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January 12, 2026

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UCS: Climate Change Induced Worst MISO Outages of the Decade

The Union of Concerned Scientists said MISO’s most devastating power outages in the past decade can be attributed to an increasingly unstable climate and compounding weather events.

UCS published a new analysis naming climate change as the culprit behind the 10 most severe blackouts in the footprint since 2014. The nonprofit science advocacy organization said all of the 10 largest power outage events over the decade have occurred since 2020, with half occurring in 2020 itself. UCS said each incident in the top 10 lasted multiple days and was associated with “compound weather events occurring over a large geographic region.”

UCS defined the worst power outages as the “greatest number of customers without power on a single day.” Outages varied from 800,000 to 1.6 million customers without power across the MISO footprint.

UCS said MISO and its membership should be girding the grid to withstand extreme weather and warned that a lack of preparedness will spell more outages for more customers.

Across MISO, top spots were claimed by derechos across the Midwest: two in 2020 and one in 2021. On June 11, 2020, the remnants of Tropical Storm Cristobal joined with a low-pressure system over the Great Lakes to produce maximum 75 mph wind gusts and several tornadoes. Two months later, another derecho that wrought $11 billion in damage cut power to parts of South Dakota, Nebraska, Iowa, Illinois, Wisconsin, Indiana, Michigan and Ohio. This time, winds reached 100 mph, and the storm spawned 26 weak tornadoes.

Days later, MISO’s Gulf of Mexico weathered Hurricane Laura on Aug. 27, 2020, which made landfall as a Category 4 in coastal Louisiana. Extensive flooding and wind damage in coastal Louisiana and Texas accounted for much of the hurricane’s $19 billion in damage.

Weeks later, Hurricanes Delta and Zeta followed on Oct. 10, 2020, and Oct. 29, 2020, respectively. The two followed an almost identical point of entry in Louisiana. Delta spawned far-flung tornadoes and brought more flooding to already inundated drainage systems in eastern Texas, southern and central Louisiana, and portions of Mississippi and Arkansas. It caused $2.9 billion in damage. Zeta’s higher winds caused $3.9 billion in damage to the grid.

“In the 10 worst outage events reviewed, it is never merely a severe thunderstorm or a hurricane alone that leads to these extensive outages. Rather, it is a derecho with multiple tornadoes and wildfires. Or it is a hurricane with tornadoes, coastal and inland flooding, follow-on fires, and extreme heat or damaged industrial facilities causing the accidental release of toxins,” UCS wrote in the new analysis.

The group noted that nearly all the most acute outages were linked to high winds, though floods, fire and ice also damaged the system.

“Where high winds dominate, damage to the grid results either from trees falling on power and transmission lines or from winds directly bringing down poles and lines,” UCS wrote. The nonprofit said repair and replacement of wind-damaged lines “may be among the biggest factors driving recent increases in electricity prices,” a little-reported detail.

Outages following summertime derechos in 2020 and 2021 | UCS

“Sequential storms like back-to-back Hurricanes Laura, Delta and Zeta in 2020 pose another type of challenge, leaving hardly any time for communities to recover between events,” UCS wrote. “As grid-damaging storms occur more frequently, areas that have experienced damages have little time to rebuild before the next extreme event and therefore are more vulnerable to deeper losses. … This means that people’s homes have been covered only by tarps, not solid, new roofs; water-damaged structures have not yet dried out; and dunes have not re-formed, allowing coastal surges to reach deeper inland.”

UCS said the repeated bouts of severe weather mean poles and power lines have barely been stood back up or restrung when they’re vulnerable to severe weather again.

In early August 2021, another derecho targeted the MISO footprint, this time bringing hurricane-force winds and flash flooding to a nearly 800-mile stretch from southeastern South Dakota and northeastern Nebraska through Iowa and on to northern Illinois, southern Wisconsin, northern Indiana, southern Michigan and western Ohio. The long line of thunderstorms caused an estimated $11.5 billion in destruction.

By the end of August 2021, Hurricane Ida — another Category 4 — followed a familiar path up Louisiana, generated at least 35 tornadoes and caused $75 billion in damage ($55 billion in Louisiana alone). Individual power outages lasted for more than a month in some cases, and some of the nearly 90 deaths attributable to the storm were due to a lack of air conditioning.

To round out 2021, on Dec. 16, uncharacteristic thunderstorms targeted Minnesota, Iowa and Nebraska with high winds. Minnesota reportedly logged its first-ever tornado in December.

UCS completed its list with severe thunderstorms that formed across southern Michigan in late August 2022 and a punishing, dayslong winter storm in late February 2023 that delivered ice, wind and heavy snow across several states.

“Extreme weather events can no longer be shrugged away as acts of God or system anomalies that we have no power to foresee or plan for,” report lead author Rachel Licker said in a press release. “Many parts of the central United States are projected to experience increases in severe thunderstorms, including derechos and hailstorms, and greater rainfall from hurricanes that make landfall. Some parts of the region may see more intense snowstorms, as well. Policymakers need to increase the electricity grid’s resilience to worsening climate change-fueled extreme weather or people will lose electricity, heat and air conditioning when they need it most. Failure to act is negligence that some could pay for with their lives.”

Report co-author Susanne Moser said it’s clear extreme storms supercharged by a warming climate are driving serious outages.

“As grid-damaging storms occur more frequently, areas directly affected have little time to rebuild before the next extreme weather event and end up spiraling into deeper and deeper vulnerability. Understanding the risks this poses for the electricity grid — and investing in the grid to mitigate those risks — is a question of safety for people and their families,” Moser said.

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Canada’s Emission Reductions Dependent on Fixing Industrial Carbon Markets

After scrapping most Trudeau-era climate policies, Prime Minister Mark Carney hopes to tighten rules over Canada’s industrial carbon markets, which observers say have failed to incentivize emission reductions.

Since replacing Justin Trudeau in March 2025, Carney has eliminated a controversial carbon tax on consumer fuels, suspended a requirement that electric vehicles make up an increasing share of car sales and backed off on a phaseout of gas-fired generating plants.

As a result, the nation’s emissions trajectory is largely dependent on industrial carbon markets created under federal legislation in 2018 and now the subject of a scheduled review.

The Ministry of Environment and Climate Change in December issued a discussion paper seeking feedback on the federal “benchmark” — the national stringency standard all provincial and territorial systems must meet — which covers more than one-third of Canada’s total emissions, including the oil and gas industry and electric generation.

The government said its engagement seeks to ensure that industrial pricing “provides the necessary incentives and framework to drive decarbonization, clean technology investment and competitiveness.” Comments are due Jan. 30 via email to tarificationducarbone-carbonpricing@ec.gc.ca.

Alberta Agreement

The discussion paper acknowledges complaints by industry that the existing system is inefficient and is hurting their competitiveness. It also follows Carney’s Nov. 27 Memorandum of Understanding with Alberta Premier Danielle Smith, in which the federal government made numerous climate concessions, including the suspension of federal Clean Electricity Regulations, which would have required provinces to start phasing out gas-powered generating plants lacking carbon capture in 2035.

Although the electricity rules are being lifted only in Alberta — the nation’s largest greenhouse gas emitter — it “surely opens the door to doing likewise for other provinces that have chafed at it,” wrote Globe and Mail columnist Adam Radwanski.

The concessions prompted Steven Guilbeault — formerly Trudeau’s environment minister — to resign from Carney’s Liberal cabinet. But some climate activists said they were cheered by Alberta’s agreement to work with the federal government to raise the price of credits in the province’s oversupplied industrial carbon market — now trading below $20/metric ton (Mt) — to a “headline” price of $130/Mt.

Facilities with compliance obligations must pay the headline price or submit credits. A $130/Mt headline price would create incentives for heavy emitters to invest in climate capture and other green technologies, said Michael Bernstein, CEO of climate policy group Clean Prosperity.

“This agreement is a sign that we could finally be moving beyond the long-running disagreements between Ottawa and the provinces over climate policy, and charting a pragmatic path to achieve our climate goals while also strengthening Canada’s economy,” he said.

Provinces Falling Short

Seven of Canada’s provinces, including Alberta and Ontario, use provincial output-based pricing systems (OBPS), while four use a similar federal system.

OBPS set performance standards defined as emissions per unit of production. Companies whose production is better than the standard generate credits they can sell; those that cannot meet the standard either buy credits or pay the headline carbon price on excess emissions.

Designed correctly, says the Canadian Climate Institute, such systems can incentivize emission reductions with low overall costs and little incentive to shift production to jurisdictions without carbon limits.

But the institute and others say some current markets are not working because they are oversupplied with credits. While the 2025 headline price was $95/Mt — scheduled to rise to $170/Mt in 2030 — emitters can purchase credits at a fraction of that cost in Alberta and elsewhere.

Clear Blue Markets, which provides consulting and market research on carbon markets, said provincial markets are falling short, citing a lack of price transparency, Alberta’s freeze on its carbon price and oversupply risks in British Columbia and Quebec.

Alberta’s freezing of its headline price and its surplus of 48 million credits have pushed trading prices to about $18/Mt, the consulting firm said in late November. Prices in federal OBPS, including Manitoba and Prince Edward Island, have been depressed to $37.50 by the inflow of cheap “offsets” from Alberta, it said.

“Ontario’s [Emissions Performance Standards program] remains robust, supporting a strong credit market. However, its 2024 funding mechanism, tying proceeds to emissions paid rather than performance, may weaken the emissions reduction signal,” Clear Blue Markets said.

Climate advocates say the program also needs a financial mechanism to establish a price floor on credits, as would be established at $130/Mt under the MOU with Alberta.

“To turn this MOU into shovels in the ground, that financial mechanism should take the form of carbon contracts for difference offered jointly by the federal and Alberta governments,” Bernstein said. “These contracts are the insurance policy that will de-risk tens of billions in low-carbon investment by giving investors confidence in the durability of industrial carbon pricing.”

“If governments uphold their commitments to strong carbon markets, the contracts need never be exercised, and so cost nothing to taxpayers,” Clean Prosperity said.

Industry Complaints

In 2024, industry organizations including Canadian Manufacturers & Exporters, the Canadian Renewable Energy Association, the Canadian Steel Producers Association, the Cement Association of Canada and the Chemistry Industry Association of Canada sent an open letter to Canada’s provincial environment ministers complaining of a “disconnect” among the nation’s provincial and territorial carbon markets that they said was hurting economic growth and decarbonization.

The group said it supports industrial carbon markets as “the most flexible and cost-effective way to incentivize industry to systematically reduce emissions.”

But it said “a patchwork of provincial carbon pricing systems has produced numerous barriers and created significant red tape across efforts to decarbonize.”

The group called for more transparency in credit markets and for removing rules that prevent industry from buying and selling carbon credits across provincial borders.

It also asked for “high-integrity offset protocols” to ensure emissions reductions are “permanent, additional and verifiable” and that provinces should invest 100% of industrial carbon pricing revenues into industry to accelerate decarbonization.

It also sought actions to support vulnerable sectors and prevent carbon leakage to jurisdictions with less stringent climate policies, citing the EU’s Carbon Border Adjustment Mechanism, a tariff on imports of carbon-intensive products such as steel, cement and electricity.

Costs

In a 2023 study on the impact of the carbon pricing on Ontario, the Canadian Energy Centre predicted it would increase costs almost 11.8% for the province’s electric generation, transmission and distribution sector.

The study said carbon pricing would fall most heavily on the province’s iron and steel manufacturing sector — with a 62% increase — due to its use of coke and coal. Basic chemicals, pesticides and fertilizers were projected to jump 29.5%.

“The carbon tax will have the most significant impact on those industries in the manufacturing sector that have a high trade exposure and a low profit margin,” said CEC. The group’s goal is to make Canada “the supplier of choice for the world’s growing demand for responsibly produced energy.”

Three Options

Existing mandatory carbon pricing systems are believed to cover 595 facilities and 252 Mt of CO2 annually (36% of Canada’s emissions). Including voluntary facilities, existing carbon pricing systems are estimated to cover 274-281 Mt of emissions (39-40%).

The ministry said it is considering three options for determining what emitters will be covered by carbon regulations: The “threshold-based” option would cover all industrial and manufacturing facilities emitting above 10,000 (Option 1A) or 25,000 Mt (Option 1B) annually (264-273 Mt; 38-39%).

Option 2, an “activity-based” approach, seeks to cover all facilities in an industry to avoid providing a competitive advantage to smaller facilities. The ministry proposed covering oil and gas, mining, chemicals, fertilizers and other manufacturing — including steel and cement — that emit at least 10,000 Mt annually (278 Mt; 40%).

Option 3, which combines the threshold- and activity-based approaches, would be the “most effective” at incentivizing emission reductions, the ministry said (284 Mt; 41%.)

All three options would apply to fossil-fueled electric generation.

The government’s engagement to improve carbon markets design and price signals means that “meeting the federal benchmark will increasingly require jurisdictions to demonstrate that their systems function as effective markets and not simply that they comply on paper,” said Sussex Capital. “While provinces and territories will retain flexibility over design, the federal government is signaling higher expectations around durable price signals, healthy credit markets and demonstrable investment impacts.”

The MOU requires Alberta and the federal government to reach an agreement on the $130/Mt price by April 1.

“How this shakes out could determine whether an agreement to work together on policy and potential pipeline approval scuppers Canadian climate action, or whether it evolves into a better, more broadly supported effort to combat global warming,” wrote the Toronto Star’s Alex Ballingall.

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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.

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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.”

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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.

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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.

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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.

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.”

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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 [and] 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.