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January 9, 2026

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Meta Announces Nuclear Projects with Vistra, TerraPower, Oklo

Meta, Oklo, TerraPower and Vistra are planning nuclear power projects totaling as much as 6.6 GW.

The announcement nine days into 2026 continues the flurry of nuclear deals the tech sector struck in 2025 as it scrambled to secure firm power for data centers.

Like the previous agreements, a significant percentage of these new deals depends on the success of advanced technologies that still have a series of technological hurdles to overcome and are not expected to produce power at scale for at least several more years.

Under the new agreements:

  • Vistra will sell the entire 2,176 MW capacity of its Perry and Davis-Besse plants to Meta under 20-year power purchase agreements. Also, it will uprate the Perry, Davis-Besse and Beaver Valley plants by a combined 433 MW and sell that to Meta, as well.
  • TerraPower and Meta will develop eight Natrium advanced nuclear plants; the combined rating would be 2.8 GW, plus 1.2 GW of storage capacity through the dual-function design of the reactor TerraPower is designing.
  • Oklo will use power prepayments and other funding from Meta to advance its plans for a 1.2-GW nuclear power campus.

Meta said the TerraPower deal is its largest support of advanced nuclear technology and that the agreements announced Jan. 9 collectively make it one of the most significant corporate purchasers of nuclear energy in U.S. history.

Meta previously struck a 20-year deal with Constellation Energy for output from the 1,025-MW Clinton Clean Energy Center.

The amount of power the rapidly expanding data center industry consumes and the potential costs this will inflict on other electricity customers have become a flashpoint. The Vistra plants and the Oklo site are in PJM territory; a location has not been chosen for the TerraPower project.

Meta pointed out in its news release that it pays full price for the electricity it uses and supports the broader grid through these energy agreements. It also creates jobs, helps secure America’s position as a global AI leader and drives innovation in new technology, Meta said.

To date, the projects it supports have added nearly 28 GW of new energy to grids in 27 states, Meta added.

Vistra said the three plants, whose four reactors originally were licensed from 1976 to 1987, were on a path to retirement as recently as 2020.

With the Meta deal providing economic certainty for the expensive facilities, Vistra now will begin planning to request renewals of the reactors’ operating licenses, presently set to expire from 2036 through 2047. Twenty-year renewals would extend the potential operating lifespan of the reactors to 80 years.

The PPAs will start in late 2026; the uprates are expected to be performed though 2034.

TerraPower will use funding from Meta to support the deployment of its 345-MW sodium-cooled advanced reactor design. The two companies are working to identify a specific site for the initial two-reactor unit TerraPower hopes to complete as soon as 2032.

Oklo will use Meta’s funding to secure nuclear fuel and advance development of its first Aurora powerhouse on 206 acres of the former Portsmouth Gaseous Diffusion Plant in southern Ohio. The first phase is targeted to come online as soon as 2030 and the full 1.2 GW is targeted by 2034.

As the timelines imply, TerraPower and Oklo have numerous milestones to meet before they can send power to the grid. But both consider themselves leaders within the crowded field of advanced nuclear reactor designers, and both already have passed important regulatory and developmental milestones.

“Our agreements with Oklo and TerraPower will help advance this next generation of energy technology,” Meta said. “The agreements also mean that Oklo and TerraPower have greater business certainty, can raise capital to move forward with these projects and ultimately add more energy capacity to the grid.”

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Black Hills Completes $350M Tx Project as New BA Prepares to Join CAISO’s WEIM

Black Hills Energy completed construction on a 260-mile, $350 million transmission expansion project that will interconnect electric systems in Wyoming and South Dakota, while expanding the footprint of CAISO’s Western Energy Imbalance Market.

The transmission line is part of Black Hills’ Ready Wyoming electric transmission expansion project and directly connects Black Hills subsidiaries Black Hills Power and Cheyenne Light, Fuel and Power.

The line was energized and placed in service in December, the company said in a Jan. 7 announcement.

“This transformative project will benefit our customers for decades to come, supporting our success in providing long-term value by delivering reliable and cost-effective energy to our customers,” Linn Evans, CEO of Black Hills Corp, said in a statement. “Ready Wyoming reduces reliance upon third-party transmission and allows us to provide customers with the value of expanded access to energy markets.”

In 2024, Black Hills Power and Cheyenne Light announced they would move from SPP’s Western Energy Imbalance Service to CAISO’s WEIM. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.)

The decision would expand the WEIM’s presence in Montana and Wyoming and extend its footprint eastward to take in a slice of South Dakota, which would become the 12th state included in the market.

Under the WEIM implementation agreement signed by Black Hills Power and Cheyenne Light, the utilities agreed to register a new balancing authority to facilitate participation in the market by 2026.

The newly energized 260-mile line is part of Cheyenne Light’s FERC tariff and will be within the WEIM when the utility begins participation in May, according to Black Hills.

“The project is expected to maintain long-term cost stability for customers, enhance system resiliency and access to power markets, support local economic growth and facilitate future development of energy resources in Wyoming,” Black Hills said in a news release.

Black Hills plans to recover approximately $300 million of the total transmission investment through the company’s transmission rider and recover about $50 million of the remaining distribution investment through base rates, according to the news release.

Black Hills could also play a role in the competition between CAISO’s Extended Day-Ahead Market and SPP’s Markets+. Black Hills and NorthWestern Energy announced a merger in August 2025, and the two entities’ sprawling territories could shape the footprints of the two competing Western day-ahead markets in key ways, although NorthWestern — a WEIM member — has not publicly signaled a leaning toward either day-ahead market. (See Black Hills-NorthWestern Merger Could Reshape Western Market Map.)

The deal requires federal and state approvals.

Black Hills Energy’s Colorado subsidiary has recently filed with that state’s utility commission for approval to join Markets+. (See Black Hills Colorado Seeks Approval to Join Markets+.)

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CAISO Looks to Remove Stagnant Projects from Interconnection Queue

CAISO has proposed new interconnection criteria to flush out stale projects from a generator interconnection queue that has reached record volumes in recent years.

The proposed change is part of the ISO’s Interconnection Process Enhancements 5.0 initiative. CAISO held a workshop Jan. 7 to review its interconnection enhancements final proposal.

In the proposal, CAISO would apply “commercial viability criteria” (CVC) to projects that had requested to extend their commercial operation date (COD) — specifically when a COD had exceeded or would exceed seven years from the date of the original interconnection request. Projects that could not meet such CVC would be withdrawn from the interconnection queue, the proposal says.

This approach would “broaden the applicability of CVC from only projects and capacity with transmission plan deliverability to all projects and capacity, including energy only projects,” the proposal says.

CAISO says the current process for limiting a project’s time in the interconnection queue is time-intensive and requires project-specific analysis. The ISO “remains concerned with the [number] of older, seemingly stagnant projects in the interconnection queue and wants to see projects advance toward commercial operations or withdraw,” the proposal says.

Calpine asked CAISO to exempt projects that will repower an existing generating facility. However, the proposal notes the ISO has “been challenged with generating facilities that have retired or come offline and have submitted repower requests and are not proceeding to redevelopment and commercial operation.”

“The ISO will continue to hold repower projects … accountable to the commercial viability requirements,” CAISO said in the proposal. “The ISO believes retired generating facilities and repower projects should proceed to redevelopment and commercial operation in a timely manner, same as queued projects.”

The proposed process would not apply to projects that have been delayed due to interconnection study results or transmission owner construction.

American Clean Power (ACP) of California urged CAISO to be cautious with the proposed interconnection queue revisions.

Excessively stringent requirements “could actually derail viable projects, particularly at a time where projects are simultaneously trying to expedite commercialization to secure expiring tax credits and facing uphill battles with permitting challenges,” said Caitlin Liotiris, principal at Energy Strategies, who represented ACP in comments on the plan.

“Unless CAISO includes exceptions and flexibility in its proposed queue management process, ACP-California opposes this aspect of the proposal,” Liotiris said.

EDF power solutions opposed the revision too, saying federal policy shifts are “significantly changing the permitting and procurement landscape.”

Those shifts include changes to environmental and land-use permitting processes; supply chain and materials procurement constraints; and labor market and wage policy changes affecting project timelines, the company said in its comments.

Another revision in the final proposal is one that would remove requirements for projects to meet the ISO’s non-load serving entities (LSE) corporate sustainability policies to receive commercial interest points.

The corporate sustainability policy requirement was unnecessarily restrictive, CAISO said in the proposal. Previous CAISO scoring data indicated non-LSE projects competed effectively in the scoring process, and CAISO had not received concerns about point values from non-LSE entities, the proposal says.

The final proposal also includes, among other items:

    • the addition of distribution system interconnection projects into CAISO’s intake project scoring system;
    • an updated process for CAISO’s generation interconnection and deliverability allocation procedures that would allow a named vice president on the committee to appoint another ISO vice president as a delegate if the named vice president is unavailable. This would avoid any risk of non-compliance with the five-business day requirement, the proposal says;
    • the elimination of a requirement that non-LSE projects meet corporate sustainability goals in order to obtain commercial interest points in interconnection scoring.

Comments on the final proposal are due Jan. 21, with a vote by the ISO Board of Governors planned for March 5.

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Black Hills Colorado Seeks Approval to Join Markets+

Black Hills Colorado Electric (BHCOE) has filed an application with the Colorado Public Utilities Commission to join SPP’s Markets+, saying it has no choice because it is embedded in a balancing authority that will be a Markets+ participant.

BHCOE, a Black Hills Energy subsidiary, receives balancing services from Public Service Company of Colorado (PSCo), which was granted PUC approval in October to join Markets+. (See Split Colo. PUC Approves Xcel Energy’s Markets+ Application.)

If BHCOE doesn’t sign up with Markets+, PSCo would be required to register BHCOE’s load and generation on its behalf. PSCo would settle directly with SPP and pass along any resulting charges to BHCOE, the utility said in an application filed with the PUC on Dec. 30. Yet BHCOE wouldn’t receive the potential benefits of market participation.

“Direct registration [with Markets+] ensures that unavoidable costs deliver value to BHCOE’s customers and positions BHCOE to access market benefits rather than bearing costs without corresponding advantages,” Kerri Schlachter, Black Hills’ program manager of Western markets and policy, said in written testimony filed with the application.

BHCOE is asking the PUC for approval to participate in Markets+ and to recover the costs of its participation through the energy cost adjustment on customer bills.

Under Colorado PUC rules, the commission will consider the application through an abbreviated proceeding in which a written decision is issued within 150 days. On Jan. 7, the commission set a Jan. 23 deadline for interventions in the case.

Markets+ or RTO Expansion?

Although BHCOE has filed an application to join Markets+, it has not yet decided whether to participate in SPP’s day-ahead market or instead join SPP’s RTO Expansion (RTOE).

The utility has commissioned a study to evaluate the two options, with results expected in June or July.

“Even with approval of this application, BHCOE may pivot to the RTO path if the analysis demonstrates that it is the superior option for our customers.” Schlachter said.

Schlachter raised some concerns in her testimony about Markets+, noting PSCo’s acknowledgement of its limited transmission connectivity to other Markets+ balancing authorities.

“This restricted interconnectivity raises questions for BHCOE about whether Markets+ can deliver the full range of real-time dispatch efficiencies with neighboring systems,” she said. “It may also lead to less effective economic dispatch compared to a more interconnected day-ahead market with a broader footprint.”

Schlachter said CAISO’s Extended Day Ahead Market (EDAM) might provide greater connectivity potential for PSCo, with its ties to EDAM participants Public Service Company of New Mexico to the south and PacifiCorp to the north.

Another issue is SPP’s Western Energy Imbalance Service (WEIS), a real-time market that BHCOE joined in April 2023.

WEIS will end when SPP’s RTOE goes live, which is expected on April 1. From then until PSCo starts its Markets+ participation, expected in October 2027, PSCo and BHCOE will rely “only on bilateral arrangements and limited tools such as Real-time Dispatchable Transactions,” Schlachter said.

Two other Black Hills Energy subsidiaries — serving parts of Montana, Wyoming and South Dakota — announced in August 2024 that they would move from SPP’s WEIS to CAISO’s Western Energy Imbalance Market (WEIM). Some viewed the move as a symbolic victory in the ISO’s competition with SPP. (See CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS.)

Black Hills Energy operates natural gas and electric utilities in eight states: Arkansas, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming, in addition to Colorado.

Cost Recovery

BHCOE’s application outlines the expected cost of Markets+ participation that would be recovered through the energy cost adjustment. The costs were estimated by applying a load ratio to PSCo’s costs.

Costs include about $117,016 in fees from Phase 1 of market development. Phase 1, which BHCOE participated in, ended with approval of the Markets+ tariff.

Administrative fees for Phase 2 are expected to be $700,000/year for the first five years and $500,000/year thereafter.

Collateral obligations will include a $100,000 one-time share of PSCo’s Phase 2 funding obligations and roughly $12,000/year.

SPP will require Markets+ members to participate in the Western Power Pool’s Western Resource Adequacy Program (WRAP). BHCOE expects about $32,000 in WRAP entry fees and $135,000/year in participation fees.

Another $5 million to $10 million is expected in one-time costs for software and information technology upgrades, followed by $500,000 to $700,000 in annual costs.

Tri-State’s RTOE Participation Approved

BHCOE’s application comes just weeks after the Colorado PUC granted approval to Tri-State Generation and Transmission Association to participate in RTOE.

Tri-State CEO Duane Highley said previously that expansion of the SPP RTO would be “the most cost-effective pathway to organized market benefit for Tri-State’s members.”

Tri-State and six other Western utilities are preparing for full market integration in April. The SPP RTOE will include WEIS participants Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Platte River Power Authority and the Western Area Power Administration.

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Cold Weather Drives Record December Energy Costs in New England

Consistently cold weather drove record-high December energy market costs for ISO-NE and caused the region to rely heavily on stored oil and LNG injections.

“It was the coldest December, by our measurements, since December 2017,” averaging about 4.5 degrees below normal, Stephen George of ISO-NE told the NEPOOL Participants Committee on Jan. 8.

He said the region experienced its second-highest monthly energy market costs — and the highest recorded December energy costs — since ISO-NE Standard Market Design was implemented in 2003.

Based on data through Dec. 30, ISO-NE energy market value totaled about $1.8 billion in December, compared to about $1 billion in December 2024 and $718 million in November 2025.

December peak demand reached 19,477 MW, shy of last winter’s 19,631-MW peak and ISO-NE’s forecast 20,059-MW peak for the current winter, George said.

ISO-NE expects the region’s winter peak to grow by about 6 GW by 2034, driven by heating and transportation electrification. (See ISO-NE’s Final 10-year Demand Forecast Tapers Expectations.)

While the low temperatures caused the region to dip into stored fuels, there has been strong LNG and oil replenishment, George said.

Day-ahead ancillary service costs also spiked, with prices associated with day-ahead reserves and the Forecast Energy Requirement reaching their highest per-MW level since ISO-NE launched its new day-ahead market in March 2025. Consumer advocates in the region have said high costs associated with the RTO’s new day-ahead ancillary service products are a key area of concern in 2026. (See Costs of ISO-NE Day-ahead Ancillary Services Higher than Expected.)

Regarding the New England Clean Energy Connect (NECEC) transmission line, George said testing may continue over the next week as the project proceeds through its final review steps, with the line scheduled to come online officially by Jan. 16. (See NECEC Transmission Line Ready to Begin Commercial Operations.)

“There’s been a bit of export testing,” he said. “Even though the line itself isn’t permitted as an export facility … exporting is an important part of that testing process.”

ISO-NE data indicate New England exported about 1,200 MW over the line for about eight hours Jan. 7.

While the line’s export capabilities “could be, at some future time, utilized,” George said, “once it’s in service and fully operational, we don’t anticipate exporting at any point.”

The NECEC project includes 20-year supply contracts with Massachusetts electric distribution companies for baseload power from Québec, and it appears unlikely the line will be operated bidirectionally for the duration of these contracts. However, Hydro-Québec has expressed a long-term interest in increased bidirectional power exchanges with New England.

George also noted Vineyard Wind’s operational offshore wind turbines have continued to run following the Trump administration’s suspension of leases for all under-construction offshore wind facilities in the U.S. Vineyard Wind has reached operation capabilities up to 572 MW, while the Revolution Wind project was scheduled to start sending power in January. (See Offshore Wind Developers Fight to get Back in the Water.)

“We’ve observed continued operation of the offshore wind facilities that are fully built out and have frequently observed several hundred megawatts of offshore wind flowing into the New England system, and we anticipate that that will continue,” George said.

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Ontario OKs Underwater HVDC Line to Toronto

Ontario has approved IESO’s proposed $1.5 billion HVDC line under Lake Ontario, which planners say is needed to meet a potential doubling of Toronto’s electricity demand by 2050.

IESO recommended the 65-kilometer, 900-MW line in September, saying it would be more “future proof” than two cheaper options. (See Planners Pick $1.5B Underwater HVDC Line for Toronto’s ‘Third Supply’.)

IESO says Toronto’s electricity demand could increase 70 to 100% by 2044 due to new housing and commercial development, data centers and electrification of heating and transportation.

Electricity demand is expected to exceed the capacity of the two transmission lines currently supplying Toronto — from Manby Transmission Station (TS) west of the city and Leaside TS from the east — creating a “reliability need” by 2038. Closure of the 550-MW gas-fired Portlands Energy Centre (PEC) would create that need by 2034.

“Without a new transmission line, Toronto would have to turn down job-creating investments and reduce housing, which is simply unacceptable,” Minister of Energy and Mines Stephen Lecce said in a statement announcing the line’s approval.

The ministry said the new line between the Darlington transmission station and downtown Toronto also will support the province’s plans to refurbish the Darlington Nuclear Generating Station and build the first small modular reactors in the G7, the Darlington New Nuclear Project.

1st Competitive Transmission Procurement

The ministry said it will take seven to 10 years to design, construct and energize the line.

The government asked IESO to select the builder of the line through what would be the grid operator’s first competitive transmission procurement. In July, IESO opened enrollment in its Transmitter Selection Framework Registry, a prequalification mechanism for future procurements. (See IESO Removes Credit Requirement for Transmission Registry.)

The underwater line was one of three options planners considered for Toronto’s “Third Supply,” including an overland route from Cherrywood TS to Leaside TS in Toronto, estimated at $800 million, and a hybrid of overland and underground segments from Cherrywood TS to the Port Lands in Toronto, estimated at $900 million.

IESO said the underwater cable is “the most future proof” option, supporting forecasted demand beyond 2044.

The ministry said an underwater line also would be less vulnerable to flooding and ice storms that have resulted in outages and more than $100 million in costs and lost productivity. The line also would save $100 million to $300 million in bulk system reinforcements elsewhere in the Greater Toronto Area, the ministry said.

The HVDC line from Bowmanville to the Port Lands in downtown Toronto would require expansion of the Hearn station in the Port Lands.

Reaction

Toronto Mayor Olivia Chow lauded the approval of the new line. “Toronto is the fastest-growing city in North America, and that growth means we need more power to fuel our homes, transit and businesses,” she said.

Scott Andison, CEO of the Ontario Home Builders’ Association, said the new line is essential to addressing the region’s need for new housing. “Communities across Ontario are approaching real electricity capacity constraints, and without new transmission investments, the ability to deliver housing at scale will be compromised,” he said.

“By securing Toronto’s future as a global economic hub and creating good-paying jobs and opportunities for suppliers and service providers throughout Ontario, this initiative delivers benefits far beyond the city’s core,” said Stephanie Crilly, executive director of the Economic Developers Council of Ontario.

Some climate activists, however, have criticized IESO for not adequately considering non-wires alternatives to meet the city’s needs.

“It is premature to consider a third line which would further tie Toronto to a nuclear future,” wrote members of Toronto East Residents for Renewable Energy in September. “Before a decision is made by Toronto City Council, IESO or the province, there must be an evidence-based examination of ALL of Toronto’s options, including energy efficiency investments, commercial and institutional demand response, rooftop and parking lot solar generation, energy storage, and wind power.”

The group also called for consideration of an alternative third line that would bring power from an offshore wind farm.

The new line was included in IESO’s Integrated Regional Resource Plan (IRRP) for Toronto, which several environmental groups have criticized for ignoring Toronto City Council’s call for closing the Portlands Energy Centre by 2035 and achieving net-zero emissions by 2040.

“The IESO’s proposal takes the city in the opposite direction,” the groups, including Environmental Defence Canada and the Ontario Clean Air Alliance, said in November. “Instead of investing in local, renewable solutions such as energy efficiency, rooftop and community solar and offshore wind, the plan entrenches reliance on centralized gas and nuclear power, keeping Toronto tied to outdated, high-cost energy sources that delay real climate action and local job creation.”

In addition to the third line, the IRRP recommends battery energy storage systems and incremental electricity demand side management, including residential solar/storage systems. “With or without the supply contributions from PEC, meeting the significant need identified for eastern Toronto due to the significant forecasted growth requires a large-scale wires solution,” the ISO said.

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Illinois Gov. Pritzker Signs Storage and VPP Bill Aimed at Affordability

Illinois Gov. JB Pritzker (D) has signed the Clean and Reliable Grid Affordability Act, which seeks to expand virtual power plants (VPPs) and energy storage in the state.

“In Illinois, we are pursuing every available option to produce affordable, efficient, clean and abundant energy,” Pritzker said in a statement. “We are leaving no stone unturned in the work to produce more electricity, lower prices for our people and secure our long-term energy future.”

The CRGA aims to cut power bills while moving forward on the state’s clean energy vision, which continues despite the federal government abandoning clean energy policies, he added. The Illinois Power Agency (IPA) said the bill is expected to save customers about $13.4 billion in savings over two decades.

The bill requires a procurement of 3 GW of grid-scale battery storage by 2030, which will help meet the need for capacity and lower power bills. Illinois is home to 11 nuclear reactors, and the bill lifts a ban on building a new nuclear facility.

Another provision requires utilities to create programs for virtual power plants (VPPs) to allow homes and small businesses to get paid to harness smart thermostats, solar panels, distributed batteries and electric vehicle charging to help balance the grid.

The bill also requires that standard energy efficiency programs are expanded, which will come with new spending requirements for low-income customers while removing the formula rates utilities get for administering such programs. Utilities will be required to offer time-of-use pricing to allow residential customers to pay less for power outside of peak times.

The IPA has handled some planning since its creation almost 20 years ago, but the CRGA requires a new integrated resource planning (IRP) process. The new IRP will be run by the Illinois Commerce Commission and its staff with input from the IPA and other agencies.

The first plan for the state’s main utilities required under CRGA is due from ICC staff by Nov. 15, 2026, with the commission to vote on it later. The IRP process is to be repeated every four years after ICC staff files the second with a due date of Sept. 30, 2029.

CRGA makes other changes such as directing the IPA to propose long-term clean energy contract procurements and protects contracted renewables from inflation by tying the budget for the renewable portfolio standard to inflation.

The bill authorizes the ICC to accelerate any pending renewable projects so they can take advantage of expiring federal tax credits.

Pritzker’s office noted that since the passage of the Climate and Equitable Jobs Act in 2021, Illinois has supported more than 6 GW of renewables, with another 6 GW under development.

The American Clean Power Association welcomed the Illinois legislation, saying it offers a framework to expand storage and reduce price volatility in the process.

“CGRA is advancing smart, timely solutions,” ACP Senior Vice President for State Affairs Sarah Cottrell Propst said in a statement. “With new investments in energy storage and virtual power plants, Illinois is positioning itself to keep energy costs low, improve reliability, and create clean-energy and manufacturing jobs — proven strategies that benefit consumers and strengthen the economy.”

The CRGA makes Illinois the 13th state to set up a procurement target for battery storage, the Clean Energy States Alliance said in a statement. An analysis found that the storage could save customers $3 billion over the next 20 years.

“States across the country are increasingly using energy storage to support the transition to clean, reliable and affordable energy,” CESA Senior Project Director Todd Olinsky-Paul said. “Energy storage can reduce reliance on costly and polluting fossil fuel ‘peaker’ plants, integrate clean renewable power onto the grid, increase energy resilience, lower air emissions and support ratepayer affordability.”

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SPP Works to Augment Western Energy Transfers

SPP says it is pursuing inter-market optimization of energy transfers between its two Western Interconnection markets, mirroring a process it has developed in its existing RTO footprint.

Carrie Simpson, the grid operator’s vice president of markets, told Markets+ leadership and stakeholders Jan. 6 that staff are working on a solution that could provide an automatic, coordinated real-time market-clearing process that would initiate energy transfers between the two markets.

“There’s nothing like it that I’m aware of,” Simpson said during a conference call with the Interim Markets+ Independent Panel (IMIP). “It’s something that we’ve been researching and there’s different levels of it. It’s not going to be full blown intra-market optimization, but we see it as a helpful step forward that will help both Markets+ and the RTO footprint in the West.”

SPP published an analysis paper in 2025 on its study of a potential inter-market optimization (IMO) framework with MISO. The study found the more efficient use of the existing transmission system components and decreased production costs could reduce operating costs by about $20 million per year.

Simpson said SPP is targeting IMO’s deployment in the West in October 2028, one year after Markets+ is to begin operations.

The grid operator’s RTO expansion (RTOE) into the Western Interconnection is on track to go live April 1, 2026. When it does, Xcel Energy’s Public Service Company of Colorado, a Markets+ participant, will find itself surrounded by RTOE members.

Simpson said western utilities will have opportunities to import and export from the RTO, using dispatchable transactions and other methods to buy and sell. When Markets+ is live in 2027, both markets will be able to take import and exports “pursuant to their respective rules.”

SPP staff already have begun RTOE’s congestion-hedging process, Simpson said. When the market is fully operating, SPP’s current western imbalance market will cease operations and its members join the RTO or work toward other markets, “Like Markets+,” she said.

“It’s a really big deal that Markets+ and RTO Expansion are allowing economic dispatch of imports and exports at the borders,” said The Energy Authority’s Laura Trolese, who chairs the Markets+ Participant Executive Committee guiding the market’s development. “We are hoping that with CAISO and [its Extended Day-ahead Market], we can also get to a place where there can be economic, and not just fixed or self-scheduled, transactions. I think that’s an important aspect that will help allow those transfers to be optimized and more efficient.”

IMIP Approves Protocols, Tariff Revisions

During the call, the IMIP approved the first version of Markets+ protocols developed by stakeholders and SPP staff and approved by the MPEC in December. (See Markets+ Stakeholders Approve Baseline Protocols.)

The protocols’ first version will provide the operational framework needed to implement the market’s tariff and establish a baseline for implementation. Future refinements will be made through the normal stakeholder processes.

IMIP approved 32 tariff cleanup items recommended by MPEC. The revisions address minor grammatical updates, clarify defined terms and align language with the protocols to ensure consistency and readability. The revisions don’t modify the market design or operations.

The committee also approved four other revisions to the tariff, which were filed in 2024 and approved in early 2025:

    • Establishing how SPP recovers the administrative and implementation costs necessary to operate Markets+ after staff executed finalized Phase 2 funding agreements.
    • Updating boilerplate language outlining SPP’s responsibility to accurately calculate real-time balancing prices during system outages lasting more than 12 dispatch intervals.
    • Aligning the tariff with the protocols in calculating local prices and settlements using mitigated offers to ensure fair outcomes within the isolated area. Flexibility reserve products are not cleared in an island, preventing costs for services that cannot provide systemwide reliability value.
    • More definitively classifying when a market storage resource is self-charging in the day-ahead and real-time markets to settle any withdrawal that is considered self-charging as load.

Legal staff said the protocols and revisions will be filed with FERC within several months, once it’s determined there are no appeals to SPP’s Board of Directors. They will ask the commission for an effective date “well into the future.”

MSC Priorities for 2026

Arizona Commissioner Nick Myers, chair of the Markets+ State Commission, said western regulators want to ensure they’re as “educated and as informed as possible on all matters Markets+” as the market’s 2027 go-live date approaches.

It’s part of the MSC’s priority to have commissioners and staff continue to engage and collaborate with stakeholders as they build the market’s design and systems. Myers said the committee’s members will work with WEIB and SPP to host various educational sessions on tariff review, greenhouse gas accounting and other issues.

The MSC, composed of western state regulators, is increasing its staff capacity to maintain continuity as commissioners “come and go,” Myers said. He said this will compensate for regulators’ lack of experience with organized markets in the Western Interconnection.

“A lot of our commissions don’t have staff dedicated to do this kind of stuff and they don’t have any kind of foundation or backgrounds or anything like that,” Myers said. “We thought that it would be prudent to have some staff members that were able to come in and step in and maintain some continuity between those commissioners. Many of our staff have already kind of been following along, but this is a way to kind of get them more formally engaged.

The MSC will work with a larger budget in 2026 following IMIP’s approval of its $437,923 request. That’s a 12.4% increase from the 2025 budget of $389,680 that covered only the past nine months.

Attendance Capped for Seams Symposium

SPP staff said attendance has been capped and they are working off a wait list for its Feb. 26 Western Seams Symposium in Tempe, Ariz.

“So, packed house,” Simpson said. “It’s pretty exciting that there’s that much interest right now.”

She said the agenda is being developed but that the symposium will focus on education and the existing seams challenges in the West.

Markets+ stakeholders have developed a seams strategy and road map designed to identify focus areas for policies, and governing documents related to seams issues with neighboring areas. FERC in November 2025 published a policy paper urging SPP and CAISO to get ahead of seams issues before their western markets go live in 2026 and 2027. (See FERC Report Urges West to Address Looming Market Seams Issues.)

“SPP and Markets+ sees a vision of mitigating those seams, managing and making them better,” Simpson said.

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MISO Fields 50 Expedited Tx Project Requests, Recommends Several

Just days into 2026, MISO already has approved or recommended dozens of expedited transmission projects for the 2026 cycle, including a substation project in Indiana that spawned several hundred million dollars in corrective action upgrades.

The price tag of the five added reliability projects to support the single expedited transmission project left stakeholders with questions over who would pay for them.

Most of MISO’s Jan. 6 Expedited Project Review Technical Study Task Force teleconference focused on expedited projects in Indiana. MISO recently completed analysis and mitigation plans for 22 transmission projects to either support a cumulative 3.7 GW in load additions or bolster reliability. The RTO recommends those projects advance to its 2026 MISO Transmission Expansion Plan (MTEP 26) after the Planning Advisory Committee has a chance to review them.

MISO already approved another 26 expedited transmission project requests for its MTEP 26 cycle as of Dec. 31, 2025. The projects represent about 5 GW of spot load additions.

MISO reviews transmission projects on an expedited basis when it cannot wait until the usual, end-of-year MTEP approval. With expected load growth, expedited requests have trended upward. MISO has received 50 submissions under its expedited process since June 2025.

This crop’s project with the highest total is a new Antioch 345-kV substation which, combined with the handful of reliability projects it requires, would cost around $378 million.

The $68.8 million project from AES Indiana involves construction of a new 345-kV breaker-and-a-half substation in the greater Indianapolis area to serve 1.2 GW of new data center load.

MISO’s Dave Seelye said the new substation project requires five corrective action plans to maintain reliability: a $2 million uprate of a nearby autotransformer, nearly $12 million to restore a neglected autotransformer to service, a $30 million switchyard expansion and connection to the local 138-kV transmission system, a $15 million equipment replacement on the nearby Guion-Whitestown 345-kV line to increase winter ratings, and finally, a $250 million investment in 55 miles of new, double-circuited 345-kV line.

MISO said the $250 million baseline reliability project supplants several rebuilds in the area that otherwise would be required.

Senior Expansion Planning Engineer Amanda Schiro said MISO conducted several rounds of study to capture all the mitigations the Antioch project would require.

Stakeholders in attendance questioned MISO’s classification of the corrective action plans for load growth projects as necessary reliability projects.

Sustainable FERC Project’s Natalie McIntire asked whether MISO would allocate the costs of the corrective action plans according to its baseline reliability project cost allocation.

Costs of baseline reliability projects in MISO are allocated to the transmission pricing zone where they’re located and spread out according to a load distribution factor. Costs are recovered by the transmission owners developing the projects.

Schiro said MISO merely analyzed “the reliability needs based on the changes to the system” and discovered NERC transmission planning violations based on the expedited projects. She said MISO categorized the projects as baseline reliability projects based on their purpose and did not consider cost allocation in its review of expedited projects. Schiro said cost sharing of the corrective action plans likely would align with their project classification.

WEC Energy Group’s Chris Plante said if stakeholders have concerns about the cost allocation of corrective action plans, they should raise them at the Planning Advisory Committee, not at expedited review task force meetings.

“This is probably not the right forum to address those,” Plante said.

MISO’s next Planning Advisory Committee meeting is Jan. 21.

Beyond the Antioch project, Hoosier Energy plans a $75.3 million, 345-kV substation expansion and line project to serve nearly 1 GW in data center load expansion in southwest Indiana. Hoosier Energy’s project also requires a $2 million corrective action plan, with construction of an additional 345-kV circuit planned between substations to reliably accommodate the load.

Finally, MISO vouched for ITC Midwest’s plans for an $11.3 million transmission project relying on Duane Arnold Energy Center, the Iowa nuclear plant NextEra Energy hopes to restart in late 2028 or early 2029. Duane Arnold’s reconnection is included in MISO’s expedited queue lane.

ITC plans to expand a 161-kV bus to support four new radial 161-kV lines that would be owned and operated by Central Iowa Power Cooperative to serve a 620-MW load addition.

The Iowa load addition project also requires a $1.2 million corrective action plan to replace transmission structures to increase line ratings.

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BPA Presents Ideas for Updating Commercial Business Model

The Bonneville Power Administration outlined suggested modifications to its commercial business model (CBM) as the agency explores updating transmission processes.

The proposed changes were presented at a Jan. 6 workshop, which is part of a series of public meetings the agency is hosting under its Grid Access Transformation (GAT) project.

BPA paused certain planning processes and launched the GAT program in 2025 to consider changes following a surge of transmission service requests (TSRs). The federal power agency’s 2025 transmission cluster study includes more than 65 GW of requests, compared with 5.9 GW in 2021. The requests exceed the total regional load forecast for the Pacific Northwest in 2034, according to the agency. (See Utilities Back Some BPA Transmission Updates, Hesitate on Others.)

“The commercial business model will essentially become the path forward for commercial customers to receive firm power service when we don’t have the capacity currently available to meet that customer’s need,” BPA spokesperson Kevin Wingert told RTO Insider in an email. “The CBM will outline the process by which we identify necessary transmission upgrades in the system in collaboration with the commercial customer(s) to be able to offer firm service.”

The CBM needs to be updated because of “significant shifts” in the industry, Lauren Nichols-Kinas, public utility specialist in BPA’s Transmission Commercial Planning team, said at the workshop.

“It’s seeming pretty logical that we need to re-examine our commercial business model and assess what’s working well and what possibly needs to be shifted a little bit to make it fit better with the things we’ve learned and the changes that are happening within the Northwest footprint,” Nichols-Kinas said.

By updating the CBM, BPA hopes to achieve six objectives, according to presentation slides:

    • Ensure all TSRs remaining in the queue are “studiable,” meaning BPA has enough information to launch a study.
    • Achieve a “studiable” queue volume and process.
    • Balance causation and socialized cost.
    • Appropriately allocate risks associated with transmission expansion, including financial and modeling risks.
    • Support BPA’s mission regarding commercial transmission expansion.
    • Fairly allocate scarce system capability.

The size of the queue affects the agency’s ability to accept uncertainty or incomplete information from requests during the studies and planning phase, according to Chris Gilbert, BPA public utility specialist.

“When the queue was 3.8 [GW] one year and 3.6 the next, we could take a lot more uncertainty,” Gilbert said. “When the queue went to 11 and 17, that ability to take some uncertainty within the data of the request decreases. Because … if you study 17 GW with a lot of incomplete data, we’re going to get power flow results that are the wrong projects in the wrong location. They’re not sized right, they’re not the right ones … we can’t do that to the region. We’ve got to narrow that down.”

‘Higher Bar’

Staff presented a matrix during the workshop, outlining potential areas for adjustment.

Nichols-Kinas noted the options presented in the matrix are initial ideas, saying BPA “does not have a preferred option in terms of changes to the business model.” Any modifications need to “be heavily informed by a regional conversation,” she added.

The matrix left some areas unchanged, like the $10,000 point-to-point TSR processing fee. But the cost of participating in a commercial study could increase, Nichols-Kinas said.

Developers pay around $150 to $200/MW of a potential project to participate in cost studies. If BPA spends less money than collected on the study, the agency issues a refund at the end of the study, Nichols-Kinas noted.

Going forward, BPA could “add an element of a nonrefundable flat per-TSR fee somewhere in the range of $10,000 to $100,000” to collect the full cost of what the agency spends on conducting the studies, she said.

“Having an upfront fee that makes sure that we’re covering those costs, and that provides conceivably a higher bar to entry, maybe makes sense at this juncture,” Nichols-Kinas added.

Staff emphasized that BPA is seeking feedback on whether “this is a healthy way to manage the size of the queue and risk mitigation.”

Other ideas include adopting longer minimum-term service contracts and changing how costs associated with preliminary engineering agreements and environmental studies are handled.

Seattle City Light’s Michael Watkins said the utility would support longer transmission contracts “as a way to securitize projects.”

“Having longer transmission service requirements could be used in other aspects that you’re looking at as a mechanism for gauging seriousness of requests, or as a requirement for granting interim service,” Watkins said. “This could apply to several aspects that we’ve talked about today.”