NEW ORLEANS — MISO’s maximum generation emergency event during a harsh winter featured under-forecast demand, issues with pricing software and day-ahead models so bogged down by complexity that they took longer to solve.
The grid operator reviewed the Jan. 23-27 winter storm during its quarterly Board Week meetup. Executive Director of System Operations J.T. Smith said the 2026 winter storm shared characteristics with the February 2021 storm.
Despite calling for maximum generation emergency procedures Jan. 24, MISO hit a 105-GW wintertime peak Jan. 27, on the final day of the storm. It eclipsed MISO’s 103-GW peak demand prediction ahead of the season. (See MISO: Gen Performance Lacking During January Winter Storm.)
Smith said MISO took the step of lodging its control room operators in Carmel, Ind., and Little Rock, Ark., in nearby hotels to make sure they would physically make it to headquarters for their shifts during the emergency.
Smith said that before the storm, MISO appeared to have ample reserves. But on the evening of Jan. 23, resources started to encounter performance issues and become inaccessible.
“We had an expectation that offline resources would be available,” Smith said during a March 24 meeting of Markets Committee of the MISO Board of Directors.
Load ultimately turned up about 3 GW higher across the Midwest region than MISO originally forecast for the Jan. 23 evening peak, Smith said.
MISO also said day-ahead offers from its members were lower than its expected need during the emergency.
“MISO under-forecasted the situation, but it also looks like our members under-forecasted the situation,” Smith said.
Smith said outages, offers that didn’t reflect true generation availability and higher load plagued the RTO. Compounding matters, MISO’s inability to publish locational marginal pricing was “not incentivizing the market to respond correctly to the situation,” Smith added.
MISO said its pricing issue “muted market response.” Because of software issues, it was unable to publish ex-post locational marginal prices for about 13 hours on Jan. 24. The Independent Market Monitor said the situation “exacerbated the emergency conditions.”
Carrie Milton, of the IMM staff, said the absence of market signals is “truly a testament” to the role the markets play during extreme weather conditions.
Milton said oil wellhead freeze-offs during the winter storm made it impossible for some MISO gas resources to get “gas at any price.” Natural gas pipeline interconnection Henry Hub traded at an all-time high of $30/MMBtu on Jan. 23.
Milton also said MISO’s emergency pricing seeped outside of the emergency in the Midwest to affect MISO South. She said emergency pricing raised prices to nearly $1,200/MWh in some parts of the South because of MISO’s regional directional transfer limit, which limits price separation between the regions to $700/MWh.
MISO accrued $16 million of day-ahead margin assistance payments to generators in the Midwest on Jan. 24, in addition to another $16 million of day-ahead margin assistance payments to generators in the South, Milton reported.
Southern Renewable Energy Association’s Simon Mahan said MISO’s inability to access the South’s generation highlights a need for it to focus on beefing up transmission links between its Midwest and South regions so the RTO can truly tap into its geographic diversity that proves helpful during system stress.
MISO’s day-ahead market model cleared slowly “for a number of days that week,” Smith continued.
MISO CEO John Bear said multiple grid operators experienced sluggish day-ahead modeling during the storm.
MISO was forced to make about 3 GW of emergency purchases from PJM on the morning of Jan. 24 and again in the evening. Smith said surplus generation in MISO South was trapped behind the Midwest-South constraint, requiring generators to stand down and driving up uplift payments.
The Monitor said just 67% of the 7.7 GW of load-modifying resources that cleared MISO’s capacity market in the Midwest for the winter season were available during the emergency event.
Milton said the IMM recommends MISO schedule load-modifying resources with longer lead times when it can tell that demand curtailments likely will be needed.
Milton said the RTO’s congestion was valued at more than $925 million during the winter, in part because of the winter storm, higher gas prices and renewable resources worsening transmission constraints.
MISO Director Robert Lurie asked if energy storage resources would have helped MISO ride out the storm more smoothly.
Smith said during extreme winter conditions, MISO often finds itself “work[ing] around” 30-minute lead gas units that encounter fuel issues.
“We live within the world of the fleet that’s given to us. There might be some opportunities there,” Smith said of battery storage.
But IMM David Patton said storage benefits would fade within a few hours in an extended cold spell.
“They can help a little bit, but they quickly lose their ability to help the system,” Patton said.
Smith said MISO’s machine-learning risk predictor was able to foresee 34% of the RTO’s 29 high-risk days over winter, better than its performance over the fall, when it failed to call any of the six high-risk days. (See MISO Usage, Outages Up in Fall 2025.)
“Better than zero, but still not great,” Smith said.
MISO also set separate peak renewable energy records for wind at 27 GW on Jan. 13 and solar at 16.5 GW on Feb. 27.
U.S. Secretary of Energy Chris Wright issued a second emergency order under Section 202(c) of the Federal Power Act to keep Unit 1 at the Craig coal plant in Colorado running for another three months until June 28.
“The last administration’s energy subtraction policies threatened America’s energy security and positioned our nation to likely experience significantly more blackouts in the coming years — thankfully, President Trump won’t let that happen,” Wright said in a statement March 30. “The Trump administration will continue taking action to ensure we don’t lose critical generation sources. Americans deserve access to affordable, reliable and secure energy to power their homes all the time, regardless of whether the wind is blowing or the sun is shining.”
Craig Unit 1 is operated by Tri-State Generation and Transmission Association and co-owned by it, PacifiCorp, Platt River Power Authority, Salt River Project and Xcel’s Public Service Company of Colorado.
Tri-State and the Western Area Power Administration Rocky Mountain Region are joining SPP as part of its RTO West expansion effective April 1, so the order directs the grid operator to use economic dispatch for the plant and to minimize ratepayer costs.
The 446.4-MW Craig Unit 1 started operations in 1980 and was poised to cease operations in December. DOE released a resource adequacy report last year arguing power plant retirements should stop considering rising demand and the agency noted that 17 GW of coal generation stayed open in 2025.
The Craig extension came a week after DOE extended emergency orders for CenterPoint and MISO to keep the F.B. Culley Generating Station open and for NIPSCO and MISO to keep the Schahfer Generating Station running. Both plants are located Indiana.
The coal plants were slated to retire in December and now are being kept open another 90 days. DOE reported that both ran during a major cold snap from Jan. 23 to Feb. 1. The Indiana plants’ 202(c) orders also are being challenged in court. (See Groups Contest Indiana Coal Plants’ Emergency Extensions at D.C. Circuit.)
In other cases, such as the legal challenge to the Campbell power plant 202(c) orders, appeals have been filed for every order. But the court has held them in abeyance and moved forward with the appeal of the first order issued for a plant.
DOE issued its first 202(c) order to block a planned retirement at the Campbell plant in Michigan in May 2025 and that case is the farthest along, with the department filing its first brief recently. Final briefs are due this April, and oral arguments are scheduled for May 15. (See DOE Defends Use of Emergency Orders in Court Filing.)
Texas regulators are launching a survey of water use by data centers and crypto miners to address concerns about whether the state is prepared for the potential demand from the large loads’ needs to cool servers and generate electricity.
The survey will be open April 2 through May 28. Public Utility Commission staff have worked with the state Water Development Board (WDB) and industry associations to develop and distribute the survey.
“The whole overall objective here for the data centers … that are either continuing to operate today or are thinking about coming to Texas, is to make sure that everybody has the water that they need,” Commissioner Kathleen Jackson said during the March 26 open meeting. “This is useful information that will help in the planning process and the future build out of additional water infrastructure.”
The Texas Legislature directed the Public Utility Commission to conduct the survey by adding a rider in the 2026/27 state budget. It instructs the commission to focus on industries whose energy demands have an “inverse relationship with their water usage.”
PUC staff will share the survey’s results with WDB and the Texas Commission on Environmental Quality for their own planning and demand purposes. Staff also must deliver a report to the legislature by the end of 2026.
State Rep. Armando Walle (D), who wrote the rider, said the survey is a “critical early step” in the state’s approach to water needs.
“We must find ways to meet the existing data gaps in our state and regional water planning process to ensure local governments — and these businesses themselves — can make informed decisions based on what resources are available, and will be available going into the future,” he said in a statement.
The Houston Advanced Research Center (HARC) said the state is home to 464 data centers and that it expected their water use to continue to rise, according to a report released in January. The center estimated that Texas uses 8 billion gallons of water each year, based on data center energy forecasts. HARC said an additional 70 sites are under development.
ESRs Separated from DRRS Development
The commission accepted staff’s recommendation to separate energy storage resources from ERCOT’s development of Dispatchable Reliability Reserve Service (DRRS) through a protocol change (NPRR1309), avoiding delays in implementing the product’s core functionality (55797).
Chair Thomas Gleeson said that while he believes ESRs should be able to access DRRS revenues, batteries’ “unique issues” would best be handled in a separate protocol change. He said ERCOT staff have told him decisions made in the second change could be rolled into DRRS’ first run.
“Because we can do it on the same timeline, it’s not going to delay DRRS, and battery inclusion in DRRS will not be delayed,” Gleeson said. “I’m comfortable with the recommendation that we separate this out.”
A 2023 law requires ERCOT to develop DRRS as an ancillary service and establish minimum requirements for the product:
reducing the amount of reliability unit commitment by the amount of DRRS procured; and
eligible resources capable of running for at least four hours and being dispatchable not more than two hours after being deployed.
NPRR1309 meets all statutory criteria and improves an earlier version by allowing online resources to participate in DRRS. The product will be awarded in real time and co-optimize (RTC) its procurement with that of energy and other ancillary services under RTC. The change has been granted urgent status and is due before the board for its June meeting.
The PUC also adopted a rule change for net-metering arrangements between a large load customer and an existing generation resource. The new rule establishes the criteria for ERCOT’s study of the arrangements and sets the procedural steps for completion within 120 days (58479).
The commission will have 60 days to deny or approve a net metering arrangement once ERCOT files its study results and recommendation to the agency.
The West-Wide Governance Pathways Initiative’s Launch Committee is finalizing role specifications for the initial board members of the Regional Organization for Western Energy (ROWE) as it prepares to evaluate candidates.
Lyceum Leadership Consulting, the search firm in charge of vetting candidates for ROWE’s board, has interviewed stakeholders to gather input on the role specifications for the initial five board positions that will be seated in 2026, Kathleen Staks, Launch Committee co-chair and ROWE interim president, said during a Pathways meeting March 27.
After the Pathways Initiative’s nine sectors provide input on the role specifications and search strategy in April, “we will kick off our board member search,” Staks said.
“This is the point at which we will be taking nominations, and the search firm will be starting their evaluation of various candidates and working through the nominating committee to evaluate those candidates and narrow it down to a slate of five,” Staks added.
Jim Shetler, general manager of the Balancing Authority of Northern California, provided an update on ROWE funding.
Shetler anticipates ROWE will raise roughly $1.1 million through stakeholder contributions and grants, “which should get us through mid- to third quarter of this year,” he said.
Shetler noted that CAISO has begun a stakeholder process to examine whether to approve an $8.5 million financing plan to fund ROWE’s start-up costs. He said ROWE and CAISO are discussing with “various banks” about what a loan structure might look like and are narrowing down alternatives. (See ‘Widespread Support’ for CAISO’s $8.5M ROWE Funding Plan.)
Meanwhile, the Pathways group working on developing ROWE’s Office of Public Participation has met with its counterpart at FERC to discuss best practices, Staks noted.
She added that the same work group has begun focusing on tribal engagement.
“We are doing some outreach and some work to figure out how the ROWE can get set up with a meaningful way for engaging with tribes and the various interests that they have as well,” Staks said.
The next Pathways meeting is scheduled for April 24.
TORONTO — Local distribution companies and bulk transmission system operators need to improve their alignment as LDCs transition from passive roles overseeing poles and wires, IESO CEO Lesley Gallinger told attendees of the Ontario Electricity Distributors Association’s ENERCOM 2026 conference March 23.
“I think the role that LDCs are taking on is becoming much more pivotal to future reliability and affordability conversations,” Gallinger said during a Q&A session with Elexicon CEO Amanda Klein. “The LDCs are front-running the adoption of emerging technologies like electric vehicles and heat pumps, and that’s useful information [for] the bulk system. And the work that LDCs have done to integrate [distributed energy resources] through their distribution systems is also … helpful from a technical perspective.”
LDCs and IESO need to improve their alignment on regional planning, forecast assumptions and operational practices, Gallinger said, citing a need for real-time distribution data.
“You have never been asked to do more than today,” Minister of Energy and Mines Stephen Lecce told the distributors in a lunchtime speech. “There has never been more constraints and pressure on the electricity system. You’re doing something right. You guys work together. You’re thinking ahead. You’re de-risking. You’re collaborating. You’re trying something new. You’re being bold. You’re challenging the status quo.”
Ontario and the federal government are making big bets on nuclear power, pledging to build 16,000 MW of new generation, including four small modular nuclear reactors and up to 4,800 MW of additional capacity at the Bruce Nuclear Generating Station. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)
Energy ‘Quadrilemma’
The passage of Bill 40, which made economic development part of the mission for IESO and the Ontario Energy Board (OEB), has turned the traditional energy trilemma — the balance of reliability, affordability and sustainability — into a “quadrilemma,” Gallinger said.
“The challenge lies in the fact that all four dimensions are interconnected. If you prioritize [an] outcome for one of the dimensions, you lose perhaps something on one of the other dimensions,” she said.
“Economic policy and energy policy are now inextricably linked. And so that leaves us kind of a narrow band for error,” she said. “We’re moving now to continuously and proactively plan. So rather than the five-year ‘set it and forget it’ model, we’re continuing to intake new information and … iterate on those plans. And that will allow us to stay adaptable and responsive to those evolving circumstances and hopefully help us get the quadrilemma equation right.”
Mark Olsheski, vice president of energy at Sussex Strategy, said increasing distribution-based generation will be crucial to navigating the next decade, before new nuclear capacity goes into service.
“We have well over 2,000 MW of embedded solar in Ontario, most of which is coming to the end of its contract. … There’s right now not … a clear plan for how that solar gets renewed,” he said during a panel discussion.
“This is just what’s already on rooftops and in fields at the distribution level. But I think that we need to deploy significant resources currently not [planned] within this window, that don’t involve big procurements for large gas or storage assets. The greatest opportunity to do that … is going to be at the distribution level.”
He cited the importance of the OEB’s Centralized Capacity Information Map, released in January, which provides data for both load and DER connections. “There are big swaths of the province that are pretty red — like you can’t really plug in a toaster oven without something blowing up. So certainly, there’s a lot of work that needs to be” done.
TORONTO — Canada should expect turbulent relations with the U.S. to continue under the Trump administration, speakers said at the Ontario Electricity Distributors Association’s ENERCOM 2026 conference.
In 2020, President Donald Trump hailed the United States-Mexico-Canada Agreement, which replaced the North American Free Trade Agreement, as the “largest, fairest, most balanced” trade deal in history. But as the agreement comes up for review in July, its renewal is anything but certain.
With “President Trump, anything is possible,” former diplomat Gitane De Silva said at the conference March 23. “I think we have to prepare for any outcome.”
The most likely outcome is that Canada and the U.S. will fail to extend the agreement, triggering annual reviews until a new pact can be reached, said De Silva, former CEO of the Canada Energy Regulator, which oversees international and interprovincial pipelines and electric transmission.
“It’s not to President Trump’s perceived advantage to get to ‘yes,’ because he likes the chaos. He likes uncertainty. He feels that makes him more powerful,” De Silva said. “So, I think we just have to become accustomed to the fact that that trading relationship is not going to be as stable as it was” before Trump.
Jeff Rubin, former chief economist of CIBC World Markets, was more blunt about prospects for the agreement, known as CUSMA in Canada.
“Prime Minister [Mark] Carney pretends that other than a few little tweaks, CUSMA will be renewed. CUSMA is a dead man walking. There is a 0% chance of President Trump renewing CUSMA,” Rubin said. “Whatever bilateral agreement [that is developed] will involve U.S. tariffs on Canadian exports.”
Already, Rubin said, car manufacturers are relocating operations in the U.S.
Rubin said it was President Joe Biden who began undermining the World Trade Organization and the global trading system with his “pervasive use of sanctions and tariffs.”
“But whereas Biden’s policy of friendshoring targeted America’s enemies — China and Russia — Trump’s policy of reciprocal tariffs makes no distinction between friend and foe. And, as Canadians have discovered to their horror, Canada is as much a target of economic warfare as is America’s enemies … perhaps in some sense even more so.”
De Silva said Canada will have some leverage in the negotiations because of the U.S. need for Canada’s heavy oil and fertilizers.
But Rubin said Canada — with the third-largest oil reserves and fifth-largest natural gas reserves in the world — has failed to maximize its resources.
“Prime Minister Carney often refers to Canada as an energy superpower. … But what Prime Minister Carney does not seem to recognize is it takes more than natural endowments to be an energy superpower,” he said. “Real energy superpowers like the United States and Russia do whatever is necessary to get the energy out of the ground and get it to markets that value it the most.
“While Canada’s geology has bestowed upon it considerable resources, the country has consistently lacked the political will to develop. That is why Canada’s oil production is less than half of Russia and Saudi Arabia and a third of America, and what Canada does produce is way below prices that other oil exporters get for their product.”
Alberta Tie Line, Secession Vote
De Silva said that in addition to considering dairy, poultry, eggs, automobiles and lumber trade, U.S. negotiators may also seek to resolve a dispute over the Montana-Alberta Tie Line.
In 2024, Berkshire Hathaway Energy (BHE) Canada, owner of the intertie, filed a complaint with the Alberta Utilities Commission alleging that the Alberta Electric System Operator’s restriction of imports was discriminatory and jeopardizing renewable power investment in Montana. U.S. Trade Representative Jamieson Greer raised the issue with the Senate Finance Committee during a presentation on CUSMA in December.
Alberta has denied discriminating against the U.S., saying it is merely managing grid congestion and protecting reliability. It says BHE’s complaint is an effort to increase its earnings from the merchant intertie facility.
De Silva noted that Montana Gov. Greg Gianforte (R) is a close ally of Trump. “Given that, I think the potential is that it rises higher on the list of irritants than something of this magnitude normally would,” she said.
Rubin said he expects Trump to attempt to influence an October referendum on whether Alberta should leave Canada. “I’m sure he’s prepared to offer Alberta statehood and throw in the Keystone XL pipeline as a sweetener,” Rubin said.
Benefits of Gridlock
Democrats could seek to restrain Trump if they win back at least one house of Congress in this year’s midterm elections, De Silva said.
“It’s actually an advantage for Canada to see that power be split,” she said. “So, it will become more dysfunctional for Americans … but in a way, that gridlock — dragging the puck — might be beneficial at this point in time.”
The long-term fate of U.S.-Canada relations will depend on who succeeds Trump as president, she said.
“The studies will show you that when you break trust, it takes at least twice as long to build it back than it did the first time,” she said. “We don’t have to like the Americans, but we’re going to be neighbors forever.”
‘Island of Stability’
Stephen Lecce, Ontario’s minister of Energy and Mines, highlighted Canadian leaders’ cooperative response to U.S. pressures, saying he wants Carney to succeed even though they are in different parties.
“This country is an island of stability in a sea of chaos,” Lecce said. “We’re working with the federal government in good faith on these matters, because in this moment, frankly, we’re on the same team. … You don’t hear [that] when I’m traveling the world. I will tell you, many of these subnational and national governments of different parties, they’re not on the same page. … That’s a Canadian value and something I’m proud of.”
Not long ago, the electric grid ran on a shared set of facts: weather data, flood maps and long-term climate projections from federal agencies. While imperfect, the data was broadly accessible and widely understood. Utilities, RTOs, regulators and developers might interpret the data differently, but they were at least starting from the same baseline.
At the very moment grid operators are being asked to plan for unprecedented complexity — explosive load growth from data centers, electrification of buildings and transport, and a rising cadence of climate-driven extreme events — the public data infrastructure that underpins those decisions is becoming less reliable, less complete and in some cases less available.
If this had happened a decade or two ago, it could have blinded the whole industry. Fortunately, a rapidly expanding ecosystem of private data platforms, proprietary climate models and AI-driven simulation tools is ready, willing and more than eager to fill that gap. And if government data integrity is threatened, the future of grid planning increasingly will be built not on shared public datasets but on licensed, and probably opaque, models.
This is a shift in governance as much as it is a shift in technology. And for a system as interconnected and reliability sensitive as the power grid, it raises a question: What happens when the “ground truth” of grid planning no longer is public?
Public Data Infrastructure is Eroding
Years ago, I toured the National Center for Atmospheric Research (NCAR), a brutalist I.M. Pei structure in Boulder, Colo., and an architecture-and-climate-science nerd’s dream day trip. On display was the room-sized Cray-1, the first supercomputer, highlighting the data-intensive nature of weather prediction.
Dej Knuckey
Funded by the National Science Foundation, NCAR was one of the leading scientific organizations creating the analytical methodologies to track the changing planet. It, along with agencies like NOAA, FEMA, USGS and EPA, has provided the baseline datasets that inform many aspects of the grid. These datasets no longer are produced by Cray-1 (the phone in your pocket is now orders of magnitude faster), and they are not perfect — but they are standardized and transparent.
Budget uncertainty, shifting political priorities and institutional constraints have all contributed to growing concern about the durability of federal climate and environmental data programs. In one of many moves to cut government research groups, the administration announced in December 2025 it would dismantle NCAR, citing it as a source of climate alarmism. While the nonprofit that manages NCAR is challenging the action, the U.S. electric system has to prepare for a day when it cannot rely on federal weather data for grid operations.
Even where data remains available, update cycles are slowing, and agencies struggle to keep pace with rapidly changing conditions. FEMA flood maps, for example, lag actual risk, while wildfire and heat risk datasets often are fragmented across agencies and jurisdictions.
For grid operators, this matters in very practical ways. Transmission planning needs consistent weather baselines, resource adequacy assessments require shared assumptions about temperature extremes and demand patterns, and emergency planning should draw from common risk maps.
The grid has always relied on a shared view of reality. As those baselines degrade — or diverge — the system risks losing coherence.
The Rise of Private Climate and Infrastructure Intelligence
Into this gap has stepped a new class of private-sector players, offering not just data but fully integrated predictive intelligence.
SPP’s Felek Abbas | SPP
One example is NVIDIA’s Earth-2 platform, a high-resolution digital twin of the entire planet. Using AI, Earth-2 aims to simulate weather and climate with a level of granularity far beyond that of traditional models. The promise is transformative: hyper-local forecasts of extreme weather, infrastructure-level risk assessments and scenario modeling that could reshape how utilities plan and operate.
Felek Abbas, senior vice president, chief technology and security officer at SPP, told RTO Insider that SPP is looking at the potential the Earth-2 platform offers.
SPP expects the improved detail and an additional week of detailed forecasting will help it in the day-ahead markets and improve its outage planning.
“If you’re expecting the load to be at a manageable place, you’re able to take an outage, but if you’re expecting the load to be really high, that’s not a time that you can afford to have an outage,” Abbas said. “More accuracy in that space means more reliability, and that’s what we’re after.”
Starting Broad or Narrow
While NVIDIA attempts to model the entire planet for any purpose — a one-planet-fits-all approach — another way to approach grid-meets-weather questions is to start with a specific industry query: How do we make the power system operate most efficiently? From there, we gather data sources, build models and test against decades of load, power pricing and weather data to develop a solution tailored for a complex industry’s needs.
Yes Energy is a prime example of this (and as of 2025, it happens to be RTO Insider’s parent company, so it clearly has great taste in industry intelligence). It has released an all-new module in its Power Signals product for “deeper forecast analysis” that isolates different weather effects to understand how they impacted historical load. In addition, it provides a view of the probable distribution of future demand based on observed weather outcomes up to a year ahead.
Models, Models Everywhere
Other industries have spawned additional weather intelligence companies with some applicability to the grid. Insurance companies and asset owners in particular seek digital crystal balls to assess the risks they face.
Organizations like First Street Foundation are redefining how climate risk is measured and monetized. Its extreme weather, wildfire and macroeconomic models translate complex environmental risks into address-level scores. For example, PVcase has integrated First Street data into its platform rather than relying on outdated FEMA flood maps, helping renewable energy developers and operators better understand flood risks.
Google DeepMind has both WeatherNext and Weather Lab. Jupiter Intelligence provides asset-level climate risk analytics for utilities and infrastructure investors, ClimateAi offers predictive climate insights tailored to operational decision-making, and Descartes Labs leverages geospatial intelligence to model environmental and economic systems at scale.
In a recent op-ed in Nature, two Oxford academics warned that rigorous standards need to be applied before trusting AI weather models. “Before weather agencies adopt AI models, the predictive skill of such models on a range of hazardous events — from heatwaves and heavy rainfall to major storms — must pass a defined minimum standard.” They proposed a protocol for training future AI systems that reserves a designated set of “iconic” extreme events solely for testing.
With or without those guardrails, we are seeing a shift from public data interpreted by utilities and regulators to private models that generate proprietary outputs embedded directly into planning and operational systems.
Implications for Utilities, RTOs and Grid Operators
For grid operators, this shift may become a source of friction and risk.
First, planning fragmentation will increase as utilities, developers and system operators rely on different datasets and models. One entity may base its load forecast on a proprietary climate-adjusted model; another may rely on historical NOAA data; and yet another may incorporate vendor-specific DER adoption projections.
The NCAR Mesa Laboratory in Boulder, Colo., conducts research on atmospheric chemistry, solar physics and forecasting models. | UCAR
The result could be a gradual erosion of alignment. Incompatible assumptions may underpin transmission plans, and divergent expectations of future conditions may emerge in interconnection studies. Regional coordination will be more difficult when participants no longer work from the same baseline.
Second, grid planning may become a “black box.” Many of the new models entering the space are proprietary and continuously evolving. Their assumptions are not fully transparent, their methodologies are not easily replicable, and their outputs may change as algorithms are updated.
For regulators and stakeholders, this creates a challenge: How do you evaluate a transmission investment justified by a model you cannot fully interrogate? How do you compare competing proposals built on different proprietary datasets?
We may move from engineering-led planning to model-led planning, with privately owned models.
Third, cost and access asymmetries are emerging. Large investor-owned utilities and well-funded developers can afford to license advanced datasets and modeling tools. Smaller utilities, municipal systems and co-ops often cannot. This creates the risk of a two-tier system of grid intelligence, where some actors operate with far more sophisticated — and expensive — insights than others.
Finally, operational dependencies are deepening.
Real-time grid operations increasingly rely on high-quality forecasts: weather-driven load, renewable generation output, wildfire risk and outage probabilities. These inputs are now being integrated into outage management systems, DERMS platforms and advanced forecasting tools — many of which depend on third-party data providers.
That creates a new form of vendor lock-in. If critical operational decisions depend on proprietary data streams, switching providers or validating outputs becomes significantly more difficult.
Regulatory and Market Implications
Regulators need to ask a seemingly simple question: Who validates the data?
If a utility files a transmission plan based on outputs from a proprietary climate model, what standard should regulators apply? Transparency? Historical accuracy? Peer review? And how should regulators enforce those standards when intellectual property protects the underlying models?
There also is a market power dimension.
Control over datasets increasingly means control over forecasts, risk perception and, ultimately, investment decisions. In that sense, private data providers may occupy a role analogous to credit rating agencies in financial markets: entities whose assessments shape outcomes but are not always fully visible or accountable.
For the grid, the stakes are particularly high because reliability depends on coordination, and coordination depends on shared assumptions. If different actors are operating on different versions of reality, the risk of misalignment — and failure — increases.
Managing the Public Grid with Private Data
I’m not arguing that private innovation is a problem. Far from it. The advances being driven by companies such as Yes Energy, NVIDIA, First Street and others are essential for managing a more complex, climate-exposed grid.
In a perfect world, society would treat public data infrastructure as critical infrastructure. However, the current administration has shown it will not consistently fund, maintain and update federal datasets at a pace that reflects their importance to national energy systems. And if it perceives climate data as a political tool rather than a neutral truth, it is unlikely to continue improving the open, standardized baselines that the industry has relied on until now.
Given the irreversible move from public to private data, transparency requirements need to evolve.
If proprietary models are used in regulated planning processes, the assumptions, validation methodologies and sensitivity analyses should be disclosed. Regulators do not need to see every line of code, but they do need confidence in the outputs.
Hybrid approaches should be explored. Public-private partnerships may combine the strengths of open data and private innovation, creating shared validation frameworks that preserve comparability while enabling advancement.
Data itself should be recognized as a core component of grid infrastructure. We regulate power plants and transmission lines. We set standards for reliability and interconnection. But we do not yet have a coherent framework for governing the data that determines where those assets are built and how they are operated.
The electric grid is becoming more digital, more dynamic and more exposed to climate risk. The question no longer is whether we have enough data to run the grid; it is whether the data we rely on is shared, trusted and governed in the public interest.
Reliability is not just a function of power plants and wires; it is a function of whether everyone is working from the same map.
Power Play columnist Dej Knuckey is a climate and energy writer with decades of industry experience.
The MISO Independent Market Monitor was looking out for retail electricity consumers when he found the $22B transmission Tranche 2 spend uneconomic, and that local solutions weren’t adequately considered. The board approved it anyway. (See MISO Board Endorses $21.8B Long-range Transmission Plan.)
With a full-blown affordability crisis in utility rates, there is no justification for questionable spending — much less if it primarily benefits other states, some of which have expensive policies that need such transmission. The IMM also found a per-household cost of such spending of $7,500.
An independent market monitor is just that — independent.
He should not be shown the door but should be allowed to continue to do his job and also to talk to state regulators who seek his advice.
Instead, those who put the plan together and approved it without full vetting of local generation and non-wires solutions should be scrutinized. We owe it to the ratepayers.
And we need to see who is really behind this new group.
Bill Malcolm is a former MISO employee. His opinions are his own.
SPP will complete its third major expansion of its RTO footprint when it begins administering the regional transmission grid under its tariff for several Western organizations overnight March 31 into April 1.
C.J. Brown, the grid operator’s vice president of operations, said staff have been encouraged by the status of their system and readiness activities, and they are expecting a successful cutover.
“After years of planning and testing, it’s exciting to be close enough to April 1 that SPP’s forward‑looking studies now include data from the western part of our expanded territory,” he said in a statement to RTO Insider. “This is obviously a major milestone, but it’s just the beginning of something bigger. Our operators and support staff are already looking ahead to April 2 and every day that follows, when we’ll be just as focused on our ongoing mission to keep the lights on.”
The expansion will add three states to the RTO’s 14-state footprint: Arizona, Colorado and Utah. It follows the previous additions of the Integrated System (IS) in 2015 and Nebraska’s public utilities in 2009. Those expansions added the Dakotas and parts of Iowa, Minnesota, Montana and Wyoming to the RTO’s footprint. (See Integrated System to Join SPP Market Oct. 1.)
The key organizations joining RTOE are:
Basin Electric Power Cooperative;
Colorado Springs Utilities;
Deseret Power Electric Cooperative;
Municipal Energy Agency of Nebraska (MEAN);
Platte River Power Authority;
Tri-State Generation and Transmission Association; and
Several Western Area Power Administration (WAPA) regions: Upper Great Plains (UGP)-West, Colorado River Storage Project and Rocky Mountain.
Basin Electric, MEAN, Tri-State and WAPA’s UGP-East Region already are members of SPP, having placed their respective facilities in the Eastern Interconnection under SPP’s tariff as part of the IS.
Several other load-serving and embedded entities that are part of WAPA’s Colorado-Missouri balancing authority also will become part of the SPP RTO on April 1.
The expansion began in 2020 when several utilities decided to explore RTO membership. A Brattle Group study found the move would be mutually beneficial and save $49 million annually.
SPP’s members will have access to seven of the eight back-to-back DC ties, with a combined capacity of 1,320 MW, that connect the asynchronous Eastern and Western interconnections.
The European Network of Transmission System Operators’ (ENTSO-E) final report on the Iberian Peninsula blackout of April 2025 lays out the root causes and chain of events that led to the collapse of the grid, providing critiques of the numerous points of failure.
Much of 472-page document, released March 20, consists of the organization’s factual report, released in October 2025, but it also includes a detailed root-cause analysis and recommendations for preventing future outages, as well as additional data that were not previously available. (See European Regulator Issues ‘Factual Report’ on Iberian Outages.)
The report’s findings largely align with those of the Spanish government and grid operator, which concluded the blackout occurred because traditional synchronous generation could not provide adequate control of high voltage resulting from frequency oscillations, exacerbated by a faulty power plant controller.
ENTSO-E stresses throughout the report that no single factor led to the collapse and that any one of the factors by itself would not have been a problem. Instead, it created a large root-cause tree displaying the multiple factors that led to a very fast voltage increase (page 332).
The roots of the tree include:
no explicit criteria concerning dynamic behavior for conventional generators’ reactive power;
no economic consequences for generators if their voltage-control requirements were not met;
renewable resources operate in fixed power factor mode; and
the design of voltage control of local generation networks not aligned with system needs.
The report separates its recommendations based on whether they are related to the root causes and gives each a priority label. ENTSO-E said generators should operate in voltage-control mode whenever possible and that transmission system operators (TSOs) should ensure there are enough voltage-control and monitoring equipment on the grid.
It also said TSOs need to enforce Europe’s harmonized voltage operating range: Spain allows its grid to operate up to 435 kV, while the rest of the continent allows up to 420 kV.
Finally, ENTSO-E said a common procedure should be established to create a snapshot after a significant event, allowing for accurate simulations of the system under similar conditions to those of the event. It noted that it had to rely on incomplete data, particularly from Spanish TSOs.
“This blackout highlights how developments at the local level can have systemwide implications and underlines the importance of maintaining strong links between local and European system behavior and coordination, while ensuring that market mechanisms, regulatory frameworks and energy policies remain aligned with the physical limits of the system,” ENTSO-E said.
