Search
January 13, 2026

Posted on

NYISO Stakeholders Request Cluster Study Enhancements

The NYISO Transmission Planning Advisory Subcommittee (TPAS) discussed stakeholder comments on possible improvements to the cluster study process and the system deliverability test process in response to presentations given in December 2025.

Stakeholders including the Alliance for Clean Energy New York and Granite Source Power asked for improvements to the pre-application process and increased training for interconnection customers. ACE NY asked for clarification to NYISO’s definition of “physical infeasibility” and for more information to be given to interconnection customers once a project is deemed infeasible. The organization asked NYISO to require that transmission owners provide interconnection customers with the studies that determined whether a project is infeasible.

GSP asked for greater standardization between transmission owners regarding site plan requirements and agreed with ACE NY that the physical infeasibility screening needed clarification.

RWE Clean Energy asked for a fast-track interconnection process for projects addressing reliability issues. Invenergy asked for an expedited capacity resource interconnection study mechanism for interconnection of co-located energy storage resources.

NYISO staff said in an earlier presentation that managing the reliability impact of the 70 GW of new generation in the queue requires numerous upgrades. The ISO previously stated that the first cluster study — the “transition cluster study” — had posed challenges to staff including many iterations of deficiency reviews due to inconsistent and inaccurate interconnection requests. The deficiencies led to withdrawals, which led to dispute resolution processes and model updates. The large volume of projects in the cluster study also poses significant challenges for validating interconnection requests and performing required evaluations on time.

The ISO presentation indicated it also wanted to pursue increased training for interconnection customers, simplify paperwork for interconnection requests and clarify the deficiency process.

Deliverability Test Recommendations

The deliverability test is a critical part of the interconnection process, which helps determine if a project is deliverable at its requested “capacity resource integration service” level, measured in megawatts. If a project cannot deliver, NYISO looks for system deliverability upgrades — upgrades to the grid — that would allow the project to function at its requested megawatt value and determines costs to the resource.

NYISO identified challenges with the deliverability test, particularly the establishment of a base case and unforced capacity factor assumptions in late 2025. Stakeholders submitted comments for discussion at the Jan. 5 TPAS meeting.

ACE NY asked for clarification of the implementation schedule of the updates to the deliverability test, citing possible confusion over when the new test would be in place. It added there was a risk of confusion with system deliverability upgrade cost estimates and asked NYISO to issue two separate ones based on the proposed new rules and the old rules.

The Market Monitoring Unit issued a memorandum in response to NYISO’s move to reform the deliverability test. The MMU has long argued that the current test penalizes new resources and is poorly suited to new technologies seeking to interconnect, specifically storage resources. The MMU asked NYISO to consider creating more capacity zones, reflect import bottlenecks in capacity accreditation factors and remove “highways deliverability test” from the cluster study.

Tony Abate, representing the New York Power Authority, said he didn’t think the MMU’s suggestions were possible to implement while the ISO is trying to reform the cluster study process. He said he appreciated the MMU’s “aspirational” stance but didn’t think new capacity zones could be delivered simultaneously with the other reforms.

Thinh Nguyen, senior manager of interconnection projects for NYISO, said the ISO is still in the process of reviewing comments and would get back to stakeholders at a future meeting.

In Other Business

TPAS heard system impact study scopes for two data center projects, both being developed by Turn Management in Herkimer County. Collectively, the two data center loads would be 500 MW on the same site. TPAS did not issue any objections and allowed both SIS scopes to move forward for Operating Committee consideration.

Posted on

MISO Picks AEP, Berkshire’s Joint Venture to Build $1.2B 765-kV Line

MISO has selected a 50/50 joint venture between Transource and Berkshire Hathaway Energy Transmission to build a $1.2 billion, 765-kV project from the RTO’s second long-range transmission portfolio.

MISO opted for the jointly owned Midcontinent Grid Solutions to build the nearly 200-mile Bell Center-Columbia–Sugar Creek–IL/WI State Line (BECI) 765-kV competitive transmission project.

“Transource demonstrated the most 765-kV capabilities of all developers, and it will partner with a strong contractor to operate and maintain the project after it is complete,” MISO said in its Jan. 6 selection report. The companies’ joint enterprise outperformed four other unnamed bidders, according to MISO.

It said Midcontinent Grid Solutions “demonstrated reasonable cost estimates and offered reasonable cost containment,” though it didn’t propose the lowest revenue requirement, which ranged from $533 million to a little more than $1 billion among bidders. Midcontinent Grid Solutions pinned its revenue requirement between $775 million and $790 million.

BECI is part of MISO’s second, $22 billion long-range transmission plan portfolio, approved by the MISO Board of Directors at the end of 2024. Most of the portfolio is composed of 765-kV projects.

BECI facility map | MISO

Midcontinent Grid Solutions pledged to cap its annual revenues through the end of the 14th year of the project’s existence at its estimates. It said it would not recover any revenue beyond its caps unless it was necessary for the company to earn a minimum 8.5% return on equity.

Estimated capital costs among the bidders varied from $808 million to $1.29 billion. Midcontinent’s winning bid predicted it would need a little more than $1 billion. MISO estimated the project would cost $1.2 billion.

American Electric Power 86.5% of Transource; Evergy owns the remaining 13.5%. To date, AEP has constructed and operates more than 2,000 miles of 765-kV lines.

MISO’s selection focused on developers’ design integrity and plans for maintenance once the lines are in service, design flexibility, ability to coordinate with other interconnecting transmission owners, and capability to finance and manage a large project.

MISO said Midcontinent Grid Solutions’ guyed, y-shaped lattice designs were the lightest structures put forward for consideration. The grid operator noted that lighter structures make helicopter installation easier while still designed to withstand a 300-year mean recurrence interval weather event. MISO noted that the company plans to keep at least 22 of the 765-kV structures on hand to make major repairs if necessary.

However, MISO said a weak point in Midcontinent’s proposal may lie in is its plan for sourcing construction materials and its routing. The RTO said the company’s “planned procurement responsibilities are less clear than other developers,” and its plan “demonstrates less certainty than other developers regarding its planned vendors and suppliers by not providing any letters of support and instead discussing supplier relationships, forecasted demand and capacity reservations which show that there is sufficient production capacity for BECI.”

MISO similarly said the company’s routing lacked specificity and was silent on whether it would route in accordance with Wisconsin’s siting priorities. It also didn’t appear to fully flesh out the complexities of siting near wetlands, forested areas and an airport, MISO said.

Transource said it has yet to draw a final route for the project.

MISO expects the line to be in service by June 1, 2034, pending regulatory approval.

Relatedly, MISO announced it would rely on Chicago-based Viridon Midcontinent to build a 345-kV project, also stemming from the second long-range portfolio. The smaller, $350 million project will span about 105 miles in southeast Wisconsin. MISO expects the line to be energized by June 1, 2033.

Blackstone Energy Transition Partners, one of Blackstone’s private equity funds, owns Viridon.

MISO said it’s concerned Viridon may have underestimated the capital costs of the project in its bid. Three other bidders estimated the project would cost anywhere from $471 million to $481 million; MISO itself estimated the project would cost $662 million to complete.

However, MISO said its confidence in its selected developer was buoyed by the fact that Viridon already executed an agreement with an experienced general contractor and proposed “cost containment strong enough to likely ensure the lowest cost to the ratepayer even if its estimated costs rose significantly.”

Posted on

NYISO Presents Final LCRs for 2026/27

NYISO has presented the final locational minimum installed capacity requirements for the 2026/27 capability year. The LCRs, expressed as a percentage of peak load forecast, represent the minimum capacity that generators and load-serving entities must maintain within the downstate zones. These zones have substantial transmission constraints.

Based on the 24.5% installed reserve margin set by the New York State Reliability Council, NYISO determined the minimum LCR for New York City, Long Island and the Lower Hudson Valley to be 86.4%, 110.3% and 82.5% respectively, assuming the Champlain Hudson Power Express is online. If CHPE is not online, NYC would have an LCR of 82.6%. The other zones’ LCRs remained unchanged.

2026/27 Informational Capacity Accreditation Factors

At the Jan. 6 Installed Capacity Working Group meeting, NYISO also presented capacity accreditation factors for the upcoming capability year for stakeholder informational purposes. These are not the final CAFs that will determine the market revenue of suppliers for the capability year. Final CAFs are due March 1.

Unlike in previous years, NYISO included two sets of informational CAFs, one calculated with CHPE in and one without. The largest shift in informational CAFs occurs in the “non-firm” resource class. These are fossil fuel resources without contractual commitments from fuel suppliers. If CHPE is included in non-firm, generators are rated at 55.32% and 58.99% in the New York City suburbs and New York City respectively. If CHPE does not come in, these values climb to 84.67% and 85.77% respectively. The full table of results can be found here.

NYISO said CHPE’s impact on non-firm generator informational CAFs was driven by increased loss of load expectation events between the CHPE-in and CHPE-out scenarios. CHPE is modeled as a summer-only resource, so when CHPE is “in” it increases winter risk by being assumed to be unavailable. Non-firm generators have opted not to declare that they have secured fuel for the winter capability period, which means they are worth less in situations where winter risk is elevated.

Posted on

PJM Presents First Look at Co-located Load Compliance Filings

PJM presented stakeholders with an initial look into the first of a handful of FERC compliance filings it is drafting to define how co-located large loads receive transmission service (EL25-49).

The first compliance filing, which is due by Jan. 20, will focus on the most straightforward directives FERC included in its order: revising the tariff to explain how developers seeking to pair large loads with dedicated supply can receive provisional interconnection service, specify how resources may interconnect to provide less than its nameplate rating to PJM, accelerate interconnection and use surplus interconnection service to bring resources online faster.

PJM is required to submit an informational report on the proposals in the Critical Issue Fast Path (CIFP) process focused on large-load interconnections. The commission specifically asked for details on proposals to expedite generation interconnection, changes to the reliability backstop that could allow it to respond to resource adequacy shortfalls, and changes to PJM’s load forecasting and demand flexibility rules.

PJM Associate General Counsel Mark Stanisz said PJM intends to keep the tariff language it is developing under the compliance filing aligned with the market design proposals the Board of Managers is considering under the CIFP process. He presented the proposal to a Co-Located Load Order Workshop on Jan. 9.

“There’s a lot in the air, but we are monitoring it all and are trying to proceed in a coherent way,” he said.

New resources intended to exclusively serve co-located load would be permitted to skip to the final agreement negotiation phase of the interconnection process if it is determined no network upgrades would be required.

PJM Vice President of Planning Jason Connell said new resources would be able to sidestep the interconnection queue only if they would be unable to inject energy into PJM’s grid, such as by tripping offline if the customer they were serving was interrupted. He compared the interconnection of co-located generation to the RTO’s rules for behind-the-meter generation (BTMG), which are not required to go through the queue. Projects already in the queue would not be able to use the new pathways.

New resources that do require network upgrades could use provisional interconnection service to begin partial operations serving the co-located load while those upgrades are under construction.

Developers of co-located resources would be permitted to provide less than the full nameplate to PJM but would be limited to reducing its interconnection service only by the amount needed to serve the paired customer.

Stanisz said the first round of directives the commission gave is more prescriptive than the rest of the order and PJM is looking at governing document language it needs to modify. Staff are reviewing draft tariff changes with the intention of posting language within a few workdays. The first compliance filing may include a definition of co-location — a change the commission requested but did not specify which compliance filing it should be included in.

Manager of Stakeholder Process and Engagement Michele Greening said a survey will be posted along with the proposed tariff revisions to solicit stakeholder feedback.

“It’s all in the spirit of clarification and frankly in the most surgical of ways,” Stanisz said of the directive for the initial filing.

In the second compliance filing, due Feb. 17, PJM is tasked with adding three new forms of transmission service that can be used to serve co-located load, requiring the customers be charged for regulation and black start service based on their gross load, clarifying how the network upgrades required to serve co-locations will be studied, and requiring that existing interconnection customers pay for those upgrades. The filing is due by Feb. 17.

Stanisz said the commission’s order did not comprehensively address many of the jurisdictional issues around the interconnection of large loads and how they receive grid service. The commission’s assertion of jurisdiction over generation interconnections is not novel or trailblazing, so unanswered questions about its jurisdiction over large load interconnections are more likely to be addressed in the advanced notice of proposed rulemaking (ANOPR) on large load interconnections.

Asked if PJM is considering requesting a rehearsing, extension or clarification of the order, Stanisz said staff are focused on preparing the deliverable compliance directives the commission has requested. While other entities might seek such relief, and PJM would review those requests, at this time he is not aware of any intent for the RTO to make such filings.

Posted on

GOP Senator Introduces Bill to Let Large Loads Set up Consumer Regulated Utilities

U.S. Sen. Tom Cotton (R-Ark.) has introduced the Decentralized Access to Technology Alternatives Act of 2026, which would let large customers like data centers set up their own private power grids that are exempt from economic regulation.

Large customers would be responsible for the grids, which could not connect to the bulk power system at all.

“American dominance in artificial intelligence and other crucial emerging industries should not come at the expense of Arkansans paying higher energy costs,” Cotton said in a statement. “My bill will ensure that America can continue to lead in these spaces by eliminating outdated regulations.”

The bill authorizes the establishment of “consumer-regulated electric utilities” (CREUs) that are made up of an electric generation and supply system that is established exclusively for new electric loads that were not previously served by any retail electric suppliers. CREUs would be allowed to build generation, energy storage, transmission and distribution subject to the condition that they are islanded from all regulated utilities and the broader grid, and that they operate independently of any public utilities.

The rule even applies to ERCOT because it exempts any CREUs there from the application of the Federal Power Act’s mandatory reliability standards that apply to the Texas grid.

CREUs around the country would be exempt from the FPA and any regulation by FERC, or the Department of Energy. The law also exempts the new utilities from the Public Utility Regulatory Policies Act of 1978 and the Public Utility Holding Company Act of 2005.

The exemptions from federal economic regulation would be lifted if a CREU decided to connect to the bulk power system, or any electric transmission and distribution system, for primary or back-up power.

To submit a commentary on this topic, email forum@rtoinsider.com.

Cato Institute Director of Energy and Environmental Policy Studies Travis Fisher has been a proponent of CREUs for some time and said in an interview with RTO Insider that the construct also likely needs state legislation to become a reality. Cotton’s bill would ensure the FPA and its regime, under Section 215, of mandatory reliability standards does not apply to the islanded “utilities.”

“A lot of industrial consumers try really hard to minimize the amount of their system that falls under the bulk power system, because then you become a NERC registered entity, that brings in all sorts of compliance costs and headaches. So, I think it makes perfect sense that an islanded system wouldn’t be part of the bulk power system, but under a plain reading of Section 215, it’s not clear that that would be the case.”

Alternatively, federal legislation could just exempt CREUs from the mandatory reliability standards. Cotton’s bill would ensure they face no other complications from federal economic regulations, he added.

“I think you would need a state law to exempt a CREU from state jurisdiction, and you would need a federal law to exempt, in theory, from federal rules,” Fisher said. “So basically, you need both. I think there’s going to be a lot of people who choose the island even without the federal law, but I can’t imagine seeing people choose an island without the state law.”

New Hampshire, Ohio, Oklahoma and Utah have passed laws that allow CREUs. The American Legislative Exchange Council has a model bill for other states, he added.

CREUs are similar to longstanding industry concepts like co-generation, microgrids, co-located generation or the newer term of art — energy parks. But they must be islanded from the grid entirely, which is not necessarily the case for those other concepts.

“As soon as you connect to the grid, you can’t really plausibly claim that you shouldn’t be regulated because there’s all sorts of concerns about how you might cause faults on the grid or shift costs,” Fisher said.

The movement behind CREUs is driven by the desire to meet the demand of new large loads. Fisher said it’s a better idea than turning back the clock on restructuring and going back to the “Southern Co. approach.”

“The thing that’s different is there are really large new customers who need to move fast, and are willing to spend a lot,” Fisher said.

Data center developers and other large loads can support expensive generation like nuclear, or renewables, without any chance of spreading costs to others, he added.

Fisher said the way the industry has restructured in ISO/RTO markets and in competitive states is not real competition, with CREUs going even further. Some supporters of restructured markets support CREUs, with the R Street Institute raising Utah’s score on its competition report card after the state passed its law. (See R Street Scorecard Ranks All 50 States on Electric Competition Policies.)

While the CREU concept would exempt large loads and related power infrastructure from economic regulation, any power plants still would need relevant environmental approvals, Fisher said. Building major facilities with their own generation can avoid issues around exacerbating pollution in populated areas under EPA’s rules for National Ambient Air Quality Standards, nitrogen oxide and sulfur dioxide.

“It doesn’t have to be near population,” Fisher said. “If you’re using solar and batteries, you can put it wherever the sun shines. So that’s the advantage that there’s some flexibility in siting, so that might help with the NAAQS issues, the NOx, SOx — all that stuff. It doesn’t directly get you off the hook from those regs, though.”

Posted on

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 [and] can raise capital to move forward with these projects and ultimately add more energy capacity to the grid.”

Posted on

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+.)

Posted on

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.

To submit a commentary on this topic, email forum@rtoinsider.com.

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.

Posted on

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.

Posted on

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.