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December 8, 2025

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CEC Eyes Major Cuts to Light EV Charger Funding

The California Energy Commission projected significant funding cuts to a key electric vehicle charging program, despite the state setting a record for the number of EVs sold in a quarter.

CEC staff on Oct. 9 published a draft report of the investment plan for the CEC’s clean transportation program, in which forecast funding for EV charging infrastructure for light-duty vehicles dropped from $98.5 million in 2025/26 to $34.2 million in 2026/27. In 2027/28, the projected funding amount decreased slightly to $33.2 million.

But EV sales are going in the opposite direction: In Q3 of 2025, California sold about 125,000 EVs — the most recorded in a quarter in the state and about 29% of total vehicle sales in the quarter, Gov. Gavin Newsom (D) said in an Oct. 13 news release. The previous record occurred in Q3 2023 when about 27% of vehicles sales were EVs.

In February 2025, California had more than 178,500 public and shared-private Level 2 and DC fast-charging ports for light-duty vehicles.

The CEC told NetZero Insider that the decrease in light-duty EV charging funding is due to projected increased investment from the private sector, along with reduced future state budget allocations. If either of these scenarios changes, next year’s investment plan update could allocate funds differently, the CEC said.

As for medium- and heavy-duty charging infrastructure, CEC staff predicted an increase in funding from $15 million in 2025/26 to $44 million in 2026/27. About 5,800 medium- and heavy duty-vehicles were registered in the state at the end of 2024. Most of these vehicles were buses.

In total, California plans to have 1.5 million zero-emissions vehicles by 2025 and 5 million by 2030. As of June 2025, more than 61 percent of clean transportation program and supplemental funds have gone to projects in disadvantaged or low-income communities or both, the CEC said.

EV Data Collection Approved

Separately, at an Oct. 8 business meeting, the CEC approved new EV charging data-collection regulations, which require public EV charging port owners in California to submit data about charger usage semiannually. Required data includes a charger’s location, availability and pricing. The data may be shared with third parties.

California will become the first state to adopt EV charging reliability and reporting regulations, CEC Commissioner Nancy Skinner said at the Oct. 8 voting meeting.

“We are laying the foundation for EV charging station reliability across the nation,” Skinner said. “[EV charging] is so important for our consumers and so important to our meeting the goals of EV adoption, because if there is a sense of unreliability, then it’s going to be harder for people who haven’t yet gone to an EV to go there.”

Publicly available Level 2 chargers have a 96% reliability of working as designed, while DC fast chargers have a 91% reliability, Skinner said.

The data collection will give the CEC, for the first time, the ability to have a comprehensive inventory of the installed chargers in this state, Skinner said. The data includes all chargers not in a residence.

“Those of us who are EV drivers, we know that we commonly use different apps or websites to find a charger,” Skinner added. “Now, if the information is not widely shared, then that charger’s not going to show up, and we won’t know that it exists.”

The regulations, Skinner said, are “going to empower us to have that inventory and to get that more publicly accessible information. So, it’s just going to improve the overall EV driver experience in California.”

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VPPs Suffer Setbacks in Calif. Legislative Session

The 2025 California legislative session ended in disappointment for virtual power plant proponents, as Gov. Gavin Newsom vetoed several VPP-related bills and lawmakers didn’t approve new funding for an existing program.

Assembly Bill 740, AB 44 and Senate Bill 541 were vetoed before the governor’s Oct. 13 bill-signing deadline. Bills sent to Newsom that aren’t signed or vetoed become law without the governor’s signature.

Edson Perez, California lead at Advanced Energy United, called the vetoes of the VPP bills “missed opportunities to save billions in energy costs by leveraging technologies all around us in our homes, garages and on our roofs.”

“This policy whiplash undermines confidence across the sector, discourages the deployment of cost-saving technologies and drives away investments,” Perez said in a statement.

Virtual power plants are collections of distributed energy resources, such as solar panels, batteries, electric vehicles or smart devices, that can be called upon to boost the grid when needed.

AB 740 would have directed the California Energy Commission to work with CAISO and the California Public Utilities Commission to explore how virtual power plants could help meet statewide load shift goals and what opportunities are available for VPPs to qualify for resource adequacy. Perez said the bill aimed to make VPPs a core part of California’s energy portfolio rather than solely an emergency resource.

In vetoing the bill, Newsom cited budget constraints.

“While I support efforts to realize the potential of these energy resources and others, this bill results in costs to the CEC’s primary operating fund, which is currently facing an ongoing structural deficit, thereby exacerbating the fund’s structural imbalance,” Newsom said in his veto message.

Newsom also vetoed SB 541, which would have required the CEC to work with CAISO and the CPUC to analyze the cost effectiveness of certain load-shifting strategies, estimate each retail electricity supplier’s load-shifting potential, and report the amount of load shifting that each retail supplier achieved in the previous year.

Newsom called SB 541 “largely redundant and, in some cases, disruptive of existing and planned efforts” by the agencies to maximize the potential of load-management strategies.

AB 44, which the governor vetoed, would have directed the CEC to devise methodologies that load-serving entities could use to modify their demand forecasts in response to measures such as VPPs.

The governor said the bill does not align with the CPUC’s resource adequacy framework.

“As a result, the requirements of this bill would not improve electric grid reliability planning and could create uncertainty around energy resource planning and procurement processes,” Newsom said in his veto message.

Another disappointment for VPP advocates was lawmakers’ decision to not provide additional funding for the CEC’s demand side grid support (DSGS) program. As part of the program, battery owners agree to make their stored energy available to the grid during energy emergency alerts or when day-ahead prices go over $200/MWh. They then are compensated based on the power they shared with the grid. (See Budget Cuts Threaten Calif. VPP Program.)

In an Oct. 1 statement, the CEC said DSGS had about $64 million remaining. CEC expects to have enough money to pay out incentives from the 2025 program season and will look for ways to continue the program in 2026.

Advanced Energy United hopes the state will “course correct” on VPPs as soon as possible, Perez said, starting with more funding for DSGS in early 2026 to keep the program going.

Offshore Wind Funding

In contrast to the setbacks for VPP bills, lawmakers made progress on other energy-related issues.

As previously reported, the legislature passed and Newsom signed AB 825, known as the Pathways bill. The bill will allow CAISO to transition the governance of its markets to an independent “regional organization.” (See Newsom Signs Calif. Pathways Bill into Law.)

Newsom also signed SB 254, a law that will create a “transmission accelerator” to develop low-cost public financing programs for certain transmission projects. The legislation also establishes an $18 billion “continuation account” for the state’s wildfire fund to cover investor-owned utilities’ wildfire liabilities. (See Calif. Lawmakers Pass Bill to Accelerate Transmission Development.)

Offshore wind advocates were pleased that lawmakers passed and Newsom signed SB 105, a budget bill that includes $228.2 million for offshore wind. The funding is the first installment out of $475 million earmarked for offshore wind in Proposition 4, the $10 billion climate bond measure that California voters approved in 2024.

Of the $228.2 million in SB 105, the CEC has already distributed $42 million in grants to improve port facilities for floating offshore wind projects. (See CEC Approves 5 Offshore Wind Projects at California Ports.)

Offshore Wind California, an industry coalition, called the funding “another important proof point of California’s progress and commitment to move forward on offshore wind.”

“California is demonstrating its continued determination to be a clean energy leader, despite the federal headwinds we’re facing this year,” the group said in a statement.

Other legislation that Newsom signed includes a data center-related bill. SB 57 requires the CPUC to send a report to the legislature on the extent to which utility costs associated with new loads from data centers are shifted to other customers.

And SB 80, which Newsom signed, creates the Fusion Research and Development Innovation Initiative to distribute $5 million for fusion energy research and development. The goal is to deliver a fusion energy pilot project in the state by the 2040s.

Surplus Interconnection Bill Vetoed

Newsom vetoed other bills, including AB 1408, which would have required CAISO to consider surplus interconnection service in its long-term transmission planning. It also would have required utilities to evaluate and consider surplus interconnection options in their integrated resource plans. Proponents said unused interconnection capacity creates an opportunity to add renewable energy resources or battery storage at or near fossil plants.

In his veto message, Newsom pointed to the “highly technical structure of processes” used by the CEC, CPUC and CAISO for grid planning.

“This bill risks constraining energy resource procurement and interconnection options, likely increasing customer electric costs and undermining electric grid reliability,” he wrote.

A bill aimed at requiring more accountability from the CPUC didn’t even make it to Newsom’s desk. AB 13 also would have asked the governor and Senate to consider geographic diversity when selecting CPUC members to address a lack of Southern California representation. (See Calif. Lawmakers Seek More Accountability from CPUC.)

The bill died in committee.

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SPP Moving Forward with JTIQ Transmission Projects

LITTLE ROCK, Ark. — SPP says it plans to continue working the Joint Targeted Interconnection Queue’s portfolio of five 345-kV projects on its seam with MISO, despite the U.S. Department of Energy’s threat to pull $464 million in previously granted funds.

General Counsel Paul Suskie told stakeholders Oct. 14 that staff’s initial internal assessment has determined “nothing stops these projects from going forward.”

“They can proceed,” he said during a Markets and Operations Policy Committee meeting. “We are having communications with MISO to see if they’re in agreement with that. Staff’s current indication is these projects will still go forward if DOE funds are pulled for the grants.”

Suskie told MOPC that he called Minnesota Public Utilities Commissioner John Tuma, who confirmed that as of Oct. 13, DOE has not yet provided confirmation of the funding’s termination.

The funds were awarded in 2023 to the Minnesota Department of Commerce, the lead applicant in the JTIQ initiative that also involves the Great Plains Institute and the two RTOs. However, the department in early October included the $464 million grant under its Grid Resilience and Innovation Partnerships (GRIP) program on a list of projects that it intended to terminate. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

POLITICO has reported that DOE has “clashed” with the White House over the administration’s desire to spare most grants so they can be used as bargaining chips with Congress and the states, explaining the lack of confirmation from the department.

“At this point, we don’t know [the grant’s status],” Suskie said. “We know the rumors, the press reports. That’s all we know at this point in time. Really, it’s a wait-and-see game.”

MISO has said it is monitoring the situation and that like SPP and Minnesota, it has yet to receive word of the grant’s termination. (See MISO Says JTIQ Tx Portfolio Stands — for Now.)

The GRIP funds would offset about 25% of the predicted $1.6 billion in capital costs for the JTIQ portfolio’s five projects.

FERC approved the RTOs’ request to allocate the portfolio’s costs 100% to interconnecting generation assessed on a per-megawatt basis. In doing so, it cited the GRIP funding as one of the “unique set of facts and circumstances of the proposed JTIQ framework.” (See FERC Upholds MISO and SPP’s JTIQ Cost Allocation over Criticism.)

“This potentially has not just impacts on the practicality of these lines,” the Advanced Power Alliance’s Steve Gaw said during the MOPC discussion. “I’m not seeing anything that others don’t see, but there are also potential legal implications from this equity impact.”

The portfolio’s projects are centered on the RTOs’ northern seam and have been framed as enabling 28 GW of primarily renewable generation. Each grid operator would have two projects in its footprint and share the fifth.

The SPP projects will be evaluated for system impacts first through its one-time expedited resource adequacy study process and then through the 2024 Integrated Transmission Planning cluster. Staff have targeted March 2026 to execute ERAS generator interconnection agreements.

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NYISO Again Identifies Reliability Need for NYC

New York City could be short as much as 650 MW in capacity in the summer of 2026, according to NYISO’s Short Term Assessment of Reliability (STAR) for the third quarter, issued Oct. 13.

The report, which assesses reliability over five years, also identified reliability needs in Long Island and the Lower Hudson Valley, though not until 2027 and 2030, respectively, and both are much less than the city’s.

The findings trigger a formal process by which the ISO will seek solutions including transmission, generation, energy efficiency or a combination of each. “NYISO will begin the process immediately by working with the local utilities and the marketplace to identify and evaluate possible solutions,” it said in a press release.

The shortfall is primarily driven by the impending retirements of the Gowanus and Narrows gas generators in the city, kept online by an ISO designation for reliability under New York state’s peaker rule. NYISO continues to say that several projects — including the Champlain Hudson Power Express HVDC transmission line and the Empire Wind offshore wind facility — would solve the city’s deficiency. But “until these system plans are completed and demonstrate their planned power capabilities to address the identified reliability needs, the previously identified … deficiencies would persist without Gowanus and Narrows,” according to the STAR.

NYISO used its press release to note the findings of its biennial Comprehensive Reliability Plan (CRP), even though it is still being finalized. (See NYISO Reliability Plan Calls for ‘New Dispatchable Generation’.)

“Taken together, these two reports show the grid is at a significant inflection point,” said Zach Smith, senior vice president of system and resource planning for NYISO. “Depending on future demand growth and generator requirements, the system may need several thousand megawatts of new dispatchable generation within the next 10 years.”

Gavin Donohue, president of the Independent Power Producers of New York, said residents should be alarmed by the findings.

“Electricity demand is continuing to drastically rise, and the state needs to look at all possible resources to safeguard strict reliability standards that millions of New Yorkers depend on,” Donohue said in a statement.

The STAR considers planned retirements, upgrades, forecast peak power demand and changes to the generation mix. Thirty-six gas turbines submitted retirement notices, including the 672-MW Gowanus and Narrows generators.

When the planned transmission and generation projects enter service and assuming all existing generators remain available, reserve margins would improve substantially, but the STAR notes that they would “gradually erode as forecasted demand for electricity grows.” As soon as 2029, the city would be once again deficient in the summer, by 68 MW for five hours.

“Even with the Champlain Hudson Power Express transmission project online, reliability margins will be breached in the near future due to lack of resources with the same capabilities coming onto the system to replace the planned peaker retirements,” Donohue said. “Increasing dispatchable generation must be prioritized so the state does not go dark.”

The ISO may extend the operation of Gowanus and Narrows until May 2029 under the peaker rule. They cannot continue operating beyond that date unless they meet state Department of Environmental Conservation emissions requirements.

Long Island could become deficient in summer 2027 by 39 to 116 MW because of the deactivations of the Pinelawn and Far Rockaway generators. Once Sunrise Wind is delivering power, the margins would improve in summer 2028 and again once the Propel NY Energy transmission project comes online in 2030.

NYISO said the Lower Hudson Valley reliability need is an exacerbation of the city’s and that solving the latter would solve the former.

But “the risk of deficiencies beyond the needs identified in this STAR is even greater when considering a range of plausible futures with combined risks, such as the statistical likelihood of further generator retirements or failures,” the ISO warned. “New York’s generation fleet is among the oldest in the country, and as these generators age, they are experiencing more frequent and longer outages.”

NYISO’s pronouncements echo those of its Reliability Needs Assessment just over a year ago. The ISO narrowly avoided issuing a formal reliability need then, but it made similar warnings of generator aging and retirements, and it also warned that the city’s reliability would depend on the Champlain Hudson project. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.)

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IESO Removes Credit Requirement for Transmission Registry

IESO has removed a credit rating requirement for prospective bidders to enroll in its Transmitter Selection Framework Registry (TSF-R), a prequalification mechanism for the ISO’s competitive procurement that is expected to begin in 2026.

Removing the requirement will ensure that all applicants are “assessed using consistent financial criteria,” IESO officials said in an engagement session Oct. 15.

“This allows us to evaluate organizations consistently through these early phases, but it’s expected that credit rating requirements will be expected and introduced as a requirement at the time of” the request for proposals, said Denise Zhong, IESO senior manager for resource adequacy and sector evolution.

IESO officials said the change was made in response to feedback after its stakeholder engagement in June. (See IESO Moving Forward with Competitive Tx Plans.) The TSF-R opened July 31.

“Concerns were raised around the current credit rating criteria within the TSF Registry that [they] may be too restrictive at this stage of the process, and it seemed that it was required for some but not all,” Zhong said.

Throughout their presentations, Zhong and her colleagues emphasized the importance of Indigenous participation and support for projects. They said since the June engagement, the ISO has continued talks with Building Ontario Fund (BOF) and Canada Infrastructure Bank (CIB) to develop ways to encourage Indigenous participation and provide loans to developers of TSF projects.

The BOF is administering the Indigenous Opportunities Financing Program (IOFP) — formerly the Aboriginal Loan Guarantee Program — which provides credit support to help Indigenous corporations attract lenders.

“The IOFP is not a loan or a grant program,” said Andrew Lee, IESO senior adviser for resource acquisition. “The IOFP is a form of credit support intended to enhance Indigenous corporations’ credit worthiness and attract lenders willing to provide a loan.”

Three loan guarantees totaling $327 million have been provided by the fund through September, Lee said, including most recently one for the Chatham-Lakeshore transmission line, a 49-km, double-circuit 230-kV line in southwestern Ontario.

IESO says initiating competition — a directive from the Minister of Energy and Mines’ Integrated Energy Plan (IEP) — will lower costs and produce innovation. The ISO is working with the ministry to identify the first transmission project to be opened to competition, with a focus on the South and Central Bulk Study, with recommendations scheduled for late 2025, and the North of Sudbury and Eastern Ontario bulk studies, both expected in early 2026.

But most of the 1,500 km of new transmission lines planned or under development will be awarded to incumbent transmitters.

‘Partial Contracting’ Model

The ISO announced in June that it had decided on a “COD+10” partial contracting model, in which the winning bidder will receive a contract covering all costs of financing, designing, building, operating and maintaining the line for the first 10 years of commercial operation.

Bidders will be asked to submit 10 annual revenue requirements (ARRs) for the initial 10 years of operation. In year 11, the contract will transition to traditional rate regulation under the Ontario Energy Board (OEB), which will review the prudency of ARRs going forward.

The model will include binding commitments for cost management, scheduling and Indigenous participation, officials said.

IESO also has been consulting with the OEB to develop the regulatory framework for the program, including exempting TSF-contracted transmission projects from “leave-to-construct” requirements.

IESO’s timeline for its TSF procurement | IESO

“One of the key recommendations coming out of the TSF is to remove the leave-to-construct requirement during project development phase for TSF projects,” Zhong said. “This change is intended to reduce timelines in the development phase, recognizing that, again, a procurement process overall will require additional time and careful execution.”

The ISO also has been meeting with transmitters, financiers, and engineering, procurement and construction firms to inform the design of the program.

Routing, Cost Containment

IESO said it will specify terminal connection points for projects but will not prescribe routes.

“In some cases, a corridor may have been identified and/or protected by the Ministry of Energy and Mines,” the ISO said. “Such a corridor will not preclude other route alignments as determined through field studies and/or community engagement.”

IESO said it is considering cost-containment provisions and ways to manage cost adjustments to balance “cost certainty and flexibility for legitimate changes.”

It asked stakeholders for feedback on whether it should set cost caps or allow developers to propose them.

To protect ratepayers, IESO said it will monitor developers’ performance and may reduce their payments if they fail to meet contractual benchmarks regarding availability (based on outages) and transfer capability.

“Unlike the rate regulated cost of service model where reasonable operational and maintenance costs are reimbursed to the transmitter, the IESO foresees a potential risk of underinvestment in maintenance and operation from transmitters as an approach to improving transmitter profit margins,” it said.

Feedback

Sonny McGinnis complained about difficulty communicating with the ISO. McGinnis, who was representing the Anishnaabeg of Naongashiing in northwestern Ontario, said he “tried calling after our sessions months ago. I could never line up with anyone. Nobody knew what the heck I was talking about. … It can’t be just lip service we’re getting.”

Stakeholders should provide written feedback on the TSF plan to engagement@ieso.ca by Nov. 5. IESO plans to share solicitation documents and contract term sheets in an engagement session in January.

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Sharper Load Growth in Utility Integrated Resource Plans

U.S. utilities continue to ratchet up load growth forecasts in their integrated resource plans.

As of September 2025, the IRPs are projecting demand will be 24% higher in 2035 than in 2023, RMI reported Oct. 15. This compares with 12% in December 2023 and 6% in January 2021.

The third-quarter “State of Utility Planning” report is the latest in a series by RMI and combines data from 130 IRPs. As RMI notes in its preface, IRPs are not a clear picture of the future, but they do provide a snapshot of trends, goals and strategies to meet those goals.

The third-quarter report is the first that reflects the impact of the One Big Beautiful Bill Act, with its phaseout of tax credits for wind and solar generation, which recently have been the largest source of new U.S. generation by nameplate capacity.

Other factors gaining prominence in the third quarter included delayed fossil retirements, uncertainty in planning, inability to bring new resources online quickly and difficulties in buying electricity from neighboring utilities.

Trends continuing from previous quarterly reports include changes in resource adequacy rules, particularly in MISO, as well as the expectation that new large loads will present demands that cannot easily be met.

These factors are set against a background of considerable uncertainty over factors such as resource costs, market rules, EPA regulations, other federal policies, frequency of extreme weather events, state policies and the load-growth forecasts themselves. The forecasts are demonstrably imprecise, and some observers maintain that top-end projections are unrealistically large.

Every IRP reviewed for RMI’s third-quarter report increased the load forecast over previous projections but also showed a wide range of uncertainty about the size of that increase. Both the quantity and hourly profiles of these new loads differ from historical trends.

The difficulty of resource planning amid all this is a common point of discussion for utilities, RMI said, along with the need to devise new ways to meet future needs.

RMI noted that since it began tracking IRPs, load projections have increased in all nine quarters and cumulative emissions projections have increased for seven consecutive quarters.

It also pointed out that emissions reductions are lagging in utility projections: The companies examined have targets of 63% emissions reductions by 2035 from a 2005 baseline, but their IRPs would lead to only a 53% reduction.

The IRPs include 259 GW of wind and solar additions through 2035, 103 GW of natural gas additions and 74 GW of coal retirements. This is 2.4% more wind and solar than was planned as of the end of 2023 but 106% more natural gas.

RMI acknowledged the challenges facing electric utilities as they try to balance regulations, costs for customers, profits for investors and climate impact.

But the clean energy advocacy nonprofit also said delayed fossil retirements and new gas generation are the default choice in most IRPs, which instead should incorporate alternatives such as energy efficiency, virtual power plants, grid enhancing technologies and clean repowering.

These alternatives — along with policy and regulatory support — would help utilities hold down costs as they transition to a zero-carbon future, RMI concludes.

The report combines historical data from RMI’s Utility Transition Hub with IRP data manually collected by EQ Research. The 130 IRPs reviewed would cover approximately 48% of U.S. electricity deliveries.

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LBNL Study Examines Drivers Behind Higher Power Prices in Some States

The Lawrence Berkeley National Laboratory released a paper recently examining why some states have seen retail power prices rise faster than inflation. The listed reasons include distribution investments, extreme weather and wildfire, natural gas prices and state renewable targets.

“Factors influencing recent trends in retail electricity prices in the United States” includes an article in The Electricity Journal. It found that states in the Northeast and on the West Coast saw some of the biggest price increases from 2019 to 2024 but noted the national averages were in line with inflation.

In nominal terms, prices rose 23% between 2019 and 2024. Controlling for inflation, they were flat outside of a bump in 2022 related to the Ukraine-Russia war’s effect on natural gas prices. The national average masks a big difference in state average prices that range from 8 cents/kWh in North Dakota to more than 27 cents/kWh in California.

“Examining recent trends in inflation-adjusted prices, 31 states saw real price declines from 2019 to 2024, while 17 states experienced increases,” the article said. “States on the West Coast and in the Northeast were most affected by rising prices — especially California, where average retail prices increased by 6.2 cents/kWh in real 2024 dollars.”

States with the greatest price decreases typically exhibited increasing customer loads over that period, which misses the recent run-up in PJM capacity prices in the 2025/2026 auctions that are affecting customer bills now, according to a presentation accompanying the study.

PJM’s Independent Market Monitor found that new data center load contributed to the largest chunk of the capacity price increase (alongside some market design parameters), and most PJM states saw retail prices jump from 10 to 15% when the new delivery year started.

Rising demand from data centers, manufacturing and other sources has been cited as creating a risk of higher prices due to their purported impact on wholesale markets, higher retail prices or cost allocation policies that might favor large commercial and industrial customers in the name of economic development. But the study found that load growth from 2019 to 2024 tended to reduce retail prices.

“In the 2019-2024 time frame, the regression suggests that a 10% increase in load was associated with a 0.6 (±0.1) cent/kWh reduction in prices, on average,” the article said.

That aligns with the understanding that a primary driver for utility spending has been refurbishing existing transmission and distribution infrastructure in recent years. Spreading those costs over a larger base cuts average prices, but the study noted that negative load-price relationship was seen in average prices and lost when focused on residential prices.

“Load growth over this historical period was led by commercial customers, and cost allocation practices have tended to benefit those large, non-residential customers,” the article said.

The study focuses on average prices across customer classes, but it noted that residential prices generally are higher than commercial and industrial prices and have risen more than those classes in recent years.

Investor-owned utilities have seen prices rise faster than public power, but the article noted that in California it is largely due to differences in wildfire risk and related costs.

“States with the greatest price increases typically exhibited shrinking customer loads — partially linked to growth in net metered behind-the-meter solar — and had renewables portfolio standards (RPS) in concert with relatively costly incremental renewable energy supplies,” the article said.

Net energy metering offers participants bill savings, but utilities must invest more in their distribution systems and recover fewer fixed costs from customers on NEM programs. The study found a 5% increase in net-metered, behind-the-meter solar led to an average price increase of 1.1 cents/kWh.

Utility-scale wind and solar development that happened outside of RPS might have led to lower retail prices in recent years, though the impact was not statistically significant, the article said. It added that RPS targets are likely to increase prices if they lead to renewables the market would not have delivered. Three-quarters of utility-scale wind and solar growth from 2019 to 2024 happened outside of RPS mandates.

Another major driver of higher prices is extreme weather, which impacts two of the states that have seen prices rise the most in recent years – Maine and California. Central Maine Power’s storm recovery cost rider rose from 0.1 cents/kWh in late 2020 to 1.8 cents/kWh in 2024.

“Between 2019 and 2023, California’s three large IOUs were authorized to include $27 billion in wildfire-related costs in retail prices,” the article said. “By June 2024, wildfire-related costs constituted an average of 17 % of total IOU revenue requirements, up from 1.7 % in 2019 and, if directly translated into one-year cost impacts, equivalent to a 4 cent/kWh increase.”

On average, the states with the highest wildfire risks have seen power prices rise by 1.1 cents/kWh, the article said.

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New Report Outlines a Road map for Interregional Tx in the Northeast

A new report outlines a high-level road map for cross-border interregional transmission planning in the Northeast, making the case for more coordinated planning processes across sub-regions and regulatory environments.

The analysis, authored by the energy consulting firm Power Advisory, was commissioned by the Northeast Grid Planning Forum. The forum is an initiative of Nergica, a Quebec-based clean energy research organization, and the Acadia Center. (See New Initiative Focuses on Interregional Tx Coordination in the Northeast.)

“Provinces and states could benefit through enhanced coordination and transmission project development that optimizes utilization of existing resources and enables development of new clean energy sources,” Power Advisory wrote.

While studies have shown significant potential for increased interregional transmission throughout the Northeast, “fragmented planning processes and challenges presented by differences in regulatory structures” have limited states and provinces’ ability to fully realize these benefits, the authors wrote.

They emphasized the need to build trust, increase information access and establish mechanisms to facilitate transmission partnerships across regions and borders.

“A collaborative planning framework will require new approaches to sharing information and will require harmonizing planning processes to meet the requirements and planning horizons of each jurisdiction,” Power Advisory wrote. “Transparency and engagement will provide confidence in identified needs among jurisdictions and stakeholders.”

The report highlights several recent larger-scale transmission planning efforts as evidence of growing interest in interregional planning.

In June, the Northeast States Collaborative on Interregional Transmission, which includes nine states, issued a request for information (RFI) to identify “potential interregional transmission opportunities … that improve grid reliability, support economic growth and reduce costs for consumers.”

The states asked for input on potential cost allocation methods and wrote that responses to the RFI will “inform potential future solicitations or transmission planning activities.”

International cooperation around transmission planning also has increased. In 2024, the New England Governors and Eastern Canadian Premiers agreed to reconvene the Northeast International Committee on Energy, directing the committee to establish working groups “to pursue regional collaboration and planning on the topics of transmission, offshore wind supply chain and hard-to-decarbonize sectors.”

In Atlantic Canada, top politicians are eying a massive buildout of offshore wind generation, which would require large-scale interregional transmission developments to move the power to load centers in Canada and New England.

According to a strategic plan published by Nova Scotia, researchers have identified offshore wind sites that could host 62 GW of generation. Nova Scotia has proposed a 5,000-MW first phase of development, requiring an estimated $40 billion in capital investment to build the generation and $20 billion to build the associated transmission.

These recent efforts “indicate recognition by the key jurisdictions that current transmission planning approaches are constrained and insufficient and need to change to realize the benefits of broader regional energy system integration,” Power Advisory wrote.

To select projects, existing regional competitive transmission solicitation processes could be aligned to allow for interregional projects, or new processes could be stood up, the authors wrote.

“The recently established ISO-NE Longer-Term Transmission Planning (LTTP) process provides an instructive model for need identification across a multi-jurisdiction region,” they said.

ISO-NE is evaluating project submissions for the first iteration of its LTTP process, which is focused on increasing transmission capacity in Maine and enabling the interconnection of onshore wind generation. (See ISO-NE Reveals 1st Details of Long-term Transmission Proposals.)

States and provinces also would need to establish cost sharing processes and could take inspiration from Europe’s cross-border cost allocation methodology, the authors wrote.

Cost allocation “should ensure full consideration of all benefits evaluated in each participating jurisdiction,” including “reduced production costs, avoided capacity costs, avoidance of alternative transmission investments, improved transmission system efficiency, reliability and other benefits,” the authors added.

To address the challenges of determining needs, selecting projects and allocating costs across regulatory authorities, states and provinces should establish “a joint coordination agreement” that “formalizes collaboration and provides a clear mandate for agency staff regarding the scope of future work,” Power Advisory concluded.

This could mirror the memorandum of understanding underpinning the Northeast States Collaborative and could lay the groundwork for answering more technical questions related to modeling, information sharing and aligning existing processes, they wrote.

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MISO Tries to Clear Up Assortment of New DR Rules

Can’t keep all of MISO’s new demand response rules straight? You’re not alone.

The grid operator convened a stakeholder workshop Oct. 14 to go over new requirements for demand response resources heading into the 2026/27 planning year.

After multiple instances of fraud and misrepresentation from DR in MISO’s capacity market, the RTO has spent months developing stricter rules to deter abuse.

The RTO has made:

    • A March 2025 filing seeking to discourage nonexistent or overstated curtailments by requiring proof of contracts and hourly meter data while instituting reference levels for DR resources so they cannot inflate baselines. FERC accepted the stricter rules in July (ER25-1729).
    • An April 2025 filing to put an end to MISO allowing load-modifying resources to also identify as emergency demand response and collect extraneous capacity payments. FERC also accepted the changes in July (ER25-2050).
    • An April 2025 filing to divide load-modifying resources into fast and slow categories for capacity accreditation, with the faster resources receiving higher accreditation values. The pending filing wouldn’t take effect until the 2028/29 planning year (ER25-1886). (See MISO Approaching LMR/DR Accreditation Based on Availability.) FERC in September decided it needed more information on the proposal’s inner workings and issued a deficiency letter.
    • A July filing to mandate its demand response to make real-world demand reductions for tests instead of submitting mock tests to prove capability. (See MISO Tries to Ward Off DR Fraud with New Testing Regime.) FERC hasn’t yet decided whether to accept MISO’s proposal and issued an August deficiency letter to glean more information. The new testing rules would apply retroactively for any tests after July 15, 2025, if MISO’s proposal wins approval (ER25-2845).

MISO plans to file at FERC for permission to more consistently dole out monetary penalties when a DR resource delivers less than promised, effective June 1, 2026. It also plans to bar energy efficiency from participating in its capacity auctions. (See MISO to Axe Energy Efficiency from Capacity Market.)

MISO senior market design economist Joshua Schabla reviewed new rules stemming from the filings that pertain to DR contracts, broader penalties, testing and providing MISO with documentation. MISO included the end of mock testing and stepped-up monetary penalties in its roundup, though those rules don’t have FERC approval yet.

Docs and Data

Before summer 2026, MISO will insist on more descriptive documentation for DR that details the operating procedures used to curtail load, how the market participant communicates with the facility making the cuts, the expected time to draw down the load and confirmation that the load can be held at a minimum amount for four consecutive hours.

“What we need to see is that the persons physically responsible for curtailing the load understand what they need to do and how they will do it; it does not need to provide confidential information but should be specific enough that a reasonable third party feels confident the facility knows what they’re doing,” Schabla said of the required documents.

MISO also will require written verification from facility owners that real power tests reflect what they expect to curtail if called upon by MISO.

Schabla pointed out that DR resources voluntarily participate in MISO’s capacity market and receive compensation to do so.

“With that, there comes a certain level of expectation of the documentation they submit,” Schabla said. He also said MISO wants to have confidence that DR resources are real, that ratepayers are paying for actual capacity and that members aren’t making decisions to retire generation or forgo adding generation because of fake DR megawatt reductions.

“We feel like we’re asking for some very fundamental and basic information,” Schabla said. He added that MISO wouldn’t outright reject registrations if information is lacking; rather, it would reach out for more data.

MISO also wants every non-residential resource that’s registered to submit a physical address of the load’s location.

“What we’re trying to accomplish here is to figure out where these LMRs are located,” Schabla said, adding that the addresses are a starting point.

Beginning in the 2027/28 planning year, MISO said it would further require market participants to submit the elemental pricing nodes for DR resources that are at least 5 MW.

Schabla said MISO hopes to gain more visibility into LMR and eventually be able order more targeted curtailments in instances like local transmission emergencies. He said the extra year should provide “plenty of runway” for market participants to start assembling more exact location data.

Moving into the 2026/27 auction, MISO will require market participants with DR to submit hourly metered output from every resource in the seasons they’re signing up to contribute. The RTO said it would allow single aggregated values from residential DR programs.

Enel X’s Allison Miller said time is running out to make registrations for the 2026/27 auction, but MISO has yet to finalize all the new rules and provide all registration templates. She also said there’s still a “back and forth” at FERC on MISO’s real power testing proposal, which was issued a deficiency letter.

Other stakeholders asked if MISO would hold another workshop to get stakeholders better acquainted with the new rules. Schabla said MISO would not. Schabla said MISO isn’t attempting to shut DR out of its markets but needs to discourage bad actors.

“We just want to make sure what we’re paying for is quality,” Schabla said.

At an Oct. 1 Resource Adequacy Subcommittee, MISO’s Neil Shah said MISO understands it’s putting market participants through tremendous change with its new demand response rules.

LMR Replacement Becomes an Option

There may be a silver lining in the 2026/27 auction: MISO will permit market participants to replace their load-modifying resources if the original resources become unavailable. MISO will allow demand response to replace (and avoid penalties for nonperformance) when a contract previously approved by state regulators is terminated or if there’s a change in ownership of the facility contracted to dial back load.

For behind-the-meter generation, MISO will allow replacements in the event of outages that are communicated to MISO at least two weeks in advance or if regulatory restrictions crop up, such as environmental run-time limits. MISO also said load-modifying resources can replace on a case-by-case basis with approval from MISO’s Independent Market Monitor.

The grid operator said it plans to hold DR resources to more rigid nonperformance penalties and make a FERC filing soon. MISO plans to assess penalties when DR resources are coming up short on what they said they could provide or when a resource is marked as unavailable but is consuming demand during an emergency. Penalties would be based on auction revenue and include a charge based on locational marginal prices at the time.

MISO will divide penalties into either partial failures (when a DR resource has provided at least 25% of its required response) or complete failures (when the resource has supplied less than 25%). MISO said repeat complete failures would lead to disqualification as a capacity resource.

However, MISO said it will offer penalty exemptions for when behind-the-meter generation must perform maintenance. For that, the market participant would have to pre-schedule a no more than 31-day outage in either a spring or fall period (March 1 to May 15, and Sept. 15 to Nov. 30, respectively).

Schabla said MISO realizes it’s unrealistic for 30 to 40% of its behind-the-meter fleet to seemingly never need annual outages, as is the case now.

Finally, MISO stressed the importance of market participants updating their availability in its nonpublic Demand Side Resource Interface. Schabla said offers made in the 2027/28 planning will begin to affect DR accreditation in the 2028/29 planning year. Beyond that, MISO didn’t touch on the new accreditation, reasoning that it was too early to address it.

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Interior Throws Curveball at Esmeralda Solar Projects, but Denies Cancellation

The fate of a 6.2-GW cluster of solar energy projects in western Nevada is uncertain following the Bureau of Land Management’s decision to break the group into individual projects for review.

On its National NEPA Register, BLM changed the status of the Esmeralda 7 to “canceled” Oct. 9. The group consists of seven proposed solar projects ranging from 500 MW to 1.5 GW, each with battery storage, on federal land in Esmeralda County.

But the Department of the Interior clarified in an email that “BLM did not cancel the project.” Instead, “the proponents and BLM agreed to change their approach” to project review, the department said.

“The projects were initially submitted as a group,” Interior said. “The developers will now pursue individual applications for their respective projects. This approach ensures focused, thorough assessments of potential impacts on public lands while supporting responsible energy development.”

Interior said the new approach “aligns with the administration’s emphasis on improving permitting efficiency and reducing regulatory burdens.”

It wasn’t clear how the change in the BLM review process might impact project timelines, or whether all the proposed projects will proceed. If completed, several of the individual Esmeralda solar projects would be among the largest in the U.S.

In July 2024, BLM released a draft programmatic environmental impact statement and resource management plan amendment for Esmeralda 7. A 90-day public comment period followed. The completed work will still be useful as individual projects move forward, Interior said.

And at least one project developer plans to forge ahead.

NextEra Energy Resources is developing the Esmeralda Energy Center, described in a November 2023 project overview as 1 GW of solar with battery storage.

“We are in the early stages of development and remain committed to pursuing our project’s comprehensive environmental analysis,” a NextEra Energy spokesperson said in an email. “[We] will continue to engage constructively with the Bureau of Land Management.”

Another project is Lone Mountain Solar, 1 GW of solar and 500 MW of battery storage being developed by Leeward Renewable Energy. A timeline on Leeward’s website shows a 2027 construction start date with projected completion in 2029. A Leeward spokesperson said the company did not have any information to share regarding the impact of changes to the BLM review process.

The other projects are:

    • Gold Dust Solar, 1.5 GW of solar and 1 GW of storage developed by Arevia Power;
    • Nivloc Solar, 500 MW of solar with battery storage by Invenergy;
    • Smoky Valley Solar, 1 GW of solar with battery storage by ConnectGen; and
    • Red Ridge 1 and 2, each 600 MW of solar with battery storage by 335ES 8me.

Developers had planned to interconnect their projects through Greenlink West, NV Energy’s 350-mile, 525-kV transmission line under construction across the west side of the state.

Each solar project would include a tie line connecting to Greenlink West’s Esmeralda substation.

One goal of Greenlink West and Greenlink North, a transmission line planned across northern Nevada, is to open more of the state to renewable resource development. When completed, the two Greenlink lines along with the existing One Nevada Line will form a transmission triangle around the state.

Energy development within transmission corridors such as Greenlink West is expected to drive additional local and regional renewable energy development, BLM said in its draft environmental report.