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March 16, 2026

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SPP RTO Expansion Members Affirm April 1 Go-live

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.

“Joining the SPP RTO expansion marks the culmination of nearly a decade of dedicated work by our employees and a major milestone for our owner communities as we advance toward a non-carbon energy future,” Platte River CEO Jason Frisbie said. “This integration will provide broader access to renewable energy resources and allow us to realize the cost efficiencies that come with participating in a fully integrated energy market.”

SPP said several other load-serving and embedded entities that are part of WAPA’s Colorado-Missouri (WACM) balancing authority also will become part of the SPP RTO on April 1. Those listed above were the signatories to RTOE’s commitment agreement and would have been financially accountable for sunk costs if the expansion effort had been terminated before go-live.

Basin, MEAN, Tri-State and WAPA’s UGP-East region already are RTO members of SPP, as is United Power. The Colorado utility was the first western distribution utility to join the SPP RTO in 2022.

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.

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A Cautionary Tale on Forecasts

By Kenneth W. Costello

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. 

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BPA Releases Draft Decision Solidifying Markets+ Choice

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.

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Monitor Urges PJM to Make Data Centers Bear Grid Burden

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.

The second capacity auction, held in December for 2027/28, procured 6.6 GW less than PJM’s Region Reliability Requirement. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement and PJM Capacity Prices Hit $329/MW-day Price Cap.)

“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.

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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.

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NERC RSTC Prepares for New Role in Standards Process

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.

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N.M. Regulators Order Blackstone to Explain TXNM Stock Purchase

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.”

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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 acquisition has received approval from the Public Utility Commission of Texas and TXNM Energy shareholders. FERC approved the deal in February. (See FERC Approves Blackstone’s $11.5B Acquisition of PNM.)

The acquisition still needs approval from the Nuclear Regulatory Commission and the New Mexico PRC.

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Policy Roundup: DOJ Sues California on EVs; DOE Offers $1.9B for ATTs

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.”

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Renewable Portfolio Standards Not Boosting Electric Rates, MIT Study Finds

A new MIT study posits that while retail electric rates are higher in states that have renewable portfolio standards, the standards are not to blame. Instead, utility-scale wind and solar generation show a weak correlation with lower prices, the authors say.

More likely drivers of rate increases include cost-recovery mechanisms for rooftop solar embedded in certain tariffs, grid-hardening necessitated by climate change and the proliferation of data centers.

The MIT Sloan School of Management announced “Renewables and Electricity Affordability: Untangling Correlation from Causation” on March 9.

The correlation between renewable energy policies and electricity prices is relatively straightforward, but correlation famously does not imply causation, and as the title suggests, much of the study is devoted to separating and explaining the factors and causes at play.

Professor Christopher Knittel, MIT Sloan’s associate dean for climate and sustainability, and Fischer Argosino, a graduate researcher at the MIT Center for Energy and Environmental Policy Research, analyzed U.S. electricity and utility spending data from 1998 to 2023, including residential prices, power generation mixes, utility spending and state renewable portfolio standards (RPS).

They said the opposite rate impacts they found for utility-scale and distributed renewables are due partly to the fundamental differences in their design.

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“Energy generated by large-scale solar plants, for example, comes with lower transmission, distribution and maintenance costs for utilities, and these efficiencies can be passed on to the consumer,” Knittel said in the news release.

But rooftop solar creates a two-way system out of distribution networks that were designed for a one-way flow from central generation plants to consumers, the authors said. They found this bi-directional flow was strongly correlated with higher operations and maintenance costs, as utilities managed the complex harmonization of thousands of decentralized generators across an aging grid.

“Our antiquated distribution networks are struggling to manage these flows,” Argosino said. “When we defer essential grid upgrades while simultaneously incentivizing rooftop exports, we create an operational strain that inevitably shows up as higher costs on everyone’s utility bills.”

But not uniformly higher. State financial incentives for rooftop solar can shift some of the costs of maintaining the grid onto ratepayers who do not have solar panels, even though solar owners derive full benefit of the grid to power their homes and export their solar panels’ output.

This exacerbates existing inequities, the authors said — those who put solar panels on the roofs of their homes are likely to be wealthier than those who do not.

Knittel and Argosino say decarbonization need not be at odds with electric rate affordability, if policies can be updated to match the changes in technology.

They suggest prioritizing utility-scale wind and solar to maximize economy of scale, modernizing distribution networks and adjusting fee structures so that all who benefit from grid infrastructure contribute to the cost of its maintenance.

The research is built on data from the U.S. Energy Information Administration, FERC and the Lawrence Berkeley National Laboratory. The years studied span a period before, during and after the widespread adoption of state RPS.

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CAISO Developing Large Loads Technical Standards

Although large loads are not new to California or the West, CAISO is formulating technical standards that address their potential boom over the coming years.

Developing the standards is a critical step to ensure artificial intelligence data center and electric vehicle large loads will reliably and safely interconnect to CAISO’s grid. The ISO established a working group on the issue in 2025 and opened a new large loads initiative Feb. 27.

“Large loads are a topic of extreme urgency and interest lately, especially with the emergence of artificial intelligence,” Danielle Mills, CAISO principal of infrastructure policy development, said at a March 10 workshop. “But we also consider large loads to be more than just data centers and AI. While data centers do present the largest use case, we are also looking at things like electric vehicle charging, electrification of buildings, and industrial processes and agricultural processes and the like.”

CAISO’s 2025/26 transmission plan shows 4.5 GW of data center capacity online currently, with an additional 1.8 GW added by 2030 and 4.9 GW more by 2040.

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“We do proactively plan for these types of large loads through the integrated planning process with the California Energy Commission,” Mills said. “We are always trying to stay ahead of any new demand for large loads, but we are aware that this is really dynamic space right now and that we are seeing increasing numbers of large load interconnection service applications at the utilities.”

CAISO is developing a definition of what constitutes a large load and new requirements for voltage and frequency ride-throughs, along with setting limits on rapid ramping and pulsating load levels. (See CAISO Examines ‘Pulsating’ Data Center Loads.)

One topic of concern is how large loads consume power or reduce load during grid disturbances, such as during a post-fault active power recovery (PFAPR) moment.

“Our mission is to ensure large loads continue to draw power from the grid during and following grid disturbances,” Ebrahim Rahimi, CAISO senior adviser for transmission planning, said at the workshop.

During a PFAPR, large loads will be allowed to reduce their power consumption during and immediately after severe faults, Rahimi said. However, after the fault is cleared and voltage returns to normal, the power consumption from the grid should be required to recover to — or close to — pre-disturbance levels within a given time, Rahimi said.

Another concern is persistent small load fluctuations. Even modest but continuous fluctuations in load can produce voltage flicker or unacceptable variations in local power quality, CAISO staff said in a large loads issue paper.

Over time, these load fluctuations might increase mechanical fatigue in equipment, such as in rotating machines and transformers. Requirements will need to ensure that persistent small-signal load variations remain within acceptable limits, staff said.

CAISO is also following NERC’s formulation of national standards for large loads, such as for computation loads from AI training centers. Rahimi said those standards will be ready for approval at the end of 2026, and NERC plans a large load Level 3 alert in May or June.

NERC issued a Level 2 alert on the issue in 2025 and will release a related report soon. (See Panelists Say More Work Needed on Large Load Risks.)

CAISO has not yet decided where large load technical requirements ultimately will be documented and enforced, he said.

“Although we are coming up with these technical requirements … how these requirements will be documented has not been decided at this point,” Rahimi said. “The whole idea is to come up with these requirements and ensure reliability, and then at a later stage a decision will be made about where to document them.”

CAISO plans to publish a straw proposal in April that includes technical requirements, transmission service offerings and cost-allocation methods for large loads.

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Industry Seeks Immediate Halt to Con Edison Storage Policy

New York energy storage and solar trade groups are seeking an immediate end to what they say is an effective freeze on interconnection of distributed storage facilities by the state’s largest investor-owned utility.

The New York Battery and Energy Storage Technology Consortium (NY-BEST) and New York Solar Energy Industries Association (NYSEIA) filed a petition for emergency rulemaking March 11 asking the Public Service Commission to restrict Consolidated Edison from applying an “unlawful and arbitrary” review standard for New York City storage projects.

They charge that Con Edison’s review process was implemented without legal justification, is causing irreparable harm to the storage industry and is exacerbating grid reliability concerns in the region. There was no need to change the way storage is studied under the state’s Standardized Interconnection Requirements, they argue, but if such a need did exist, there are much better ways to address it.

The utility stood by its actions.

“Con Edison supports battery storage as a critical part of New York’s clean energy transition, and the rapid growth in applications reflects strong market momentum,” Vice President for Distributed Resource Integration Raghu Sudhakara told RTO Insider via email March 11. He added, however, that the sector’s expansion must be carried out in a way that does not shift new infrastructure costs onto the utility’s ratepayers.

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The disagreement has been fermenting for months, and it spans PSC cases on energy storage (18-E-0130), distributed generation and storage (24-E-0621) and New York City reliability needs (25-E-0764).

NYISO and the PSC both have identified grid reliability risks looming in and near New York City, and both have taken steps to address it. (See N.Y. PSC Directs Con Edison to Create Plan to Avert Energy Shortfall.)

Battery energy storage systems (BESS), with their dispatchable output and lack of on-site emissions, are one of the potential solutions in the densely populated region; over 2,000 MW of capacity have been proposed.

On Aug. 15, 2025, Con Edison notified developers that it had placed on hold all BESS proposals seeking interconnection at seven constrained substations. It added 21 more substations to the list Sept. 16.

NY-BEST on Jan. 13 petitioned the PSC for “urgent action” on the utility’s move. It supported its call for immediate relief from Con Edison’s new restrictions on BESS interconnection with a white paper outlining suggested changes in interconnection and market rules to better enable storage to provide maximum value to the grid.

The infrastructure upgrade requirements resulting from Con Edison’s changes to the Coordinated Electric System Interconnection Review rendered most of the energy storage projects proposed in New York City economically unviable, NY-BEST said.

The organization also flagged the “fundamental misalignment between utility financial incentives and New York’s energy affordability goals”: A utility earns a regulated rate of return on capital expenses such as infrastructure upgrades, but not for facilitating third-party BESS interconnections.

The PSC on Feb. 20 solicited public comment on the petition but took no action to change or limit Con Edison’s practice.

On Jan. 14, Con Edison told the PSC there were 115 MW of operational BESS and 865 MW with executed interconnection agreements in the utility’s service area as of Dec. 31. But the interconnection queue for BESS proposals with 5 MW or less capacity had reached 2,500 MW, up 300% in two years.

That is a quarter of its 10-GW peak load in 2024, Con Edison wrote.

A problem, it said, was that the BESS proposals were being concentrated in areas with less expensive land and more favorable zoning — 65% of the storage megawatts in the queue would be supplied by just 10 of the company’s 63 substations. More than 20 substations were at or near hosting limits.

Because BESS typically would seek to recharge overnight, full buildout would make night peaks exceed daytime peaks and require new infrastructure that otherwise would not have to be built. Con Edison sought to put the developers on the hook for the resulting costs, which it said could run in the $100 million to $1 billion-plus range.

“As the market scales, storage must deliver real benefits to customers — not drive new infrastructure costs that show up on bills — which is why we are working with regulators and stakeholders to align growth with real-world grid conditions preserving grid reliability while also protecting affordability,” Sudhakara explained. “Without reforms, current policies risk shifting significant new costs to customers, undermining both affordability and the long-term success of storage.”

NY-BEST and NYSEIA in their petition attempt over the course of 26 pages to punch holes in the legality, accuracy and necessity of Con Edison’s steps to carry out the priorities Sudhakara cited.

They ask the PSC for an emergency rule to immediately block Con Edison from using the restrictive requirements for distributed storage applications and keep the ruling in place while it considers NY-BEST’s Jan. 13 petition.