidding that would unduly inflate battery BCR payments. While those changes addressed an important concern, CAISO is working through additional issues related to market efficiency and improving the incentives for batteries to bid in a manner that is cognizant of real-time prices, the spokesperson said. BCR payments to batteries have remained stable even with significant battery fleet growth, they said. 

CAISO is working on additional revisions to the BCR process within the agency’s storage design and modeling initiative that started in 2025. 

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BPA Issues Final Long-term Power Contract, Updates Strategic Plan

The Bonneville Power Administration has finalized the set of policies and records of decision (RODs) underlying its long-term power sales contracts and has taken additional steps to align with President Donald Trump’s priorities, CEO John Hairston said during the agency’s quarterly business review Aug. 14.

The policies and RODs build on the agency’s provider-of-choice policy issued in March 2024 and provide more details about the products and services it offers under the new long-term contracts. The goal is to complete all contract offers by Sept. 30 and for customers to return signed contracts by Dec. 5, allowing BPA to execute them by the end of the year, Hairston said. (See BPA Close to Issuing New Long-term Power Contract.)

“This has been an incredibly iterative and collaborative process,” Hairston noted. “BPA greatly appreciates the time and energy invested by so many people to ensure we establish a foundation for stable, competitively priced and flexible power sales. The long-term certainty provided by these contracts will support regional economic stability and help ensure a more reliable and affordable power supply for customers we serve.”

BPA has updated its strategic plan in accordance with the Trump administration and the Department of Energy’s goal to provide “more secure, reliable, abundant and affordable energy,” Hairston said.

One change, Hairston added, is that the agency has removed objectives related to diversity, equity and inclusion to align with executive orders issued shortly after Trump took office.

“Other minor refinements reflect the department’s focus on energy addition, not subtraction, and strengthening grid reliability and security,” Hairston said.

Hairston highlighted other BPA projects, including a partnership with Energy Northwest to increase the output of the Columbia Generating Station by 162 MW in a $700 million project, and an upgrade to Montana-to-Washington transmission aimed at expanding capacity.

He commented on BPA’s new power and transmission rates for fiscal years 2026 to 2028. Customers’ power rates will increase by about 8 to 9% over the next three years, while transmission rates will jump by an average of nearly 20%. (See BPA Customers to See Increased Power, Transmission Rates.)

“The new rates balance the need to keep rates low and stable while supporting power and transmission system investments to meet customer load growth and connect new generation,” Hairston said. “The rates we adopted are the product of multiple settlements that required hard work and collaboration.”

The administrator noted the June 12 presidential memo directing the federal government to withdraw from a deal the Biden administration signed that eventually could have led to breaching several dams operated by BPA on the Snake River. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams.)

“The federal parties provided notice of withdrawal on June 24, which also made clear that the federal government is willing to engage in good faith efforts to seek a satisfactory solution to the pending litigation and concerns of various stakeholders,” Hairston said.

Financial Outlook

BPA’s forecast for net revenue in the third quarter of 2025 is $184 million, a $26 million decrease from the second quarter but higher than the $70 million target.

Power services’ net revenue forecast is $105 million, $27 million above target. Transmission services’ net revenue forecast is $73 million, $80 million above target.

“BPA’s above-targets results are mainly due to higher power and transmission revenues, lower-than-predicted Integrated Program Review expenses and debt-management actions,” according to a news release. “Notably, BPA was able to use liquidity tools to offset its largest power purchases in January and February through a federal debt-management transaction that allowed BPA to realize significant gains.”

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New York PSC Denies NYPA’s Clean Path Transmission Priority Status

The New York Public Service Commission has denied the New York Power Authority’s petition to grant the Clean Path New York transmission project priority status, finding that the utility did not demonstrate it would relieve congestion (20-E-0197).

Instead, the PSC said, NYPA relied “on a recitation of the state’s future needs for renewable generation and the presence of a significant amount of proposed projects in the NYISO interconnection queue to justify designating the project as a” priority transmission project (PTP).

“NYPA does not provide any evidence of existing congestion and does not even meet the standard … for establishing a need to unbottle renewable resources,” the PSC wrote in its Aug. 14 ruling. “This approach overlooks the [PSC’s] emphasis” in its criteria for identifying PTPs “on the need to unbottle existing generation, and therefore misses the mark.”

The PSC noted that recent NYISO studies and the Coordinated Grid Planning Process do not show Clean Path being needed “expeditiously.” It cited the ISO’s 2023-2042 System and Resource Outlook, which found that Clean Path would reach only 47% utilization by 2040.

“Even if we assume the project is technically capable of meeting future needs, designating it as a PTP now would mean charging ratepayers for transmission facilities that will not begin conducting significant amounts of generation until a point in the future that may be two decades away,” the PSC wrote.

Clean Path originally was an $11 billion project that included transmission and renewable generation components. In 2024, NYPA terminated Clean Path’s renewable energy certificate by mutual agreement with the New York State Energy Research and Development Authority. In February 2025, it submitted an updated petition for the transmission portion that came in about $5.2 billion. (See NYPA Argues Clean Path Potential Benefits Outweigh Cost.)

The PSC found that Clean Path could not be justified as a near-term solution to the ongoing reliability issues affecting New York City because NYPA’s petition did not identify any new renewable generation that would be delivered through it.

“The record does not show that the project will deliver significant amounts of generation output to the New York City grid until the 2040s,” the PSC wrote. “If reliability issues arise in the 2030-2035 time frame, the project would not provide a solution.”

The project would have included 178 miles of HVDC line between upstate New York and Queens.

The PSC broadly agreed with NYPA that new transmission is necessary but that projects based on “generation to be built in the future” do not rise to the same urgency as unbottling existing generation. The commission also rejected NYPA’s argument that the existing planning processes take too long to develop a solution to New York’s reliability issues.

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New Report: Consumers Could Pay $3B More Annually if DOE Stay-open Orders Persist

A new Grid Strategies report concludes that if the U.S. Department of Energy continues to supersede retirement decisions for fossil-fueled power plants, it could cost consumers an extra $3 billion annually in a little more than three years.

The report, “The Cost of Federal Mandates to Retain Fossil-Burning Power Plants,” said if the DOE’s trend of stay-open orders persists, it could affect the 34.95 GW of large fossil power plants scheduled to retire between now and the end of 2028.

The Aug. 14 report estimated the cost of DOE mandates on the almost 35 GW of generation could climb to $260 million due monthly by January 2029.

Author and Grid Strategies Vice President Michael Goggin said added costs could surge to nearly $6 billion per year at the end of 2028 if owners of other aging power plants, enticed by revenue guarantees associated with the DOE’s mandates, announce earlier retirement dates.

Environmental nonprofits Earthjustice, Environmental Defense Fund, Natural Resources Defense Council and Sierra Club commissioned the report after the DOE in May issued two mandates to keep Constellation Energy’s Eddystone oil and gas power plant in Pennsylvania and Consumer Energy’s J.H. Campbell coal plant in Michigan operating about three months past their announced retirement dates. (See DOE Orders PJM, Constellation to Keep 760-MW Eddystone Generators Online and DOE Orders Michigan Coal Plant to Reverse Retirement.)

“Based on the trend to date and indications that DOE has approached the owners of many retiring fossil power plants about potentially mandating their retention, DOE may attempt to mandate the retention of nearly all large fossil power plants slated for retirement between now and the end of 2028,” Goggin wrote.

The report used the 34.95 GW slated for retirement in a low-end estimate and 66.34 GW in a high-end estimate, in which it assumed other plants would announce accelerated retirements.

To arrive at the 66 GW tally, Grid Strategies combined the 35 GW in confirmed announcements with another 31.39 GW of fossil fuel generation across 36 plants that are at least 60 years old.

The nearly 35 GW figure did not include the little more than 8 GW of retiring fossil plants that have at least some replacement fossil capacity planned on site. It also excluded about 310 MW of retiring fossil plants that are smaller than 50 MW.

The report said in all, the DOE could deliver mandates to 90 aging power plants across the country.

Grid Strategies noted that MISO’s median retirement age for its coal plants is around 60 years, while data from the U.S. Energy Information Administration pins the median age of coal plant retirement at 54 years in 2024. Goggin wrote that the 60-year age screen “should provide a conservative estimate of the total fossil capacity that is likely to retire.”

Estimated monthly costs of the DOE keeping about 35 GW of retiring fossil plants online from mid-2025 through 2028 | Grid Strategies

Grid Strategies used an average $89,315/MW-year cost of keeping a plant open, bringing the total annual ratepayer cost by the end of 2028 to $3.121 billion in the low gigawatt estimate and $5.925 billion in the high estimate.

The consulting firm calculated a weighted average cost of recent reliability-must-run (RMR) contracts across the country to come up with the $89,315/MW-year value. It reviewed RMR contracts for Brandon Shores, Wagner and Indian River in PJM; Lakefront Unit 9 and Rush Island in MISO; Braunig Unit 3 in ERCOT; and six units including Midway in CAISO. Contract costs ranged from $49,858/ MW-year for Wagner to $167,619/ MW-year for Lakefront Unit 9.

Goggin said the contract costs should provide a reasonable proxy for ratepayer subsidies paid out under DOE mandates. However, he acknowledged that the first two plants to be kept online are in uncharted territory, with “scant precedent for determining ratepayer subsidy costs for keeping plants open past their scheduled retirement date” due to DOE intervention.

Consumers Energy reported that the J.H. Campbell plant accumulated $29 million in costs after a little more than a month of extended operations. (See DOE Extension of Michigan Coal Plant Cost $29M in 1st Month.) Goggin said if that “cost trend were to persist, that would translate to $279 million in annual cost or $178,559/MW-year, almost exactly twice our estimate.”

The report also noted that the Citizens Utility Board estimates the cost for the Campbell and Eddystone plants at a weighted average annualized cost of $181,200/MW-year, more than twice the report’s estimate.

Grid Strategies determined that California has the most to lose in the low-end estimate, at an annual cost of $389 million by the end of 2028. Texas and Colorado follow at $183 million and $178 million, respectively, per year. Michigan, Louisiana and Illinois — all MISO states — also would register noteworthy costs at $171 million, $164 million and $161 million, respectively.

The report assumed that states that don’t contain plants slated for retirement, including the six New England states, New York, Hawaii, Alaska, Oregon and South Carolina, would be unaffected by DOE stay-open mandates in the low-end scenario. In all, it said ratepayers in 39 states and the District of Columbia stand to incur costs if the DOE doles out mandates to all plants currently counting down to a retirement date.

The analysis assumed plants don’t begin receiving funds to stay open until a month after their scheduled retirement. Goggin noted that the DOE could issue mandates earlier than that.

Grid Strategies said it chose to include potential plants that aren’t yet slated for retirement in the high estimate because the DOE’s actions could create a “perverse incentive” for plants to declare earlier retirements, so they’re paid to remain open.

“This perverse incentive is what economists would call a moral hazard,” Goggin wrote.

Goggin wrote that the report’s eye-popping cost estimates conflict with the April presidential executive order that charged the DOE with issuing mandates, which emphasized rising demand from AI data centers and domestic manufacturing and protecting the “the national and economic security of the American people.” Goggin said it’s “intuitive and inherent” that the DOE keeping plants operating would drive up customer bills.

“Power plants have been slated to retire because their owners and state regulators have determined they are no longer economic or needed. DOE mandates override those well-informed decisions, inflating electric bills for homeowners and businesses and undermining the competitiveness of U.S. factories and data centers,” the report said.

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NERC ‘Leaning into AI’ for Online Assistance

CALGARY, Alberta — NERC staff told a Board of Trustees committee that the ERO’s work on integrating artificial intelligence technology into its operations is “on track” and has produced promising developments.

Speaking to the board’s Technology and Security Committee on Aug. 13, Howard Gugel, NERC’s senior vice president for regulatory oversight, said the ERO Enterprise is “leaning into AI [by] learning, listening and supporting the industry” while engaging with developers on possible uses for the technology in the organization’s business.

Gugel and other speakers characterized the ERO’s approach to AI as “conservative,” acknowledging the need to keep industry data secure and deploy the technology responsibly. NERC and the regional entities have adopted the National Institute of Standards and Technology’s AI Risk Management Framework as a model. NIST’s framework is structured around four core functions:

    • Govern — implement a risk-management culture through policies, processes and accountability mechanisms;
    • Map — identify and document the context, intended uses and potential impacts of AI;
    • Measure — develop metrics for evaluating AI risks, and test and monitor performance regularly; and
    • Manage — prioritize and address identified risks through mitigation strategies, monitoring and improvement.

NIST provided a set of attributes that AI systems should exhibit to demonstrate trustworthiness. These include accuracy and robustness across diverse conditions, protection against failures and outside attacks, accountability and transparency, processes for safeguarding user data and privacy, and fairness.

“There [were] a number of reasons that the NIST AI risk framework was attractive,” said Joseph Younger, chief operating officer at the Texas Reliability Entity. “It’s non-industry-specific; it’s flexible; and it can be tailored to different-size organizations as well as organizations that are at different maturity levels in terms of how they’re implementing AI. … [It] also provides a range of supporting materials, including playbooks, models [and] templates that NERC and the regions could leverage as needed as we start out on these journeys.”

One of the first projects under the ERO’s AI initiative is a chatbot, developed with an outside partner, intended to help users quickly find information from NERC’s website. In the meeting agenda, NERC said such an application “could significantly reduce the time required to … find and apply the knowledge required to perform CMEP [compliance monitoring and enforcement program] tasks.”

The chatbot “can be used as a tool for either somebody that’s a new hire to NERC, or somebody that’s wanting to know more about standards, just to quickly ask a question and get it back,” Gugel said. NERC is developing the chatbot with AI Factory, a product of Microsoft partner company UnifyCloud. An internal pilot is expected to begin in the third quarter.

NERC also is exploring the use of OpenAI’s ChatGPT to help summarize comments submitted for draft reliability standards, which are in the public record and therefore considered a low security risk. In addition, ReliabilityFirst began a test of Microsoft Copilot in January to determine its suitability for the RE’s business. RF has “enabled Copilot for about 35 users, with plans to reach 50 by August 2025,” NERC said. RF has limited the use of Copilot to work teams that are not “primarily focused on core CMEP functions.”

Trustee Sue Kelly noted that in addition to these efforts, NERC’s Modernization of Standards Processes and Procedures Task Force — of which she is a member — is exploring the use of AI in the standards development process. She asked Gugel if such a use case would fall under the governance model.

Gugel assured Kelly that if such an application were created, the personnel involved would be appropriately trained and that the program would “have good guardrails in place [about] what … files can be accessed on the internet, and [which] ones can’t.”

“At this point, my vision would be [that] there’ll always be somebody reviewing that output for a sanity check before it ever goes out for either a public comment or be a document that’s actually used somewhere,” Gugel said.

E-ISAC Notes Growing Threat Sophistication

Matthew Duncan, vice president for security operations and intelligence at the Electricity Information Sharing and Analysis Center, delivered a presentation on the state of the security landscape at the TSC meeting.

Duncan said the environment remained largely “unchanged,” but the E-ISAC has seen “subtle shifts in the techniques and tradecraft being used by all manner of adversaries.” China-linked actors remain an ongoing threat, with an additional rise in malicious activity, including distributed denial of service attacks, from pro-Iran groups following the U.S.’ and Israel’s airstrikes on that country’s nuclear program earlier this year. (See Iran Strikes Likely to Raise Cyber Risk, CISA Warns.)

Between January and June, the E-ISAC made 1,982 direct shares to member and partner organizations, a 79% increase over the same period in 2024. Shares to utility members overall were up 43% year over year, and shares to Canadian members and partners up 13%. Duncan credited the increase to “the efficiency and the automation gains we have made at the E-ISAC.”

Asked by Trustee Jane Allen about reports that AI has fueled an increase in cyberattacks, Duncan acknowledged that “you don’t always know it is AI, or [generative] AI, that’s attacking you.” He said that one possible sign of AI assistance is that “the phishing emails … have all gotten better grammar and better spelling” and seem to be better tailored to their targets.

“The unfortunate truth is [generative] AI makes hacking easier, so even non-sophisticated folks can use these tools to do more effective phishing,” Duncan said. “So I think it behooves us to get ahead of this, to train our people to think about how to respond. If you have a question about whether an email or a text is authentic, find an alternative way to confirm that it is real.”

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Report Urges 5-GW Battery Storage Buildout in SPP

A new report urges SPP to accelerate its interconnection process and reform market rules to allow greater buildout of energy storage.

The report notes that hundreds of battery storage proposals are sitting in the SPP interconnection queue, working through lengthy reviews. Few batteries are deployed in SPP now, but even 5 GW of capacity could boost reliability and reduce costs by a projected $7 billion over the next decade.

Aurora Energy Research issued the report Aug. 12. The American Clean Power Association (ACP), which commissioned it, called for SPP and state policymakers to:

    • accelerate interconnection for the quick-to-deploy technology;
    • reform market rules to generate price signals that incentivize storage development and recognize the reliability contribution of storage;
    • remove ambiguity on when storage must register as a transmission customer and how the associated charges are applied; and
    • streamline and clarify state and local permitting with uniform rules and standards to ensure faster, more certain project execution.

SPP did not return requests for comment for this story.

The RTO recently completed a yearslong effort to streamline and integrate its transmission and generation planning: On Aug. 5, its board of directors approved the Consolidated Planning Process and asked FERC to approve a March 1, 2026, effective date. (See SPP Celebrates Novel Consolidated Planning Process.)

Several statistics provided by Aurora, the Energy Information Administration and SPP itself point to the potential importance of storage:

    • SPP is the second-largest RTO in the nation geographically.
    • It is expecting the largest peak load growth of any RTO, reaching 69 GW in 2035 due to electrification of oil and gas extraction and data center buildout.
    • Thirty-eight percent of its 2024 energy production was from wind turbines.
    • Wind turbines are highly variable sources of power generation — in the past 30 days, hourly output nationwide ranged from 10,352 to 77,765 MWh.
    • The SPP interconnection queue is crowded with proposals for solar generation, which also is intermittent if more predictable.
    • SPP’s 2025 accredited summer battery storage capacity is 172 MW.
    • More than 25 GW of battery capacity proposals entered the SPP interconnection queue in 2024.

Aurora modeled two distinct scenarios in its report: one where restrictions limit 2035 battery capacity to 1.4 GW and the other where 4.7 GW of batteries are deployed, based on economic viability and assuming continuation of various policy reforms such as federal clean energy tax credits and SPP’s Consolidated Planning Process.

In 2035, prices during late-afternoon/early evening summer peak demand periods could be $1,141/MWh under the 1.4-GW scenario, compared with just $153/MWh under the 4.7-GW scenario.

Total system costs could be $7 billion higher in 2035, and electricity prices would climb 10.1% from 2029 to 2035 under the 1.4-GW scenario.

Also over the next decade, the report forecasts growing net hourly load ramps due to expected increases in population and solar generation.

Small ramps will decline in number, the authors say, but large ramps will become more numerous: By 2030, more than 700 hours a year will require a ramp greater than 4 GW, compared with 37 hours in 2020.

A storage fleet larger than 5 GW is critical to grid reliability and cost savings, the report states.

It cites the performance of battery energy storage systems in ERCOT, where 15-minute battery discharges as high as 1.97 GW prevented load shed during several high-stress periods in the late summer of 2023.

“Evening power prices could be 80% lower in SPP if the region can build out the battery storage central states need to ensure reliability,” Noah Roberts, ACP vice president of energy storage, said in a news release. “As power demand surges, battery storage is one of the fastest and most effective ways to strengthen reliability and lower electricity bills. Grid batteries deliver significant cost savings for families and businesses, and provide the reliability needed to power our economy into the future.”

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N.J. Puts on Hold Remaining Pieces of $1.07B OSW Transmission Project

Bringing to a halt two major outstanding elements of New Jersey’s once-aggressive offshore wind plans, the state Board of Public Utilities postponed by 30 months all activities on onshore infrastructure intended to connect the wind farms to the grid. 

The three BPU board members voted unanimously to delay all possible expenditures on the $1.07B project, which was approved in October 2022 and would deliver 6,400 MW of offshore wind generation. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) Two seats on the five-member board are vacant after Commissioner Marian Abdou stepped down in July. 

The project, at its outset, was widely seen as groundbreaking because it was conceived under FERC Order 1000’s State Agreement Approach, which enabled the BPU and PJM to work together to shape the plan. The project included three points of interconnection on Jersey Central Power and Light’s transmission system and included a new substation adjacent to the company’s Larrabee substation. BPU officials said at the time the project would save $900 million over a baseline scenario in which the projects were not coordinated. 

Genevieve DiGiulio, project manager of offshore wind for the BPU, said that once the 30-month hold is over, there is a specific schedule for the projects to move forward. The BPU board at that time, however, will decide what happens next, she said.   

The three commissioners also voted unanimously Aug. 13 to accept a request by Atlantic Shores, the state’s only remaining active wind project, to terminate its Wind Renewable Energy Agreement with the BPU. The project developer in June said it would put the 1.5-GW project on hold because of opposition from the Trump administration. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)   

“Obviously some federal uncertainty has created a situation where we need to make sure that we’re acting in a way that we always do what’s in the best interest of ratepayers,” said BPU President Christine Guhl-Sadovy. “And so this, along with some of the other actions today, are in response to some of those federal decisions around clean energy.” 

The New Jersey League of Conservation Voters, saying the decision was a result of “President Trump’s clean energy ban,” called it a setback that nevertheless will “not stop our fight for a clean energy future in New Jersey.” 

“Offshore wind is critical to our clean energy portfolio and to protecting our health, environment and economy. Every delay forces our residents — especially low-income families and communities of color — to breathe dirty air and bear the brunt of climate change,” said Ed Potosnak, executive director of New Jersey LCV. “Solar and wind are the cheapest forms of energy, and New Jersey deserves clean, affordable, renewable energy, and we will not stop until we achieve it.” 

Solar Project Delays

The board also agreed to extend the development deadline for a series of solar projects in the Community Solar and Competitive Solar Incentive (CSI) programs that have been delayed by difficulties with the interconnection process with utilities. The CSI program is a part of the state’s Successor Solar Incentive (SuSI) program that sets incentive levels through a bid process for grid-scale projects. 

Sawyer Morgan, a project manager in the BPU’s clean energy division, said that out of 451 projects in the community solar pipeline and five others in the CSI pipeline, about 160 submitted a request to the BPU for an administrative extension to project completion deadlines. 

“The large number of projects entering the program simultaneously resulted in lengthy wait times for completion of facilities or engineering studies,” he said. “Stakeholders have reported concerns about the progress of interconnection with EDCs [electric distribution companies] and the opacity and unpredictability of the process.” 

Most of the delays were created by the slowness in developing engineering studies, Morgan said. 

The board agreed to extend the operation deadline for all projects in the two programs by nine months and allowed projects to request an additional six-month extension. The board also agreed to require developers to include a “completed facility study or equivalent feasibility or engineering study” to register a project. 

In a bid to move projects forward more quickly, the board also required EDCs to publish a monthly interconnection queue inventory with data including the locations of projects applying for interconnection progress through the process and other requirements. 

Commissioner Zenon Christodoulou suggested the BPU needs to orient developers to better handle delays. 

“When we talk about unexpected delays, I mean, we’ve known about interconnection issues for years and years and years,” he said. “So these still remain to be issues … but it’s still unexpected? I think the developers should understand and should expect this.”  

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Mass. Delays Next OSW Solicitation Due to Federal Uncertainty

The Massachusetts Department of Energy Resources (DOER) will delay its next offshore wind solicitation until “at least 2026” due to uncertainty around federal permitting, tax credits, tariffs and other investment risks that threaten to derail the state’s ambitions for offshore development. 

The fate of Massachusetts’ previous procurement, which selected 2,678 MW from three project bids, remains unclear. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.) The state repeatedly has pushed back the timeline for finalizing contracts for these projects, with negotiations now slated to wrap up by the end of 2025. New England Wind 2, one of the selected projects, already has backed out of the negotiations.  

“Massachusetts remains committed to an all-of-the-above approach to energy, including offshore wind,” said DOER spokesperson Lauren Diggin in a statement following the announcement. She added that the state plans to “develop a more flexible offshore wind procurement schedule so ratepayers can secure the best deals.” 

The state began preparations for its next offshore wind solicitation in late 2024 and requested public comments on the procurement in May 2025. The DOER noted in an Aug. 7 memo that “commenters overwhelmingly recommended” waiting until at least 2026 to issue the next request for proposals (RFP) because of the uncertainty around federal policy and the ongoing negotiations for the previous solicitation.  

The Trump administration has undertaken a multipronged assault on the U.S. offshore wind industry, halting leasing and permitting, rescinding designated wind energy areas, signing into law the expedited phase-out of federal tax credits, and recently launching an effort to overhaul all regulations related to wind generation. (See Dept. of Interior Launches Overhaul of OSW Regs.) 

Offshore wind companies have reported significant financing challenges stemming from the Trump administration’s actions; Ørsted recently said it has been unable to reach a financing deal for up to $9.33 billion needed to finish construction on its Sunrise Wind project. (See Ørsted to Raise $9.3B, Self-finance Sunrise Wind.)  

The company said potential investors were spooked by the Trump administration’s stop-work order on Equinor’s Empire Wind project. While Ørsted plans to raise money from existing shareholders to complete Sunrise Wind, the company and its investors remain in the dark as to whether the Trump administration will move to halt construction on Sunrise Wind or other in-progress projects.  

In comments submitted to Massachusetts for its next procurement, Ørsted urged state regulators to focus on reducing risks to developers associated with changing federal regulations and macroeconomic conditions. It advocated for increased flexibility around commercial operation dates, longer price indexation timelines, inflation and interest rate adjustment mechanisms, and “provisions around force majeure for events beyond developer and state-level control.” 

“These measures would help to counter complexities in the political and regulatory climate and macroeconomic conditions that have significant impacts on the long development timelines and high capital intensity unique to offshore wind projects,” Ørsted wrote. 

Ocean Winds, the developer of SouthCoast Wind, one of the projects selected in the previous solicitation, wrote that the state should “focus on reducing the uncontrollable risks that would otherwise be assumed by developers,” and said these risks will translate into higher power purchase agreement prices if not addressed in the RFP.  

The company also recommended that the state “wait for greater macroeconomic and political stability before releasing its next RFP,” and said uncertainty around interest rates, material and labor costs, and federal tax credits “[creates] significant financial risk and [undermines] confidence in long-term project viability, making it difficult for OW to proceed with a bid into the next Massachusetts auction.” 

Vineyard Offshore wrote it “strongly recommends that Massachusetts consider material modifications to its form PPA contracts to address significant federal permitting, tariff and tax credit policy risks.” 

The offshore wind developer also recommended “moving away from pre-published contracts to high-level term sheets that provide the necessary contractual information to inform bid price level but otherwise provide flexibility to negotiate durable contracts aligned with current market risks.” 

Offshore wind development risks are not limited to the actions of the Trump administration. SouthCoast Wind and Commonwealth Wind (now New England Wind) both backed out of contracts during the Biden administration, part of an industry-wide wave of cancellations caused by rising costs from inflation, high interest rates and supply chain constraints.  

‘Crucial’ for GHG Targets

The significant issues experienced in back-to-back offshore wind procurements underscores the significant challenges Massachusetts faces in scaling up the industry. 

The state is counting on offshore wind to be a key component of its decarbonization strategy, and in 2022 set a goal of procuring 5,600 MW of offshore wind by mid-2027. The state has only the 804-MW Vineyard Wind project under contract, which is slated to come online around the end of 2025. 

Meanwhile, ISO-NE has said repeatedly the reliability benefits of offshore wind resources, and continued long-term struggles of the offshore wind industry could create significant resource adequacy challenges for New England by the mid-2030s if power demand increases at the rate ISO-NE anticipates. 

The Conservation Law Foundation said the DOER should seek to procure enough power to meet the state’s 5,600-MW goal in the next RFP and that offshore wind development “is crucial for keeping Massachusetts on track to meet its binding greenhouse gas emissions reduction targets.” 

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WIRES Report Includes Survey on Industry’s Views of Advanced Tx Tech

WIRES Group has released a report looking into advanced transmission technologies (ATTs) and how they can help cost-effectively expand the transmission grid.

Prepared by London Economics International, the report includes a survey of 20 WIRES members, including transmission owners and technology providers, on their experiences with ATTs and best practices. It refers to “ATTs and innovative practices” collectively as “ATT+.”

“Transmission capacity will need to expand in order to support economic development and meet the rapid increase in electricity demand, while also maintaining system reliability and resiliency in the face of more frequent extreme weather events across the country,” the report said. “ATT+ can help TOs address various needs in certain situations and should be thought of as one of the tools in the toolbox to complement and supplement traditional transmission system capital investments.”

The definition of an ATT can vary depending on who is using the term and can include grid-enhancing technologies (GETs) and advanced conductors. But the paper considered a broad range of technologies that it put in three categories: siting and design, construction, and operations.

Siting and design ATTs include artificial intelligence-powered software that can speed up permitting; compact line designs that use less space for high-voltage transmission; and innovative approaches to expediting permitting processes.

For construction, the report looks into exoskeletons that add additional circuits above existing lines, helicrane construction that can install equipment in hard-to-reach areas, and modular tower raising systems that can lift up transmission towers without de-energizing lines.

The operations side of ATTs involves the most diverse range of technologies and is broken down into three subsections. Hardware components include advanced conductors, advanced flexible transformers and digital substations. GETs include dynamic line ratings, advanced power flow controllers and topology optimization.

Compact lines use new designs for towers that take up less space. The report cites a design used by American Electric Power from BOLD Transmission in Indiana in 2019. The towers were shorter and narrower, allowing for smaller easements, cutting costs and helping to minimize impacts on neighborhoods. It also allowed for more capacity than traditional designs.

Modular tower raising uses hydraulics that are mounted on the inside body of an existing transmission line, which can raise the tower to allow new framing to be installed without de-energization. Ampjack’s Tower Raising system has completed more than 750 tower raises, the report said.

Transmission asset inspections and maintenance typically are conducted by engineers climbing up pylons or using helicopters, but drones and robotics can do the same work for less money, especially in areas that are hard to reach. Using drones and robots for such work is safer, cuts down time and can enable more data collection on asset conditions.

The survey asked 13 TOs and seven technology providers about the benefits of ATTs. The top responses were improved system utilization and performance, expanded transmission capacity, improved reliability, improved resilience, and expanded interconnection of new load and generation. ATTs also can lower costs for customers by minimizing the need for capital investments and cutting operating costs, they said.

The survey asked what is holding companies back from deploying ATTs. The top answers were a lack of operational expertise, uncertainty about the technology’s capabilities and value proposition, and performance risks. Some firms listed the regulatory framework’s disincentives, but it was the lowest-ranked answer.

What WIRES Group members view as the main obstacles to rolling out ATTs | London Economics International

“Preference for technologies with low uncertainty (and therefore known benefits and costs) is not unique to the electric transmission sector,” the report said. It cited the diffusion of innovations theory by sociologist Everett Rogers, which was focused on the field of communications and posits that widespread adoption of new technologies occurs only as uncertainty decreases.

“LEI observed similar themes throughout interviews with technology providers and TOs,” the report said. “Regulators, system planners and TOs, by the nature of their priorities (where providing reliable electricity service at reasonable cost is paramount), tend to prefer technologies with proven track records over new technologies that are not yet commercially available or widely deployed under various real-world conditions due to uncertainty around performance under unexpected future operational conditions, and also potential ambiguity in future benefits and costs.”

The current regulatory structure in many regions tends to focus on nearer-term planning horizons of five to 10 years, which can lead to incomplete cost-benefit analyses for some ATTs that put more weight on near-term benefits. That is not helped by uncertainty around longer-term projections of benefits, which can make regulators overly cautious about using them, the report said.

Some opponents of transmission investments have argued that utilities are biased against ATTs because their earnings are lower than spending on wholly new infrastructure.

“It is inaccurate and overly simplified to claim that TOs do not benefit financially from ATTs that impact operating costs because of the cost-of-service environment,” the paper said. “In fact, regardless of whether a TO operates under stated rates or transmission formula rates, there is often some regulatory lag inherent in a cost-of-service environment, so TOs can reap some financial benefit from operating cost savings. Furthermore, the financial incentives and business factors that drive investment and operating decisions of TOs are much more complex because of the multiple objectives that TOs need to meet (reliability, policy and overall cost minimization) and constraints they face in their regulatory and business environments.”

Still, aligning financial incentives and implementing regulatory mechanisms that can level the playing field between operating versus capital investment-oriented ATTs, and between ATTs and traditional investments, would make cost impacts more transparent and encourage focusing more on the benefits side of the equation, the report said. That would lead to greater use of the technologies, it argued.

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Members Say MISO RA Better off Under Seasonal Capacity Auctions, Sloped Curve

MISO members largely agreed that MISO’s new capacity auction structure — featuring individual seasonal auctions and a sloped demand curve — is better for the health of the system.

MISO’s Advisory Committee said the 2025/26 Planning Resource Auction (PRA) results from April likely show that future auctions would spur more actions to sustain reliability. The Aug. 13 talk via teleconference was part of the committee’s “current issue” series.

Wisconsin Public Service Commissioner Marcus Hawkins said the auction is “paying dividends and supporting reliability in a major way.”

“I think we’re seeing those signals play out to retirement decisions,” Hawkins said.

MISO’s 2025/26 auction cleared at a record-breaking $666.50/MW-day for the summer season as members claimed 1.9% above the 7.9% summer planning reserve margin requirement. The padding in cleared reserves occurred even as MISO experienced a steady decline in spare capacity.

MISO’s 2025/26 surplus was 2.6 GW, a drop of 43% compared to the 4.6-GW surplus of summer 2024 and much lower than summer 2023’s 6.5-GW excess. More than 90% of load was secured before the voluntary auction. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)

The 2025/26 auction was the second to feature offers divided by seasons and the first to ditch MISO’s vertical demand curve, which foreclosed the option for additional capacity beyond the reserve margin to hold value.

John Wolfram, representing MISO transmission owners, said the narrowing summertime capacity stores evidenced by the auction should send good signals to members for “firm capacity resource development” and generation retirement delays.

Sharon Segner, senior vice president for competitive transmission developer LS Power, agreed that MISO’s system tightness today means that developers and stakeholders must ensure that “what is planned for the system gets online in time.”

But Sam Lukens, of the Illinois Office of the Attorney General, said the premium put on capacity is due largely to expected large loads from data centers and raises the question of whether consumers should bear the added costs.

Lukens said MISO should consider holding meetings to discuss whether consumers should be shielded from the costs of added demand on the system. He said the cost-causers should pay for the demand they introduce on the system.

“I still think the PRA is a short-term signal,” Lukens said. “There needs to be more discussion about how these large load forecasts are influencing consumers. In Illinois, consumers are really feeling the impact of the PRA.”

Attorney Jim Dauphinais, representing multiple industrial end-use customers, said the auction results and prices “properly” sent “a signal that capacity supplies are diminishing.” However, he said MISO’s preliminary public auction data communicated a significant shortfall, which thankfully didn’t pan out.

“We think the preliminary PRA data needs to be looked at more carefully,” Dauphinais suggested. He said more accurate data would give members better indication on how to prepare.