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December 12, 2025

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Ontario Govt. Moves to Tighten Grip on OEB, IESO

Ontario’s Progressive Conservative government continues to put its stamp on the province’s energy policy, proposing legislation that would add “economic growth” to the missions of IESO and the Ontario Energy Board (OEB).

The Ministry of Energy and Mines posted the legislation Sept. 4, a day before the provincial government announced Geoff Owen as the OEB’s new chair. Owen, who has served on the board since 2021, was appointed chair at the recommendation of Minister Stephen Lecce.

The ministry’s proposed legislation is intended to support the province’s first Integrated Energy Plan, which seeks to ensure sufficient capacity for a forecast 75% increase in electric demand over the next 25 years. (See Ontario Energy Plan Gives IESO Long ‘To Do’ List.)

The bill would amend the Ontario Energy Board Act of 1998 and the Electricity Act of 1998 to update the missions of the OEB and IESO, making economic growth a “core consideration” in electric rulings and system planning. “The proposed amendments are targeted towards enhancing electricity transmission and distribution planning processes to account for the expediency of the electricity grid buildout to drive innovation and economic growth, and to strengthen self-reliance and energy security,” the ministry said.

In addition, the legislation would:

    • give the lieutenant governor authority to set connection requirements for data centers, which IESO projects will account for about 13% of new electricity demand by 2035.
    • allow rate-regulated entities to establish accounts to track increased costs that could result from territory-of-origin restrictions on energy procurements. The OEB would review for prudency and rate recovery.
    • expand the purposes of the Electricity Act to allow IESO to undertake clean hydrogen pilot projects with non-electricity applications such as transportation and industrial use.
    • amend the Ontario Energy Board Act to enable the OEB CEO to issue “scoped policies” such as timelines for adjudicative proceedings and the information to be considered, such as relevant government policy statements. “This authority would not bind commissioners to make determinations in alignment with government direction/policy,” the ministry said.
    • amend the Municipal Franchises Act to eliminate requirements that a municipality’s voters approve new natural gas municipal franchises. “The process to obtain municipal electors’ assent can be administratively burdensome and costly for some municipalities,” the ministry said. “Franchise applications often include a request to waive this requirement, and the OEB has granted that request in the vast majority of cases.”
    • implement the Future Clean Electricity Fund, which would make payments to non-emitting hydro and nuclear electric resources and transmission projects. The FCEF will be funded by the Emission Performance Standards program, which is designed to reduce greenhouse gas emissions from large industrial facilities by “setting standards, rewarding innovation and taking into consideration specific industry/facility conditions while allowing for economic growth,” the ministry said.

Blowback over Gas Ruling

The Progressive Conservative Party, led by Premier Doug Ford, has controlled Ontario since 2018, when it ended 15 years of Liberal Party rule.

After canceling hundreds of what it said were above-market renewable energy contracts, the Ford administration has committed to expanding renewables in the province. But it also is backing an expansion of nuclear power and continued use of natural gas. In support of its Integrated Energy Plan, the Ministry of Energy and Mines issued a prescriptive 12-page directive spelling out in detail how IESO is to carry out its policy, with sections on planning, district energy systems, distributed energy resources, transmission, low-carbon hydrogen strategy, hydro and nuclear generation, and export opportunities. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)

The OEB has attracted increasing attention from the government since the board’s December 2023 decision rejecting a rate proposal by Enbridge Gas. OEB said it would require Enbridge or developers to pay 100% of the cost of new natural gas connections in advance. The board said the previous policy, which spread the costs to consumers over 40 years, would result in stranded assets as the province moves to meet Canada’s 2050 target for net-zero greenhouse gas emissions.

In February 2024, then-Energy Minister Todd Smith announced legislation to reverse the OEB ruling and said he would appoint a new OEB chair.

“Natural gas will continue to be an important part of Ontario’s energy mix as we implement our pragmatic plan to invest in and bring online more clean nuclear energy,” Smith said. “Unlike the previous government, which saddled families with sky-high hydro bills, our government is taking a thoughtful approach that keeps costs down for people and businesses and delivers energy security.”

In addition to reversing the OEB decision, the Keeping Energy Costs Down Act, which was approved in May 2024, authorizes the minister to issue directives requiring the OEB to hold a generic hearing to determine any matter respecting natural gas or electricity.

The ministry said OEB’s decision could add tens of thousands of dollars to the cost of new homes.

But an analysis by Western University’s Ivey Business School concluded that “the government’s decision to override the OEB should have virtually no effect on affordable housing in the province. Based on our admittedly rough estimates, their policy might reduce the annual cost of buying a home by $92.74 or it could possibly increase it $32.90. Hardly seems worth damaging regulatory independence for.”

In a December 2024 report, Ontario’s auditor general challenged the ministry’s claim that the new law would have no impact on the environment. “The ministry did not explain that the proposed changes had the potential to increase greenhouse gas emissions by encouraging the continued construction of new natural gas infrastructure and continuing Ontario’s reliance on fossil fuels instead of shifting to electricity,” it said.

OEB Chair

Geoff Owen, chairman of the Ontario Energy Board | Foresight Strategic Advisors

Owen, a principal at Foresight Strategic Advisors, joined the board in 2021, becoming vice chair in 2024 and acting chair in April. He previously held executive positions at the Royal Bank of Canada in regulatory affairs, business strategy and public affairs. He also served in the offices of the Premier of Ontario, Minister of Finance, Minister of Economic Development and Minister of Municipal Affairs and Housing.

“Mr. Owen assumes his role at a pivotal time, as the Ontario Energy Board begins to deliver on the Minister of Energy and Mines’ Integrated Energy Plan directive and continues carrying out our core regulatory responsibilities while supporting Ontario’s economic, social and environmental development,” OEB said in a press release.

Owen replaced Mark White, who served less than a year after being appointed OEB chair in July 2024.

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CAISO Price Formation Proposal Looks to Reduce ‘Unnecessary’ Market Mitigation

After years in the making, CAISO has released a price formation proposal intended to reduce “unnecessary” market power mitigation, strengthen reliability and provide consistent pricing incentives in the Western Energy Imbalance Market (WEIM) and future Extended Day-Ahead Market (EDAM). 

Release of the straw proposal, which was followed by two workshops Sept. 3 and 4, is part of CAISO’s Price Formation Enhancements initiative, started in 2022 to focus on two key subjects around real-time market pricing: balancing authority area-level market power mitigation and scarcity pricing. 

BAA-level market power mitigation is “a ‘nickname’ for market power mitigation applied to WEIM transfer constraints and, in the future, EDAM transfer constraints,” James Friedrich, CAISO policy developer, said at the Sept. 3 workshop. 

“So instead of saying that mouthful, we just call it BAA-level market power mitigation,” Friedrich said at the workshop. “And what it’s doing is ensuring that, when transfer constraints bind between balancing areas participating in the regional markets, that we ensure that there is competitive pricing inside the balancing areas that are price-constrained from the broader market due to these constraints.” 

The market power mitigation process “essentially prevents suppliers from within these constrained BAAs from exercising market power over the constrained balancing area,” Friedrich added. 

To improve its BAA-level market power mitigation process, CAISO’s proposal is considering using a “grouping approach” for a market power mitigation (MPM) test, one that will try to increase competitive pricing when a participating BAA becomes price-separated from the broader market due to binding transfer constraints, the proposal says. 

Currently, during a MPM test, each BAA is modeled individually. This means that power supply from neighboring BAAs is not accounted for during a MPM test. Therefore, this practice could be overestimating market power and could lead to unnecessary mitigation, the proposal says. 

The individual MPM test approach “was acceptable when the WEIM had fewer participating entities, but it has become a concern in today’s larger, more interconnected market,” the proposal says. 

BAAs rarely operate as fully isolated “islands,” the proposal says. With dozens of BAAs participating in the regional markets, a “rigid one-by-one test could mischaracterize competitive conditions and reflect an outdated methodology,” the proposal says. 

On the other hand, a group of BAAs in a MPM test would become a combined region, allowing the market to assess the BAAs with spare transfer capability, according to the proposal. 

Scarcity Pricing Improvements

The second main subject of the proposal is scarcity pricing, a mechanism meant to “create really powerful market incentives,” Friedrich said during the Sept. 4 workshop. 

Scarcity pricing incentives coordinate the behavior of all market participants to improve reliability in tight conditions by encouraging generators to be and stay online, getting flexible demand off the system, and incentivizing storage resources to defer charging, Friedrich said. 

“More reserves generally means a more reliable system. Fewer reserves mean a less reliable system,” Friedrich said. “When you get in scarce conditions, each incremental megawatt is valued not just by the cost of production for the unit to produce [electricity], but also in valuing its role in preventing a system outage.” 

Currently, CAISO’s scarcity pricing mechanisms include: 

    • a tiered scarcity reserve demand curve (SRDC) that provides the marginal prices of ancillary services when the availability of this type of power supply is low. 
    • a Flexible Ramping Product (FRP) demand curve that provides the scarcity pricing signal in the real-time market.  
    • an imbalance reserve demand curve for the extended day-ahead market that allows the market to forgo procuring imbalance reserve. 

However, CAISO has found problems with each mechanism. The SRDC applies inconsistently in the real-time market, meaning real-time energy and reserve prices do not consistently incorporate the scarcity value of reserves and “thus do not consistently reflect short-term operating conditions,” CAISO said in the proposal. This issue can result in inadequate price signals and increase reliability risks.

“The scarcity reserve demand curve is not really a great tool for scarcity pricing the way we traditionally think about it … because it’s not designed to trigger unless there is an actual shortage,” making it a reactive rather than proactive price signal, Friedrich said. 

“And the gold standard for scarcity pricing are designs that are intended to be proactive, meaning they kick in before the actual shortage condition occurs, which is the whole point,” he added. 

CAISO staff and stakeholders said the ISO should consider “re-optimizing” ancillary services in the real-time market. Doing so would “allow the market to better reflect real-time system conditions and costs by releasing ancillary services capacity procured in the day-ahead market that could be more valuable for energy or other services in real-time,” CAISO said in the proposal.  

CAISO and stakeholders are considering extending procurement of ancillary services into the five-minute market to provide more consistent price signals, the proposal says. 

CAISO also is looking to improve scarcity pricing mechanisms so they gradually increase energy and reserve prices ahead of supply shortages. CAISO’s Department of Market Monitoring suggested extending use of the Flexible Ramping Product (FRP), which could help the real-time market better position resources and improve pricing signals ahead of potential scarcity conditions, the ISO said in the proposal. 

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Study Details Business Case for BTM and FTM Storage in Mass.

A new economic study found that front-of-the-meter battery storage systems in Massachusetts “significantly outperformed” behind-the-meter systems despite significant programs and incentives supporting BTM storage.

The study authors said the economic advantage of FMT storage would be even greater in states with less robust BTM incentives. However, they emphasized that BTM systems typically provide resilience benefits that aren’t easily quantified, which may justify the higher costs for some customers.

The report was written by American Microgrid Solutions and commissioned by the Clean Energy Group; it is intended to help the Cape and Vineyard Electric Cooperative evaluate its storage options.

It compared one, 2-MW FTM battery with five smaller BTM batteries, with equal capital costs between the FTM and BTM options. “Commercial-scale BTM battery storage is the most expensive type of battery system at this time,” the authors wrote.

They noted that large FTM batteries “benefit from economies of scale, can execute lucrative tolling agreements with utilities and can more easily access wholesale energy markets,” while small residential storage systems “benefit from off-the-shelf, fully commercialized components that do not require custom engineering and design, and do not typically encounter costly interconnection barriers.”

“Commercial-scale [BTM] systems, which typically fall into the 60- to 200-kW range, often require custom engineering and design and may encounter interconnection barriers, but do not enjoy easy access to utility tolling agreements and wholesale energy markets,” the authors added.

The report found the payback period for an FTM battery to be about 14 years, compared to a 19-year payback period for BTM storage, assuming 20 years of continued state incentives. The BTM payback period increased to about 24 years when the duration of incentives was cut to five years.

Cumulative 20-year revenue and cash flow was estimated to be about $1.6 million for FTM storage, compared to about $300,000 for BTM storage with 20 years of incentives. The study noted that FTM storage is heavily dependent on the rates it is paid via contracts with electric utilities, while BTM storage systems “rely heavily on incentives and subsidies.”

While BTM storage is supported by the federal investment tax credit (ITC) and Massachusetts state programs including the ConnectedSolutions, SMART and Clean Peak programs, FTM resources with utility contracts are eligible only for the ITC, the authors said.

Overall revenues could change significantly if the assumptions related to state policy or utility contracts are altered, the authors found. Reducing the tolling rate paid by utilities by 20% lowered the 20-year cash flow by $1.3 million, while reducing the duration of state incentives to just five years resulted in a negative cash flow of nearly $500,000.

Although FTM storage outperformed BTM storage in the modeling, the study noted that BTM storage can provide significant reliability benefits by supplying backup power during outages.

“The differential between net costs of the FTM system versus the BTM systems effectively establishes the cost of providing backup power to the facilities,” the authors wrote. “The ‘resilience premium’ on the BTM systems averages $13,300 per site per year, or $66,500 annually for five sites, assuming state performance incentives continue at their present values for 20 years.”

They also noted that FTM systems may be more susceptible to interconnection barriers “because they are typically much larger than their BTM counterparts and have no capability to manage loads ‘behind the meter’ to limit reverse flow,” adding that interconnection uncertainty can “make forecasting financial returns for FTM batteries challenging.”

Battery storage projects make up about half of the ISO-NE interconnection queue, with more than 15 GW of storage seeking to interconnect.

The ISO-NE queue has been frozen since June 2024 as the RTO transitions to its new cluster study process, which was mandated by FERC Order 2023. The order is intended to help address interconnection backlogs and barriers across the country. (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.)

ISO-NE’s first cluster study, which will be conducted under transitional rules, is scheduled to begin Oct. 10. Interconnection customers have until then to submit executed cluster study agreements, and stakeholders should get a better sense of which projects intend to proceed with the interconnection process following the deadline. The cluster study will take 270 days, and the restudy process will take 90 days.

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Feds Pull $716M Loan Commitment from N.J. Offshore Wind Project

The U.S. Department of Energy has withdrawn a $716 million loan commitment that would have helped New Jersey upgrade the state’s transmission system to connect offshore wind to the grid. 

DOE approved the loan commitment to Jersey Central Power and Light (JCP&L) in January, shortly before President Donald Trump took office. A department spokesperson called the commitment “conditional” and said “DOE and JCP&L mutually agreed to withdraw from the commitment,” declining to comment further. 

New Jersey Board of Public Utilities spokesperson Alonza Robertson said the agency is “deeply disappointed in the federal government’s decision to cancel funding for critical transmission infrastructure projects.” 

The loan commitment would have supported the New Jersey Clean Energy Corridor, a transmission infrastructure upgrade project. Specifically, it would have funded a portion of the work that resulted from the agency’s use of FERC Order 1000’s State Agreement Approach with PJM. 

The $1.07 billion series of projects, in which JCP&L had a major role, were centered around a new $504 million substation next to the utility’s existing Larrabee substation. The package of transmission upgrades would have enabled the state to deliver 6,400 MW of offshore wind generation to the PJM grid. 

Grid Plans Postponed

The BPU, however, put the project on hold for 30 months on Aug. 13 after the state’s only remaining viable offshore wind project, Atlantic Shores, asked to terminate its Wind Renewable Energy Agreement because of opposition to the project from the Trump administration (See N.J. Puts on Hold Remaining Pieces of $1.07B OSW Transmission Project.) 

“These transmission investments are essential for grid reliability, energy security and economic development in our state,” Robertson said in a statement to RTO Insider. “The cancellation of committed federal support undermines the certainty that developers, utilities and ratepayers need to plan for our energy future and represents a step backward in building a clean energy future.” 

A spokesman for JCP&L, which is owned by First Energy, declined to comment. 

The loan commitment withdrawal emerged several days before a Labor Day statement jointly signed by New Jersey Gov. Phil Murphy and four other governors reaffirming their commitment to offshore wind. The statement called on the Trump administration to “uphold all offshore wind permits already granted and allow these projects to be constructed.” It followed a stop-work order issued by the administration against Ørsted’s Revolution Wind project off the coast of Massachusetts and Rhode Island. (See related story, Revolution Wind Sues to Lift Federal Stop-work Order.) 

“Efforts to walk back these commitments jeopardize hardworking families, wasting years of progress and ceding leadership to foreign competitors,” wrote Murphy and the governors of New York, Connecticut, Massachusetts and Rhode Island. “These projects represent years of planning, billions of dollars in private investment and the promise of tens of thousands of additional jobs. They are revitalizing our ports, strengthening our supply chains and ensuring that America — not our competitors — leads in clean energy manufacturing and innovation.” 

Projected Ratepayer Savings

New Jersey’s offshore wind sector, like those of other states, initially struggled amid high equipment costs and logistical challenges, which resulted in Danish developer Ørsted’s abandonment in October 2023 of its Ocean Wind 1 and 2 projects, two of New Jersey’s first three projects, leaving only Atlantic Shores moving forward. 

The state’s ambitious effort to use the SAA to create grid upgrades that would tie several projects to the grid, rather than leaving each to forge their own connection route, was seen as innovative. DOE’s proposed loan to the project was among several loan commitments totaling $22.9 billion made to utilities for transmission, pipeline and clean power investments in the waning days of the Biden administration. (See LPO Offers Eight Utilities $22.9B in Loan Guarantees.) 

Announcing the loan commitment Jan. 16, DOE’s Loan Program Office (LPO) said the project “comprises 40 miles of transmission and substation upgrades and expansions.” The department said the proposed loan would “reduce upward pressure on electricity rates for ratepayers from project costs as a result of the reduced cost of debt associated with LPO financing” and would produce “an estimated $150 million in savings for JCP&L ratepayers over the life of the loan.” 

In a July 30 quarterly report filed as required by its agreement with the BPU, JCP&L said the project was on schedule and in the engineering, procurement and permitting phase. One element, the Larrabee Substation, was in construction, the report said. About 45% of the permitting and 60% of the engineering had been completed, the report said. 

The report said the utility had spent about $59.5 million of an expected cost of $910 million. 

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West Coast Senators Urge Passage of Calif. Pathways Bill

Six Western U.S. senators came out in support of the California legislation needed to transform CAISO’s market into an independent regional energy market, saying in a letter to Gov. Gavin Newsom that the bill promises “improved grid reliability and significant energy cost savings.” 

Democratic U.S. Senators from Oregon, Washington and California issued the letter in support of SB 540, urging Newsom to help get the bill passed before the Golden State’s legislative session ends Sept. 12.  

A heavily amended version of the bill passed the state Senate on a 36-0 vote in early July but stalled in the Assembly after many backers pulled their support in protest of the amendments.  

While one of the bill’s sponsors, Sen. Josh Becker (D), recently expressed confidence about passage of a suitable version of the bill this session, supporters are under pressure to ensure a stripped-down version of the legislation is printed before midnight Sept. 9 to comply with a rule requiring an amended bill to be in print for 72 hours before lawmakers take a vote on it. (See Pathways Bill Will Make It to Newsom’s Desk, Author Says.) 

The bill would implement the plans of the West-Wide Governance Pathways Initiative, a multistate effort to create an independent “regional organization” (RO) to govern CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market (EDAM), the latter set to launch in 2026. 

“In California, Oregon and Washington, broad participation in an expanded regional power market will result in improved grid reliability and significant energy cost savings for our constituents,” the senators’ letter said. 

Sens. Jeffrey Merkley and Ron Wyden of Oregon, Sens. Patty Murray and Maria Cantwell of Washington, and Sens. Adam Schiff and Alex Padilla of California signed the letter. 

The lawmakers emphasized many of the arguments EDAM supporters have made, including claims that the day-ahead market option will result in expanded access to generation resources across the West, improved grid resiliency and affordable electricity. 

They also noted that the onset of new load from data centers, onshoring manufacturing and increased electrification “is straining both the grid and our constituents’ pocketbooks.” 

“In tandem, consumer electric bills have soared — a result of rising demand, increasing wildfire risk and the misguided, impractical policies of the Trump administration,” the lawmakers wrote. “It is now being reported that around 80 million Americans are sacrificing basic expenses like food or medicine just to keep the lights on. Expanded regional power markets would allow for better utilization of existing generation, helping to meet growing demand while lowering energy costs.” 

“We urge you to take this extraordinary opportunity to jump-start the expansion of regional markets by enabling the CAISO, through legislation, to partner with an independent RO, thereby improving grid reliability and electric bill affordability for all West coast states as soon as possible,” the lawmakers stated. 

In tandem with CAISO’s EDAM, SPP is developing a competing day-ahead market for the West — Markets+. 

One of the largest participants in Markets+ is the Bonneville Power Administration, which manages the output from 31 hydroelectric dams in the federal Columbia River Power System, while also operating more than 15,000 miles of transmission lines — about 75% of the Northwest grid. 

In the lead-up to BPA’s day-ahead market choice, the U.S. senators from Oregon and Washington issued multiple letters, including one in December 2024 saying BPA had failed to make a financial case for joining Markets+. (See BPA Has not Made ‘Business Case’ for Markets+, NW Senators Say.) 

After BPA issued its final record of decision in favor of Markets+ in May, Wyden and Merkley told RTO Insider that the agency had rushed its decision, expressing disappointment. (See BPA Chooses Markets+ over EDAM.) 

Robert Mullin contributed to this article. 

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SPP Board Approves 765-kV Project’s Increased Cost

SPP’s Board of Directors has approved a pair of contentious measures that were put aside during its August quarterly meeting: a tariff change to integrate and operate high-impact large loads, and a revised cost estimate for a 765-kV transmission project in New Mexico and Texas.

The latter approval is contingent on cost and schedule control measures that “meet the [board’s] expectations.”

Southwestern Public Service’s 345-mile project, SPP’s first 765-kV line, was approved in February with an estimated cost of $1.69 billion. SPS filed a revised cost estimate of $3.62 billion in June, more than double the earlier projection and easily outside the variance bandwidth of +/-30% that can lead to a re-evaluation. (See SPP Board Sets Aside 765-kV Costs, Large Load Policy.)

SPS CEO Adrian Rodriguez said during a Sept. 4 special board meeting that the utility has committed to a cost cap and regular reports to the board. He also said it is open to a third-party monitor, as suggested by Texas regulatory staff.

“We’re talking about working with the Southwest Power Pool board, the Southwest Power Pool staff, for this type of transparency and scrutiny and highlight that this is important not just for us, not just for our customers, not just for our regulators in Texas and New Mexico, but for all of you,” Rodriguez told the board, state commissioners and members. “We’re focused on reliability in the Southwest Power Pool and being mindful of the cost impacts to customers across SPP.”

SPP staff said the Potter-Crossroads-Phantom project, which crosses the New Mexico-Texas state line, remains the best technical solution to provide the region with voltage support. It also resolves several needs in the 2025 and 2026 Integrated Transmission Planning assessments and addresses load projections; the RTO’s latest 10-year forecast indicates 105 GW of potential load, almost doubling its current peak of 55 GW.

Casey Cathey, the grid operator’s vice president of engineering, said when the 765-kV project is removed from the 2025 ITP models, staff must add nearly 4 GVARs of temporary reactive power to support the region’s voltage. He said 35 generation projects totaling 10 GW of capacity, some of which are under construction, also are contingent on the SPS line.

“[The SPS project] is required before we can even contemplate moving forward with the 2025 ITP assessments and understanding what that portfolio looks like,” he said. “We did look at alternatives, multiple 345 facilities [and] double-circuit 500-kV facilities. All of those were actually more expensive, [had] wider rights of way and were just less optimal compared to the single 765.”

SPS submitted a cost-cap proposal to the board as part of its commitment to build the project in a “cost-effective manner, with reasonable and measured oversight and customer protections.” It also said it will forgo the return on equity applicable to the cost overruns above the current cost estimate and a 20% variance cap.

The company’s guarantee can be adjusted for exceptions consistent with those provided in competitive bids, such as changes in statutory tax rates, investment costs, import tariffs or secondary impacts on domestic markets, or the schedule resulting from changes in federal, state or local legislation and laws that became effective after Jan. 1. Other exceptions include force majeure (as defined in the SPP tariff) and increases in interest rates.

“I hope we have demonstrated our commitment and transparency to SPP, the staff, board and the commissioners by setting the foundation for 765-kV estimates,” Rodriguez said. “I want to highlight our commitment to being competitive, being transparent and being committed, not just to our customers at SPS but to the entire SPP as we’re evaluating this reliability project.”

He noted the exclusions are primarily based on items that are outside of SPS’ immediate control and those for which it has limited opportunity to mitigate.

The Members Committee approved the revised cost estimate with an 11-1 advisory vote. EDP Renewables opposed the motion, casting doubt on SPS’ cost-containment guarantee, and nine other members — primarily public power entities — abstained.

“We can be a case study on 765,” Rodriguez said. “Our transparency means that we have informed the market, including bidders, of our perspectives on this line, and we can be the case study to make sure that these types of major projects move forward with a clear understanding from the board, from the staff, as to what can be done, what issues arise and where cost mitigations can occur.”

Large Load Integration OK’d

Similar cost concerns were raised by regulators during a Sept. 3 education session on the 765-kV project and SPP’s fast-track study to integrate high-impact large loads (HILLs).

While they favored SPP’s tariff change (RR696) to expedite faster and more predictable interconnection timelines for rapidly developing large loads, they also want to maintain regional reliability, transparency and equitable cost allocation.

Minnesota Public Utilities Commissioner John Tuma spoke for several when he expressed worries about accommodating large loads that might not show up. He drew on the state’s experience in the Iron Range, where he said loads with service agreements don’t always materialize.

“We see a big technology boom. There’s going to be a lot of capital flowing in. It’ll look really sexy,” Tuma said. “Everybody wants to get in the middle of it, but some of them are going to bust, and that’s just a reality that we have to live with. … That’s one of the big concerns as a state that we have because in the end, we pay for our neighbors’ mistakes.

“We want to be quick and nimble. We don’t want to be dumb,” he added. “And so, I’m hoping that we continue to analyze these things carefully. We’re all partners in this together, and if one of our partners screws up, it could cost us and our ratepayers money.”

SPP CEO Lanny Nickell agreed. He said staff will work with the regulators and the Regional State Committee to develop a “fully informed and appropriate” cost-allocation approach for the future.

“The amount of load growth being projected, with much of that driven by data centers, will certainly drive significant transmission upgrade investment,” he said. “We need to make sure that ratepayers aren’t having to bear unfair portions of the cost needed to connect those loads while we have some time to figure out the best cost-sharing approach.”

Staff revised the large load policy to reflect the numerous comments and feedback received from stakeholders, removing conditional high-impact large load service (CHILLS) and the design associated with dispatch, study and charges for the service from its original proposal. It also removed one of three paths for high-impact large load generation assessment (HILLGA).

HILL studies will remain on a 90-day timeline. Changes include a revised HILL definition that clarifies its transmission service study process and its independence from non-conforming load.

SPP members endorsed the tariff change, 18-1, with three abstentions. OGE Energy voted against the measure, citing concerns with delays in the interconnection process and accreditation issues with increases to the planning reserve margin.

Approval is contingent upon SPP modifying the tariff to reinstate a 60-day study under Attachment AQ, which governs upgrades or other changes to delivery point facilities.

Stakeholders approved RR696, as modified, during the Markets and Operations Policy Committee’s own special meeting in August. The measure passed with 95.7% approval after failing during MOPC’s regular quarterly meeting in July at 53.7%. (See SPP MOPC Passes Revised Large Load Policy.)

The tariff change resulted from a directive by then-Chair John Cupparo in May that staff propose by the board’s August meeting a timely, scalable and reliable approach to manage the exponential growth of load demand across the footprint. (See “Cupparo Issues ‘Executive Order,’” SPP Board OKs 1-time Study for LREs’ Gen Needs.)

The CHILLS policy will be taken up during the MOPC, RSC and board meetings in October and November.

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Common Charge Wants to Grow Distributed Resources to Meet Spiking Demand

With rising demand putting pressure on the system, a new group has launched to encourage distributed solutions such as virtual power plants that can be deployed quickly and cheaply.

“Right now, those are two of the biggest issues that we have on hand: affordability and reliability,” Katherine Hamilton — acting executive director of the new group, Common Charge — said in an interview. “And, so, the way we want to do that is to maximize distributed assets that are already being developed and can be plugged into the grid, and to ensure everybody has access to those technologies and those applications.”

Common Charge is a coalition, not a trade group. While it includes companies in the distributed energy resource industry, it also includes nonprofits and consumers, Hamilton said. Founding members include Advanced Energy United, Charge Ahead Partnership, Coalition for Community Solar Access, Eco Capital, Institute for Local Self-Reliance, Pivot Energy, Solar United Neighbors, Sunrun and Vote Solar.

“Distributed solutions often are not even considered in the mix as part of the solution set for mitigating for rate increases and prices going up,” Hamilton said. “So, we want to unlock that and make sure everybody has access to those solutions.”

The distribution system is state regulated, and how much distributed resources are used varies by jurisdiction, so part of the group’s efforts is to figure out best practices and ensure they are adopted as widely as possible.

“If you try to follow the distributed energy resource ecosystem, it is very diverse and very disaggregated,” Hamilton said. “And what we’re trying to do is bring a little more organization to that and then drive a lot more impact.”

Distributed resources are at work in different regions, with Common Charge pointing to PJM’s dispatch of thousands of megawatts of demand response during heat waves this year. New York delivered 6 GW of distributed solar early and under budget in 2024. New England benefited from behind-the-meter solar this summer as it helped meet high demand reliably.

ERCOT has a pilot program providing the grid with nearly 60 MW of power from customer-sited assets, and microgrids in Texas have helped keep hospitals running. In a recent test in California, 100,000 distributed assets simultaneously discharged to the grid for two hours, functioning like a power plant and helping to cut peak demand.

“From a small business improving operations through an energy management system, to a community leveraging solar to save on energy bills, to homeowners enjoying the comfort of smart thermostats, millions of distributed assets already exist, and more are waiting to be leveraged in a modern, coordinated energy grid,” Hamilton said. “These assets are proven to increase reliability, lower utility costs and grow local economies.”

Some of the distributed technologies like solar panels are tied to climate change and the divisive politics surrounding it, with skeptics dominating the federal government now, but Hamilton said Common Charge was focused on more bipartisan issues.

“We’re trying to address two of the big issues that [exist] regardless of whether people are talking about climate change or not, and we’ve just seen as demand rises and more strain is put on the grid — from data centers, from increased manufacturing, from electrification — that affordability and rates are going up,” she added. “Affordability is huge, and that’s regardless of what’s happening on the climate side, regardless of what’s happening on the federal side; it’s really just about affordability on a very day-to-day, kitchen table issue.”

The other major issue implicated by demand growth is reliability, which has been a focus of the Trump administration, and distributed resources can help there, Hamilton said.

Former FERC Chair Pat Wood — now CEO of Hunt Energy Network, which is deploying distributed assets across ERCOT — endorsed Common Charge’s mission. He is working on a parallel effort by the Pew Charitable Trusts with former New York Public Service Commission Chair and PJM COO Audrey Zibelman to expand the use of DERs around the country.

The Pew effort is to give decision-makers, which include utilities, state regulators, governors’ offices and even federal officials, a detailed plan for maximizing the benefits of DERs. Wood said he benefited from similar resources while working to restructure Texas’ electricity market in the 1990s when he chaired the Texas Public Utility Commission.

“What we’re trying to do with this group is put out, not just the principles, but how do you do it?” Wood said. “What do you need to address, for interconnection costs, for timetables, for standardization of equipment, for rates, for customer engagement or other customer protection aspects to it, which we’ve learned from all the other industries that just because they’re a competitor, it doesn’t mean they’re nice.”

The rules need to be balanced so that customers’ privacy is protected without being so onerous they hold back the deployment of DERs to benefit the broader grid, he added.

“We’re in the mode of no megawatt left behind, because with all this kind of electrification of everything, and then, of course, the data tsunami that’s kind of sweeping over everywhere, we’re going to need power coming off every corner of the grid,” Wood said.

The distribution grid has been used to ship power one way historically, but recently that has changed, with advances in computing enabling appliances from smart thermostats to water heaters, pool pumps and plug-in cars to help balance the power system.

“There’s just so much more on the grid than when we opened up the Texas market, or when I was at FERC and we were getting the final rules done on the transmission grid,” Wood said. “That same zeal and effort need to continue all the way to the meter.”

FERC has issued major orders on tapping the demand side to benefit wholesale markets in the past, and numerous states have held “grid of the future” proceedings, but both Common Charge and Wood think now is the time that the technologies will really take off.

It is twice as expensive to build a natural gas plant as it was five years ago, and while renewables have helped keep wholesale prices in check, that has not flowed through to the distributed grid, with the rates rising.

“The regulated rates are going up way faster, and the competitive rates coming down, [and they] kind of net each other out,” Wood said.

The promise of competition was lower prices overall, not just shifting costs from the competitive side of the industry to the regulated side, Wood said, and enhancing DERs can make that promise come true. Now with the pressure of rising demand helping push prices even higher, it has attracted more attention from politicians, with governors and legislators around the country focused on ensuring affordability. Wood said that is not a bad thing.

“They can help create the investments and certainty for generators to come in to help push the monopoly utilities to open up their grid and embrace new technology to incentivize customers to get smart and to use their power in the market to discipline price and service,” Wood said. “I mean, who better than the governor or even a president to do that?”

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MISO 2025 Tx Expansion Estimate Drops Slightly to $12.4B

The cost estimate for MISO’s 2025 Transmission Expansion Plan (MTEP 25) has fallen slightly from previous estimates to $12.36 billion.  

MISO previously clocked MTEP 25 at $13.1 billion and 444 projects, driven by growing load. (See MISO 2025 Transmission Planning Cycle Rises to $13B.) The newest version includes 10 fewer projects.  

The RTO said MTEP 25 “is shaping up to be another significant year driven by load growth and reliability.” According to the grid operator, MTEP 25 includes 1,930 miles of transmission lines (44% of which are new) that would accommodate nearly 11.6 GW of spot load additions.  

The 2024 MTEP included $6.7 billion worth of projects. That figure does not include the $22 billion second long-range transmission portfolio that technically was included under the annual planning cycle.  

MTEP 25 contains $3.44 billion in baseline reliability projects as dictated by NERC standards, $673 million in projects necessary for generator interconnections, nearly $5 billion in projects for load growth, $1.38 billion in projects to address the age and condition of existing facilities, $1.3 billion in projects to satisfy locally defined reliability criteria and $489 million to address more general local needs.  

Louisiana is set to receive the most investment this year, at more than $3.4 billion. The amount is split between baseline reliability projects and those needed to meet load growth.  

MTEP 25’s 10 most expensive projects account for 44% of the portfolio’s total cost, with four of the 10 in Louisiana. Entergy Louisiana’s Cargas 500-kV station and Smalling 500/230-kV station project in the northern part of the state is the year’s most expensive, at $1.2 billion. Entergy Louisiana said the project is necessary to support new customer load. The work would be located near a proposed Meta data center slated for Richland Parish. 

MTEP 25 spending by category | MISO

Entergy Louisiana’s Babel-to-Webre 500-kV baseline reliability project takes the second-most expensive slot at almost $1.1 billion.  

This year, 49 projects went through MISO’s expedited project review and were cleared to begin construction before MISO’s Board of Directors votes on approving this year’s transmission package in December.  

At a Sept. 5 West Subregional Planning Meeting, Joseph Dunn, MISO director of transmission planning, said the “tremendous” number of expedited review requests were brought on by load growth.  

MISO’s modeling for MTEP 25 assumes projects from the second long-range transmission portfolio enter the scene on schedule in 2035. Five MISO states — the majority of which won’t contain a project — are trying to revoke the cost-sharing of the $22 billion portfolio, which would put the projects in jeopardy. (See MISO States Split on FERC Complaint to Unwind $22B Long-range Tx Plan.)  

This year’s transmission expansion package also contains a blast from the past, as Northern States Power has entered a $92 million maintenance project for a 345-kV line that was part of MISO’s 2011 Multi-Value Project portfolio.  

According to MISO, any maintenance on Multi-Value Projects must be classified under the multi-value category.

MISO plans to publicly post its MTEP 25 report Sept. 29, kicking off a two-week comment period for stakeholders. The grid operator will preview a more final MTEP 25 report at the Oct. 8 Planning Advisory Committee meeting.  

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Aging, Expensive N.Y. Nuclear Plants a Bargain, Report Finds

A new report estimates keeping New York’s aging commercial nuclear reactors running through 2050 would save $50 billion in energy. 

Other economic and environmental benefits would accrue from continued operation of the four reactors, which now account for nearly half of New York’s emissions-free electricity, the authors point out. 

The state’s energy planners have concluded the same — they included nuclear energy in the state’s updated energy plan and have recommended the state continue subsidizing the reactors until 2049. 

The Carbon Free NY Coalition, a nuclear power advocacy group, announced the new report by the Brattle Group on Sept. 4. 

Along with the $50 billion in savings, the Brattle analysis concluded that extended operation would contribute $38 billion to the state’s economy; support 2,020 direct jobs and 12,380 other jobs; and preserve $10 billion in tax revenue, $4 billion of it going to the state. 

The four reactors also are increasingly important to New York’s decarbonization goals, as efforts to develop solar and wind generation within the state’s borders are proceeding more slowly than hoped. 

Fossil generation equivalent to the reactors’ 27.5 TWh output in 2024 would have emitted 16.4 million tons of CO2, the coalition noted. The state has paid the reactors’ operator $3.69 billion in subsidies since 2017, in recognition of the reactors’ high cost of operation as well as their high value to the state’s grid and environment. 

“Keeping the upstate nuclear plants operating until midcentury will contribute substantially to New York’s clean energy goals and keep costs lower for ratepayers. It will also support the New York economy, contributing substantially to GDP and jobs — particularly in the upstate region,” said Dean Murphy, lead author of the report and a principal of The Brattle Group. 

The four reactors at three plants in two locations along the south shore of Lake Ontario all are owned by Constellation Energy, which is part of the coalition that commissioned the Brattle report. 

Nine Mile Point Unit 1 is the oldest operating commercial reactor in the nation, and the Ginna reactor is the second-oldest. The FitzPatrick reactor entered commercial operation in 1975; Nine Mile Point Unit 2 is a relative youngster, entering commercial operation in 1988. 

Constellation needs signals of support to take the step of updating and relicensing the geriatric plants, and New York is moving to provide those signals. (See N.Y. Makes Case for Extending Nuclear Subsidies to 2049.) 

Given that renewables are developing slowly in New York, and given that the state is pinning its energy strategy on the hope that new technologies will be perfected, affordable and scalable, nuclear power takes on considerable importance for the Empire State if it is to meet its decarbonization targets. (See N.Y. Considers New Fossil Generation as Renewables Lag.) 

The report analyzes the impact of FitzPatrick, Ginna and Nine Mile Point 1 retiring in 2029, due to expiration of New York’s ZEC subsidy program, and Nine Mile Point 2 retiring in 2032, due to expiration of the federal 45U tax credit. 

They have a combined nameplate rating of 3,537 MW and run at a five-year average 94% capacity factor, and their retirement would lead to an average 3.36% annual increase in retail prices from 2030 to 2050, the report states. 

Retirement of the four reactors likely also would increase the amount of fossil generation the state needs — the report points out that this is exactly what happened when the Indian Point nuclear plant was shut down. 

Earlier in 2025, Gov. Kathy Hochul (D) directed the New York Power Authority to develop new nuclear generation. (See N.Y. Pursuing Development of 1-GW Advanced Nuclear Facility.) 

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MISO Selects 10 Gen Proposals at 5.3 GW in 1st Expedited Queue Class

MISO has assembled 10 generation finalists to enter its first interconnection queue fast track, and the list includes five natural gas proposals, three solar farms, one wind farm and a battery storage facility.  

About 4.3 GW of the projects’ combined installed maximum capacity of nearly 5.3 GW would come from natural gas generation. The projects under evaluation span six states and have in-service dates ranging from January 2027 to August 2028. MISO whittled the list down from 47 applications. (See 26.5 GW of Mostly Gas Gen Compete for MISO’s Sped-up Grid Treatment.)  

The RTO said it continues to evaluate the remaining 37 proposals for inclusion in upcoming study cycles. MISO plans to study up to 10 generation projects per quarter, with a maximum of 68 projects, before it retires the temporary express lane process Aug. 31, 2027. The fast track aims to get necessary generation interconnected sooner than MISO’s regular queue currently allows.  

MISO said the first cycle of generation projects to enter the expedited study process were selected by a combination of the timestamp of their application submission and application withdrawals, a review of common constraints near the project and developers’ ability to rectify shortcomings in their applications prior to the study kickoff.  

“The first 10 projects cover all three regions of MISO, stretching from Louisiana to Minnesota,” MISO Senior Vice President of Planning and Operations Jennifer Curran said in a press release.  

Curran said each project “must meet rigorous standards to make sure only necessary and feasible proposals move forward.” 

Applicants had to identify a specific resource adequacy need their projects would address and secure a blessing from their relevant regulatory authority to be considered.   

Entergy La.’s Gas Plants for Meta Make the List

Entergy Louisiana’s proposed 1.64-GW gas plant, intended to meet the upward of 2 to 2.3 GW Meta will need to operate its $10 billion, hyperscale data center, is the largest on the list. (See Louisiana PSC Approves 3 Controversial Gas Plants Ahead of Schedule for Meta Data Center.) The Franklin Farms units are two of the three Entergy Louisiana would need to build to keep Meta’s facility powered.  

Invenergy’s proposed 1.2-GW gas plant in Kenosha County, Wis., to address a 1.75- to 2-GW need among Wisconsin Electric customers is the second-biggest project.  

Otter Tail Power is the sole battery facility to make the cut. The 75-MW Hoot Lake Battery Energy Storage System is proposed to serve a need highlighted in Minnesota’s Integrated Resource Plan.  

MISO also agreed to study Interstate Power and Light Co.’s separate requests for a 750-MW combustion turbine and 350-MW wind farm in central Iowa to help serve a 3.2 to 3.5-GW projected need in MISO’s Local Resource Zone 3.  

Other contenders in the fast lane include: MidAmerican Energy’s 263-MW natural gas combustion turbine in Adair County, Iowa; Lincoln Capital Land’s 125-MW solar farm to serve City Water Light & Power’s unmet needs from generation retirements in downstate Illinois; Ameren Missouri’s 300-MW solar farm in the northern portion of the state; Minnesota Power’s 85-MW Boswell Solar Project in Itasca County, Minn.; and an upgrade of the gas turbine at Minnesota Municipal Power Agency’s Faribault Energy Park in southern Minnesota that requires 60 MW of additional interconnect capacity.  

Curran called the queue fast track a “critical tool we can use to support reliability as we work toward long-term improvements in the interconnection process.”  

MISO plans to accept another round of applications for expedited study in early November and begin studying them at the beginning of December.