The push to develop a resource adequacy program serving non-CAISO members of the ISO’s Extended Day-Ahead Market appears to be gathering momentum, with backers saying they aim to produce a draft design for the program in April.
That’s a key takeaway from a March 7 letter to the leaders of the CAISO Western Energy Markets (WEM) Body of State Regulators (BOSR), in which six utilities planning to join the EDAM spelled out the clearest vision yet for how the program could take shape: on the footing of the ISO’s Western Energy Imbalance Market.
“The WEIM’s proven ability to support reliable load service makes it a natural foundation for exploring an expanded framework through EDAM and an integrated RA solution,” the utilities said in the letter, which was signed by Mike Wilding, PacifiCorp vice president of energy supply management, on behalf of PacifiCorp, Balancing Authority of Northern California, NV Energy, Portland General Electric (PGE), Public Service Company of New Mexico (PNM) and Turlock Irrigation District.
The letter was addressed to BOSR Chair Gabriel Aguilera, chair of the New Mexico Public Regulation Commission, and Vice Chair John Hammond, a member of the Idaho Public Utilities Commission.
“A voluntary regional RA program aligned with an organized market footprint is expected to deliver value in several areas, including enhanced regional coordination, greater reliability and capacity savings for our customers,” Wilding wrote.
The letter comes nearly five months after a handful of utilities — including NV Energy, PacifiCorp, PGE and PNM — announced their intent to withdraw from the Western Power Pool’s Western Resource Adequacy Program (WRAP), choosing not to commit to the program’s first “binding” season in winter 2027. (See PacifiCorp Next to Leave WRAP After Raising Concerns.)
The WRAP, which was conceived and established before the competition between the EDAM and SPP’s Markets+, is operated by SPP but includes members intending to participate in either day-ahead market — although Markets+ members are required to join it.
Around the same time as the withdrawals, RTO Insider learned some of the withdrawing parties had already begun discussions to create an alternative RA program focused on EDAM participants. (See EDAM Participants Exploring Potential New Western RA Program.)
Wilding said the utilities envision the “offering to encompass the EDAM and WEIM footprint,” and noted they foresee it being governed by the Regional Organization for Western Energy (ROWE), the independent body established by the West-Wide Governance Pathways to oversee the WEIM and EDAM. (See Pathways’ ROWE Could Offer Western RA Program, PGE Says.)
“During the transition, the entities identified [in the letter], all of which are committed to EDAM or leaning toward EDAM, propose to guide the stakeholder process and encourage engagement from all interested parties. We recognize the importance of this initiative, but it is important to note that no official commitments or decisions have been made at this time,” he wrote.
The utilities welcome input from “state regulators, load-serving entities, suppliers and regional partners” as the initiative advances, Wilding wrote.
The effort’s backers intend to release “a draft design for a market-integrated solution” in April and “launch an open transitional stakeholder process to refine the program.” The first step will be to start dialogue during the WEM Regional Issues Forum meeting March 16, the letter said. The RA program is also on a March 19 meeting agenda of the ROWE’s newly established Formation Committee.
“The West faces a transformational moment. By building on the successes of WEIM and EDAM, we all have the opportunity to create a unified framework that advances reliability, affordability, regional transparency and regulatory goals,” Wilding wrote.
The Bonneville Power Administration’s (BPA) planned departure from the Western Energy Imbalance Market has prompted questions about how the agency will handle the yearlong period before it joins SPP’s Markets+.
The agency plans to exit the EIM by Oct. 1, 2027, and trade in bilateral markets until Oct. 1, 2028, when it expects to join Markets+, BPA staff said during a day-ahead market participation workshop March 12.
BPA staff don’t expect any hiccups related to liquidity or finding trading partners in a bilateral market, saying, “We’re bidding in with reserves that we’re already holding.”
Libby Kirby, BPA’s Markets+ program manager, said most of the agency’s trades are already bilateral.
“We submit non-regulating balancing reserves as the minimum that we put in the market,” Kirby said. “We will no longer do that. We will return to balancing within the [balancing area]. … We still have … the same methodology. We hold the same amount of balancing reserves.”
Still, meeting participants voiced concern.
“An entire year to be out of the EIM just seems like a really long time, considering that you’re already in the EIM now,” Henry Tilghman, a consultant for the Northwest & Intermountain Power Producers Coalition, said during the meeting. “It seems like it’d be just as much work for operations people to manage in the bilateral market as the EIM.”
Elsa Chang, BPA’s EIM program manager, said the agency will commit resources beginning in January 2028 to start training, system configuration testing and the other necessary steps to join Markets+.
The full year is needed for the “time to do training, to do testing,” Chang said. “We would have to go straight into these SPP activities without much prep time.”
Dan Williams, principal adviser for Western markets at The Energy Authority, supported the plan. By setting a firm timeline, BPA is allowing other entities in the region to prepare for bilateral trading liquidity instead of dealing with uncertainty, he argued. He said he hopes the exit from the EIM will prompt discussions on the seams between Markets+ and CAISO’s Extended Day-Ahead Market, which is to launch May 1, 2026. (See BPA Outlines Next Steps in Markets+ Implementation.)
“There’s no reason that by that point in 2027, we can’t have bilateral markets working better with EDAM that will allow BPA to have markets to buy and sell into and maintain market liquidity across the region, even after exiting the EIM,” Williams contended.
But Chris Roden, director of energy resources at Clatskanie People’s Utility District, asked for more transparency on what the EIM exit will mean, saying the transition feels like a “Jesus-takes-the wheel moment.”
“We have a number of subsequent processes that we run based on that market participation,” Roden said. He added that settlements and rates “have become really contingent upon EIM participation.”
Texas Gov. Greg Abbott has appointed former infrastructure developer Patrick Rhode to the state’s Public Utility Commission, bringing the agency to its full five-person complement.
Rhode’s term expires Sept. 1, 2027, and is effective April 1, according to Abbott’s March 12 announcement.
Rhode spent 16 years as vice president of corporate affairs for Cintra, which develops and manages energy, highway and airport infrastructure projects in North America. He founded his own eponymous public relations consulting firm in Austin in 2024 and serves as its president.
He is credited with helping secure and protect more than $10 billion in “new age” infrastructure projects and managing diverse policy climates at federal and state government levels.
The Advanced Power Alliance, which represents advanced generation projects, welcomed Rhode’s appointment. The APA said his career has been defined by “navigating complex institutions” and “demonstrating a seasoned understanding of how public policy, regulatory environments and private investment” work together.
“Texas is home to more power generation investment than anywhere else in the country, and that investment … is the product of a regulatory environment that is stable, predictable and focused on positive outcomes for Texas consumers and the Texas economy,” APA President Jeffrey Clark said in a statement. “A strong, reliable, affordable electric grid requires all of these technologies working together, and the commission plays an essential role in ensuring the conditions are in place for diverse energy investment to continue.
“We are confident that Commissioner Rhode understands the stakes.”
Patrick Rhode Strategies works with organizations to help manage commercial development support, government and public affairs, political risk and strategic communications.
Before he joined Cintra, Rhode was a special assistant to President George W. Bush, associate administrator of the Small Business Administration and senior adviser to NASA, and he held senior roles in the Department of Homeland Security after Sept. 11, 2001. He began his career in television reporting for CBS and ABC affiliates.
An Arkansas native, Rhode holds bachelor’s degrees in political science from the University of Arkansas and in communications from the University of Arkansas at Little Rock.
The PUC’s membership was changed from three commissioners to five after the disastrous 2021 winter storm that brought the ERCOT grid to its knees. Besides the electricity sector, the commission regulates the state’s water, wastewater and telecommunications utility industries.
Forecasting is like driving a car blindfolded while following directions given by someone who is looking out of the back window. — Anonymous
Utility regulators beware: Not all forecasts are objective. Some are normative or biased, while others are based on science. When making important decisions, regulators must frequently choose between competing forecasts submitted by parties with varying agendas.
With potentially billions of dollars at stake, regulators need to reconcile the “forecast” discrepancies. Just as important but often overlooked, regulators also need to know the range of plausible forecasts and the risks associated with accepting one forecast over others. The risks triggered by uncertainty can play an important role in regulatory decisions.
Much of the push for a particular decision, whether for long-term planning purposes, merger proposals, determining future utility rates or other matters, comes from interest groups.
Regulators should receive their forecasts, which are critical for decision-making, with a grain of salt. They should ask if the forecasts are self-serving or are they legitimate and reflect objective analysis? Gaming by different stakeholders can present regulators with biased forecasts, which would require special regulatory-staff expertise to uncover.
Hedging Under Uncertainty
Often ignored, regulators should hedge their decisions to account for the inherent uncertainty associated with forecasting the future. A rational decision-maker would tend to respond to future unknowns by exercising caution in committing to a major action today.
Ken Costello |
Regulators therefore should require utilities and other parties to submit a reasonable range of forecasts to justify their positions. Basing a large investment or other major decision solely on the “best guess” forecast, or the future deemed most likely to occur, can result in substantially higher costs relative to the best action determined ex post facto with actual outcomes. In other words, an avoidable risky decision is more likely when based only on information provided by a “best guess” forecast without considering other possible futures and their implications for the right decision.
A range of forecasts or scenarios can help regulators quantify and evaluate the risks associated with individual decisions, related to electric-generation planning, energy efficiency initiatives or other actions, then judge whether the risks are intolerable. Uncertainty requires regulators and utilities to ask if the possible maximum losses from a particular decision are large enough to disqualify that decision from further consideration?
I use the term “forecast” to encompass both 1.) the future outcome that is most likely to occur (i.e., the “best guess” or single-point forecast) and 2.) a future outcome that is less likely to occur based on an alternative set of assumptions like economic conditions, the price of electricity, the price of substitutes for utility electricity, and the economics of renewable energy.
Some analysts refer to “best guess” forecasts as reference forecasts when they reflect the future with the highest probability of occurrence. The forecast is based on a set of events the forecaster expects will occur or considers more likely to occur than other events. If one has to choose a single forecast with a bet of $100 on the line, what would it be? It would presumably be the “best guess” forecast since the payoff would go to the person whose forecast lies closest to the actual outcome.
The regulator makes choices by using forecasts provided by utility stakeholders. First, it could approve the utility action based on the single-point price forecast; for example, the “best guess” demand growth of electricity 4% per annum, so the decision is contingent only on this forecast. This is a valid decision, however, only when 1.) the regulator places a high degree of confidence in single-point forecasts, and 2.) the consequences of incorrectly forecasting demand within a large range are minimal. For example, the preferred decision does not depend on whether demand growth is 2% or 4%. Otherwise, the regulator lacks access to valuable information to decide.
This situation is analogous to a person choosing a financial asset with the highest expected return, say, stock in a high-tech company, without considering its risk relative to other assets.
Most people would decide not to allocate all their investments to this high-return, high-risk asset. They would tend to diversify their investment portfolios to balance the tradeoff between return and risk. For financial assets, diversification implies an objective other than maximizing expected return or minimizing risk. Diversification reflects managing risk at a cost acceptable to the decision-maker given the degree and nature of their risk adversity.
Modern portfolio theory considers the inherent risk in various financial and physical assets and develops methods for aggregating investments to maximize the tradeoff between risk and return. In a different context, selecting a specific generation technology, or group of technologies, may stem from its lower risks relative to other technologies, even if the other technologies have lower expected levelized costs.
Using Different Forecasts
In our above example, as an alternative, the regulator could approve the utility action based on a range of demand-growth forecasts. It could, for example, review several forecasts from credible sources to select high, medium and low forecasts that represent reasonable demand-growth possibilities.
The evidence might show that demand-growth forecasts within a certain range result in the same preferred decision (e.g., expand generating capacity by a certain level by the year 2035). This sensitivity analysis makes the regulator more confident that the action taken will carry little risk unless it assigns a non-trivial probability to demand growth beyond the selected range. (The risk would be the opportunity cost of making a particular decision when another decision would have produced a better outcome after the fact.) Analysts consider such actions to be robust under a wide range of conditions. Robustness means that regulators would require less precision from a “best guess” forecast.
The regulator could approve the utility action after considering the cost of making the wrong decision based on erroneous demand forecasts (i.e., the loss function). The building of a generating facility based on demand growth of 5%, for example, could cost the utility an additional $100 million a year, compared with building the facility when the actual demand growth turns out to be 3%.
The regulator might want the utility to “hedge” its plan to moderate the cost (i.e., loss) from mis-forecasting demand growth. One idea is for the regulator to instruct the utility to take a wait-and-see approach as it accumulates more information to improve its forecasting accuracy before committing to a decision. To the extent that waiting reduces demand-growth uncertainty, the utility may reap an “option value” from an investment delay stemming from this uncertainty.
Loss Function
Rational risk-averse decision makers, implicitly if not explicitly, apply what is called a “loss function.” This function calculates the cost of a decision conditioned on a single forecast or range of forecasts that turn out to be wrong. Assume the decision to build a new gas-fired generating plant is contingent on the natural gas price being in the range of $3 to $5.
If the actual price is $7, the utility’s revenue requirements would be $500 million lower if it chose to build a solar facility instead. The $500 million represents a loss from relying on the wrong forecasts, which is inevitable when dealing with something as dynamic and unpredictable as demand growth, natural gas prices and other factors affecting the optimal decision.
The above example has a parallel to the current climate-change debate. Studies have shown that catastrophic consequences can follow if we do not take actions today to reduce greenhouse gases, but these consequences are highly uncertain, so much so that scientists cannot assign probabilities to their likelihood.
We may, therefore, spend money today to avoid an outcome that may never occur. The question is: What should we do today? The same question applies when an event is unlikely to occur but will cause a catastrophic outcome if it does. A society, group or individual that is risk-averse would tend to spend something today, for example buying insurance, to mitigate possible financial consequences in the future.
Distorted Incentives?
Although less guilty than in the past, utilities, in my observation, place excessive reliance on “best guess” forecasts to justify major decisions and fail to include a loss function in their forecasting exercise. One question still lingers: Does this problem reflect flawed decision-making, or do utilities and regulators deliberately produce and approve forecasts with overblown sureness and absent information on the negative consequences of erroneous forecasts?
The latter reason could be to buttress a particular, politically palatable action or, in some other way, advantageous to a utility or the regulator. One has to wonder.
Kenneth W. Costello is a regulatory economist and independent consultant who resides in Santa Fe, N.M.
The Bonneville Power Administration released its draft proposed decision to join SPP’s Markets+, noting that a year after the agency issued its record of decision in favor of the market, preparations have advanced to a point where BPA can “move forward with implementation and propose joining Markets+ in October 2028.”
The draft decision differs from the agency’s day-ahead market policy and record of decision that it issued in 2025. Those were “a direction toward participation in Markets+” when the market was still in a “conceptual stage,” BPA staff said during a March 12 workshop discussing the decision. (See BPA Chooses Markets+ over EDAM.)
“We are pleased to share that we have advanced our planning for systems, processes and market implementation because of the rapid progress in Markets+ development,” BPA Administrator John Hairston wrote in a letter announcing the draft decision. “This progress in market development has allowed the agency to advance implementation planning efforts and further evaluate readiness requirements. We are now positioned to move forward with implementation and propose joining Markets+ in October 2028.”
Hairston touted Markets+’s day-ahead and real-time capabilities, writing the market would “ensure a reliable, affordable and abundant energy supply for consumers in the Northwest.”
The decision will allow BPA to continue preparing for market entry and work with customers on day-ahead market implementation, according to the letter.
Hairston’s letter briefly notes that in the lead-up to the earlier ROD, the agency found it would reap greater benefits in Markets+ than in CAISO’s Extended Day-Ahead Market.
The agency is not “revisiting” the issue. Rather, BPA seeks comment only on the March 12 draft decision, Hairston wrote.
Following the release of the ROD, BPA began reviewing its ability to satisfy Markets+ obligations. The agency joins not only as a market participant but also as a balancing authority, transmission operator and transmission service provider, and must therefore “have the capability to perform numerous tasks,” Hairston noted.
“Bonneville will continue to engage in proactive planning for both agency and customer Markets+ participation activities throughout this process,” according to the letter. “Bonneville’s customer and stakeholder engagement will be ongoing, including through its day-ahead market workshop series, tariff proceedings and rate case processes.”
The first wave of participants will join Markets+ on Oct. 1, 2027: Arizona Public Service, Salt River Project, Tucson Electric Power, Powerex and Xcel Colorado. BPA expects to join a year later alongside Chelan County Public Utility District, Grant County Public Utility District, Puget Sound Energy and Tacoma Power.
Stakeholders have until April 3 to comment on the draft decision.
PJM’s Independent Market Monitor warned that the cost of wholesale power in the RTO will continue to rise with the rapid addition of data center load without enough capacity to serve it.
According to the Monitor’s State of the Market report for 2025, released March 12, PJM’s total cost of power rose nearly 49%, from $55.52/MWh in 2024 to $82.67/MWh in 2025. Of that, the cost of capacity rose 262%, from $3.61 to $13.09, after two Base Residual Auctions that saw record clearing prices.
“Data center load growth is the primary reason for recent and expected capacity market conditions, including total forecast load growth, the tight supply and demand balance, and high prices,” the Monitor wrote. “But for data center growth, both actual and forecast, the capacity market would not have seen the same tight supply demand conditions; the same high prices observed in the 2025/26 BRA [held in 2024], the 2026/27 BRA and the 2027/28 BRA; and the currently expected tight supply conditions and high prices for subsequent capacity auctions.”
In both the report and in a teleconference with reporters, Monitor Joe Bowring blasted PJM for “continuing to simply accept the interconnection of large data center loads that cannot be served reliably because there is not adequate dispatchable capacity.”
“But the consensus seems to have moved to, ‘Well, let’s interconnect them, but let’s curtail them whenever that capacity is needed by other customers,’” Bowring told reporters. “That’s easier said than done.”
The high capacity prices have had a direct effect on retail prices, with ratepayers seeing spikes beginning June 1, 2025. “Just a simple fact,” Bowring said. “There’s been a lot of attempts to confuse the issue. … It is entirely about data centers.”
The Monitor urged changes to the capacity market to account for data center load before the next BRA in June. It also argued that its proposal for the reliability backstop auction, instigated by the governors of PJM’s member states and the White House, is the only one consistent with both the principles laid out by the government and the Ratepayer Protection Pledge signed by several large tech companies.
Those documents “establish two essential core principles: that the data centers must bear their own costs and risks and not shift them to other customers, and that the data centers must bring their own new generation in any one of a number of forms or be fully curtailable,” the Monitor wrote. “The temptation to create complex regulatory structures to shift data center costs and risks to other customers should be resisted. … Other PJM customers, whether residential, commercial or industrial, should not be treated as a free source of insurance for data centers.”
Bowring was blunter on the teleconference: “Really the only purpose of running this backstop auction is for data centers that have not managed or don’t want to be involved in negotiating bilateral contracts with generation developers to meet their demand.”
A reporter asked about data centers’ opposition to long-term bilateral contracts with utilities, as they argue load forecasts are uncertain. Instead, they want PJM to act as the counterparty for a predetermined amount of capacity in the backstop auction. (See PJM Plans to Release Reliability Backstop Design in April.)
“I mean, think about what that’s saying: that individual data centers don’t know what their demand is?” Bowring replied. “That’s not a plausible statement. I think part of what the data centers are doing is trying to make things sound more confusing than they are in order to avoid taking responsibility for their load.”
Making the RTO a counterparty “makes every other customer in PJM a source of free insurance for the data centers, which is ironic because these are some of the biggest, most profitable companies in the world,” he said.
Future participants in SPP’s RTO expansion into the Western Interconnection have affirmed their support to meet the April 1 go-live deadline with a unanimous vote of support.
SPP said in a March 12 news release that the decision to proceed as planned with the Western RTO expansion is a “strong signal of confidence” as the grid operator and its members complete their final system tests.
“April 1 will be a milestone day for SPP,” CEO Lanny Nickell said in a statement, noting the grid operator will be the first RTO to bridge the Eastern and Western grids.
The expansion marks the culmination of more than a decade of outreach and collaboration with Western entities. Those efforts have included the failed Mountain West Transmission Group, but also the Western Energy Imbalance Service (WEIS) market and Markets+, the latter of which is expected to be deployed in October 2027. (See Monroe’s Western Outreach Pays Dividends for SPP.)
The expansion will occur overnight March 31-April 1, when SPP will begin administering the regional transmission grid under its tariff for the following organizations:
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
Western Area Power Administration (WAPA) regions: Upper Great Plains (UGP)-West, Colorado River Storage Project and Rocky Mountain.
Basin, MEAN, Tri-State and WAPA’s UGP-East region already are RTO members of SPP. All seven also are participating in the WEIS market.
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 says its wholesale electricity market, resource adequacy program and other regionalized services can help Western members reach renewable energy goals; strengthen system reliability; and use new opportunities to buy, sell and trade power.
The quarterly meeting of NERC’s Reliability and Security Technical Committee in Phoenix saw updates and progress on key ERO initiatives, as NERC leaders confirmed that big changes are coming.
NERC Trustee Sue Kelly, who has served as liaison between the ERO’s Board of Trustees and the committee for the past two years, told members that “management is already hard at work” preparing to implement the recommendations of the Modernization of Standards Processes and Procedures Task Force. Trustees voted to accept the recommendations at their most recent meeting in February, and NERC’s management said it hopes to finish the transition by the end of 2027. (See NERC Board Accepts MSPPTF Recommendations.)
Implementing the MSPPTF’s proposals would put the RSTC at the center of NERC’s standards development process and “require a collective change in mindset” from members, Kelly said. The committee would be in charge of vetting all standard initiation requests twice a year to determine the appropriate action.
“This committee will definitely be in the mix as things move forward, [and] I will do all I can to support that effort,” Kelly said. “Your role in SIR review is going to have to take place in a substantially shorter time frame than you all are used to working under, and we’re all going to need to adjust our time expectations accordingly.”
Kelly and NERC Chief Engineer Mark Lauby highlighted the importance of the committee’s work on large loads, which Kelly called an “incredibly high-profile” topic that “we do not have a moment to lose … to address.”
Lauby told attendees that NERC is “moving swiftly toward” a Level 3 alert on large loads that will identify “essential actions” for recipients to follow. It follows a Level 2 alert in 2025 that provided recommendations on large loads; Lauby said NERC will release a report on the responses to that alert “soon.”
Action on Large Loads, DERs
The discussion of large loads continued as committee members approved a proposed policy paper on challenges integrating large loads into the electric grid. NERC’s Large Loads Working Group developed the paper, which includes topics on the interconnection process, planning and resource adequacy, modeling, security and resilience, disturbance ride-through and load balancing; industry provided comments June 16-July 17, 2025.
Members also approved a technical reference document from the System Planning Impacts from Distributed Energy Resources Working Group, created in response to industry comments on a standard authorization request relating to the role of DERs in operational planning analysis and real-time assessments. SPIDERWG members developed the document to suggest possible resolutions to stakeholders’ comments and to “demonstrate the current industry practices associated with modeling DERs.”
Also approved was a security guideline on voluntary best practices for physical security protection at electric facilities. NERC’s Security Working Group proposed the guideline as a replacement for an existing document based on input from asset owners and operators. It emphasizes a layered defense approach incorporating physical security controls, electronic systems, security personnel and effective corporate security policies.
The last document approved by RSTC members at the meeting was an implementation guidance document for reliability standard PRC-023-6 (Transmission relay loadability). The paper applies to requirement R1 of the standard, which concerns protective relay settings, and clarifies the criteria by which asset owners can evaluate phase protective relay element settings.
The RSTC also accepted several documents to post for industry comments, including reliability guidelines on operating reserve management and on modeling of aggregate DERs, and a security guideline on DER aggregators and inverter-based resources. A policy paper on the use of artificial intelligence and machine learning also was accepted for comment by RSTC members, as was a technical reference document on supply chain risk mitigation strategies.
In a potential hurdle to Blackstone Infrastructure’s acquisition of TXNM Energy, state regulators have ordered Blackstone to provide legal justification for its purchase of 8 million shares of TXNM stock without the regulators’ consent.
Two hearing officers with the New Mexico Public Regulation Commission on March 11 issued an order to show cause related to the stock purchase. The order starts an investigation but does not determine whether any violations occurred.
TXNM and Blackstone Infrastructure announced in May 2025 Blackstone’s proposed $11.5 billion purchase of TXNM, the parent company of Public Service Company of New Mexico (PNM) and Texas-New Mexico Power (TNMP). Under the proposal, TXNM would be acquired by Blackstone Infrastructure subsidiary Troy Parent Co.
In June 2025, Troy TopCo LP, which owns Troy Parent, closed on a deal to buy 8 million shares of TXNM stock for $400 million. The stock purchase made Troy TopCo TXNM’s third-largest shareholder, with about a 7.59% ownership, according to filings in the case.
On Feb. 6, Prosperity Works filed a motion asking the commission to look more closely at the stock purchase. On its website, the group says its mission is to promote “economic prosperity for all New Mexicans.”
Prosperity Works argued that under New Mexico Statutes section 62-6-12, buying stock of a public utility or holding company requires PRC approval if the purchase is for the purpose of acquiring a public utility or holding company. Without commission approval, the purchase “shall be void and of no effect,” the statute states.
In their response, TXNM and Blackstone said the statute applies only to transactions that result in a change in control of a public utility or holding company. They said the stock purchase was a financing transaction separate from the proposed acquisition.
The PRC hearing officers’ order said Blackstone’s response does not fully address Priority Works’ concerns.
“Further inquiry is necessary to ensure that the joint applicants have properly adhered to the statutory obligations presented in Section 62-6-12,” the hearing officers said in their order. TXNM and Blackstone must show why the stock purchase didn’t violate state law and, if a violation did occur, what the legal and practical implications are.
Blackstone and TXNM are required to file briefs by April 6. Other parties in the case may also file comments by that date, and responses are due by April 20. Hearing examiners will then hold a hearing.
Among parties formally supporting Prosperity Works’ motion is the New Mexico Department of Justice, which filed a brief in the case Feb. 19.
“State law requires oversight when public utility stock is issued in connection with a transaction like this,” Attorney General Raul Torrez said in a statement. “We are asking the commission to ensure that all legal requirements are satisfied and that the public interest remains the guiding priority.”
Other supporters include New Energy Economy, the New Mexico Consumer Protection Alliance, the Coalition for Clean Affordable Energy and PRC staff.
Blackstone’s bid to buy TXNM Energy comes after a previous attempt to buy PNM failed. Avangrid announced in January 2024 that it was pulling out of its proposed $8.3 billion acquisition of PNM Resources, as the deal remained tied up at the New Mexico Supreme Court. (See Lights out for Avangrid’s PNM Acquisition.)
As part of the proposed Blackstone acquisition, PNM would provide $175 million in benefits to customers and the state — including a $105 million acquisition rate credit, the companies said in August 2025. PNM said the acquisition would help it meet key goals, including transitioning to clean energy, modernizing and hardening the grid, and building new transmission. (See PNM Seeks Approval for Blackstone Acquisition.)
The Trump administration has sued California over its electric vehicle law, claiming it amounts to an illegal, state-specific mileage requirement for carmakers.
The U.S. Department of Justice filed the lawsuit on behalf of the National Highway Traffic Safety Administration (NHTSA), which under the Energy Policy and Conservation Act is supposed to establish “uniform, nationwide vehicle fuel economy standards.”
“Oppressive, expensive electric vehicle mandates drive up costs for American consumers and violate federal law,” Attorney General Pamela Bondi said in a statement March 12. “California is using unlawful policies from the last administration to create exorbitant costs for our citizens.”
The lawsuit names the California Air Resources Board (CARB) as a respondent, arguing that its carbon and zero-emissions vehicle mandates are related to fuel economy standards because they effectively increase fuel economy, which is determined by how much carbon is emitted from a vehicle’s tailpipe.
“CARB’s standards and mandates also undermine and conflict with NHTSA’s congressionally assigned role in establishing nationwide, uniform vehicle fuel economy standards,” the lawsuit said. “CARB’s CO2 standards and ZEV mandates create a patchwork of inconsistent regulation for vehicle and engine manufacturers in an area where Congress imposed a uniform, national approach.”
The Environmental Defense Fund called the lawsuit “reckless,” saying the ZEV standard protects Californians from health-harming and climate-destabilizing pollution.
“California’s standards are firmly anchored in our nation’s clean air laws,” EDF Associate Vice President Peter Zalzal said in a statement. “For more than half a century, and across both Republican and Democratic presidential administrations, California has adopted standards that cut pollution and result in enormous health benefits for people across the state.”
DOE Announces Funding for ATTs
The U.S. Department of Energy announced a $1.9 billion funding opportunity to accelerate upgrades to the nation’s power grid, saying the investments will meet rising electricity demand and resource needs while lowering costs for consumers.
DOE said the “Speed to Power through Accelerated Reconductoring and Other Key Advanced Transmission Technology Upgrades” opportunity builds on the Grid Resilience and Innovation Partnerships program, which offered up to $10.5 billion in funding over five years to states, tribes, utilities and others to strengthen grid resilience and innovation. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.)
“Thanks to President Trump, we are doing the important work of modernizing our grid so electricity costs will be lowered for American families and businesses,” U.S. Secretary of Energy Chris Wright said in a statement March 12.
DOE wants concept papers by April 2, and full applications are due May 20. The agency expects to make selections in August.
The funding was welcomed by the WATT Coalition, with its Executive Director Julia Selker saying ATTs can help address affordability.
“American utilities have demonstrated that ATTs could unlock gigawatts of grid capacity and save billions in electricity costs if scaled across the country,” Selker said. “This funding will help utilities scale up their ambitions and timelines for transmission grid modernization.”
