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March 16, 2026

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ISO-NE Details Initial Forecast of Capacity Auction Reforms’ Effects

ISO-NE has published initial data on how its proposed capacity market overhaul will affect resource accreditation, providing an indication of how the changes would affect capacity market revenues for different resource types.

The RTO presented the long-awaited impact analysis results to the NEPOOL Markets Committee on March 12. Reacting to the findings, several stakeholders expressed concern about the expected negative effects on storage, solar and demand response resources.

ISO-NE cautioned it has yet to finalize the proposed market changes and stressed the results do not reflect the effects of winter gas system constraints, which could significantly affect market outcomes in the winter season. The region should get a clearer picture of the potential effects when the RTO presents additional analysis in the coming months.

The Capacity Auction Reforms (CAR) project, intended to take effect in time for the 2028/29 capacity commitment period (CCP), would establish a new capacity accreditation framework; split annual commitment periods into six-month seasons; and cut the time between auctions and CCPs from more than three years to about one month.

The accreditation and seasonal changes would directly affect how much capacity each resource can sell in the market.

The RTO currently accredits resources based on a “qualified capacity” framework that does not account for factors including intermittency, fuel limitations and resource outage rates. Under the CAR proposal, ISO-NE would accredit resources based on their modeled ability to reduce energy shortfall. Accreditation values would be subject to change on an annual and seasonal basis depending on shifts in the characteristics of energy supply and demand in the region.

The timing and length of modeled shortall events would be significant factors in determining accreditation values. For example, short-duration storage would be more valuable for preventing short-duration shortfall events, while intermittent resources would be better at mitigating shortfalls that coincide with their production profile.

For the 2028/29 CCP, ISO-NE’s modeling estimated the median summer shortfall duration to be about three hours and the median winter duration to be about five hours.

ISO-NE plans to calculate accreditation values based on performance during marginal reliability impact (MRI) hours, which it defines as “hours where additional available capacity would reduce unserved energy in that hour or in a subsequent hour.”

MRI hours include periods of energy shortfall; when storage would be dispatched to avoid unserved energy; and when storage would be unable to charge. Enabling storage conservation or charging can reduce expected shortfall in subsequent hours, ISO-NE noted.

“While summer EUE [expected unserved energy] events last about three hours on average, incorporating the associated dispatch and charging hours shows that total MRI events are considerably longer — averaging roughly nine hours,” said Chris Geissler, director of economic analysis at ISO-NE. “Similar to summer, MRI event duration during winter is also longer than EUE events, with an average of 21 hours.”

The impact analysis shows a reduction in total systemwide capacity under the proposed rule changes. ISO-NE has not forecast how the changes would affect revenues but did estimate how the proposal would affect each resource type’s share of total system capacity.

The near-term results indicate an increase in capacity share for nuclear, non-intermittent hydro, wind, storage-limited oil and dual-fuel resources, and passive DR including energy efficiency.

In contrast, ISO-NE projected significant declines in capacity share for storage, solar and active DR resources.

For storage resources, duration would have a significant effect on capacity value. ISO-NE estimated the reliability value of a four-hour battery to be about twice the value of a two-hour battery in the summer and winter. For wind and solar, offshore wind performed better than onshore in both seasons, and sun-tracking solar outperformed fixed.

Accreditation values varied significantly by season for many resource types. Hydro, wind and oil resources with large storage capacity performed better in the winter, while imports, energy storage and solar performed better in the summer.

ISO-NE forecasts an increased capacity share for gas-only resources in both seasons, with a higher share in the winter because of higher maximum capabilities amid low temperatures.

However, the gas-only results may be misleading, as they do not account for winter pipeline constraints, which can be a major limiting factor for these resources. ISO-NE plans to account for these limitations through a separate “gas capacity demand curve,” which would reduce the winter capacity clearing price for gas-only resources that lack firm fuel arrangements. (See ISO-NE Introduces Approach to Modeling Gas Constraints.)

ISO-NE’s longer-term analysis indicated that adding significant amounts of solar and wind would decrease the per-megawatt reliability value of these resources by reducing their correlation loss-of-load events. For wind resources, the addition of 2,000 MW of capacity in 2035 reduced the reliability benefit of additional wind by about 20% in the winter and more than 40% in the summer.

Several participants expressed concern that ISO-NE is overestimating winter risks — including the duration of winter events — causing accreditation reductions for batteries and solar.

“As the accreditation results currently stand, the design will fail to send investment signals for renewables, demand response and energy storage to participate in New England’s capacity market,” said Alex Lawton, director at Advanced Energy United. “That will deter new supply from entering the market and put upward pressure on electricity prices as demand continues to grow.”

He said the impacts of the new gas demand curve remain a “major unknown,” but this “won’t solve the core problem of severely undervaluing advanced energy technologies.”

Lawton added that he remains “optimistic that the ISO will consider stakeholder feedback, run other scenarios in their model, and make changes that reflect realistic conditions and market behavior so that real system risk drives accreditation, not modeling choices.”

ISO-NE plans to present the results of two additional longer-term modeling cases in April. In May, the RTO plans to discuss the results of an analysis focused on the effects on market clearing outcomes. Outputs of this analysis will include estimates of clearing prices, consumer costs and capacity revenues by resource type.

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Virginia Legislature Wraps Up, Passes Clean Energy Bills

The Virginia Legislature wrapped up its main session with Democrats taking advantage of a wider margin in the House of Delegates and recently elected Gov. Abigail Spanberger (D) to push through bills favoring clean energy.

“The General Assembly has passed a slate of legislation squarely focused on making life less expensive for Virginians,” Spanberger said in a March 14 statement. “I’m particularly proud to see lawmakers pass our entire Affordable Virginia Agenda to drive down housing, healthcare and energy costs for Virginians across our Commonwealth. High costs are top of mind in every community — and our agenda directly responds to those concerns.”

She’s reviewing the legislation, which awaits her signature, with an eye toward advancing her affordability agenda, the governor added.

“We have a governor now, who got sworn in shortly after the session started here, too, who’s more supportive of clean energy solutions than her predecessor,” Advanced Energy United’s State Lead for Virginia Jim Purekal said. “‘Her’ predecessor — I like saying that, right? And, also, this governor is more engaged with the General Assembly than her predecessor was.”

While Democrats grew their majority in the House, the commonwealth staggers its state elections, so the Senate was unchanged, he added.

House Bill 397 and Senate Bill 809 are companion bills that require state agencies to develop regulations around re-entering the Regional Greenhouse Gas Initiative, which Spanberger called for after Virginia pulled out of the cap-and-trade market under previous Gov. Glenn Youngkin (R). (See Va. Air Board Approves RGGI Withdrawal.)

“For me, this is about cost savings. RGGI generated hundreds of millions of dollars for Virginia — dollars that went directly to flood mitigation, energy efficiency programs, and lowering bills for families who need help most,” Spanberger said in a speech shortly after taking office in January. “Withdrawing from RGGI did not lower energy costs. In fact, the opposite happened — it just took money out of Virginia’s pocket. It is time to fix that mistake.”

The legislature passed HB 895, which requires Dominion Energy to procure at least 16 GW of short-duration batteries (with 10 or less hours of storage) and 4 GW of long-duration batteries (greater than 10 hours) by 2045.

Other bills are meant to grow solar’s role in Virginia, with HB 711 requiring localities to review projects adequately before they can reject them and HB 807expanding the shared solar program for Dominion.

While Dominion has gotten approval for one natural gas plant through the State Corporation Commission and has plans for more in its integrated resource plan (IRP), Purekal said the focus of Democrats who control the government is on affordability and clean energy.

“We’re seeing a greater appetite for affordable options, and so that’s where the clean energy solutions really come into play,” Purekal said. “Because, you know, 10 years ago, we weren’t able to have this conversation about clean energy solutions. We’re seeing pivotal and drastic drops in cost now for solar and for storage and for wind. But we’re primarily talking about solar storage, really.”

Solar and storage are the fastest resources to deploy on a system seeing substantial demand growth from data centers, he added.

If Virginia doesn’t build its own natural gas plants, it will rely on imports from other states in PJM that are interested in building the facilities, said Stephen Haner. Haner is a former lobbyist who got to know energy policy in Virginia by working for Newport News Shipbuilding and now writes for the web publication Bacon’s Rebellion.

“There’s nothing passing that would ease the path for gas,” Haner said. “There are a number of things passing that create new impediments to gas. They’re rewriting the entire Integrated Resource Plan statute.”

HB 429 would amend the IRP process by requiring the use of the social cost of carbon and limiting Dominion’s options for flexibility around the Virginia Clean Economy Act, he added. It passed both houses on the session’s final day.

Rejoining RGGI when the states that historically shipped excess power east in PJM are not joining will lead to leakage, Haner said.

“You can see the pattern for the years before we were in RGGI,” he added. “You see one output for Dominion plants in the three years in RGGI, those plants all dropped, and then as soon as we got out of RGGI, those plants output went back up again — the gas plants that they’ve got. And that’s what’s going to happen.”

Data centers are driving the load growth in Virginia. SB 253 shifts grid upgrade and capacity costs onto them, Haner said. The bill passed both houses March 14.

The State Corporation Commission recently approved a new rate class for data centers. Judge Kelsey Bagot talked at EPSA’s conference earlier in March about how the regulator is dealing with the growth in data centers. (See EPSA Summit Held with ISO/RTOs in the Middle of the Political Debate.)

Dominion has about 20 GW of new demand under contract and more than 40 GW in its interconnection queue, but it’s unclear how much of that is “real.” New data centers must wait years to connect. They have the incentive to claim a large amount of capacity so they’re not left short when they get to the front of the line, Bagot said.

“You have that incentive on the data center side, at the same time that there truly is this demand that we need to build for,” she added. “And so, you’re trying to balance those two things. I think what we’ve really been working a lot with Dominion and our utilities on; is how can we shift some of that risk onto those entities that are asking for that new capacity? As opposed to having the other captive ratepayers cover the risks associated with potentially over-building for what folks in line say they need.”

Uncertainty around future demand is ubiquitous. It takes four to seven years to power a greenfield facility, while data centers can go up in two, Data Center Coalition CEO Josh Levi said at EPSA’s conference. Uncertainty is also present in the regulatory structure.

“The Virginia State Corporation Commission issued a ruling four months ago on large load tariffs. The General Assembly is in the process of rewriting it,” Levi said. “I mean, uncertainty is very much in play right now.”

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NRC Finds Minor Violations, Elevates Oversight of 5 Reactors

The Nuclear Regulatory Commission reports that 90 of the nation’s 95 operational commercial nuclear reactors met the highest category of performance in the 2025 oversight process.

The other five fell into the second performance category — indicating findings of low safety significance — and will face an elevated level of regulatory oversight including additional inspections and follow-up on corrective actions.

No reactors fell to the third or fourth performance categories, which trigger additional NRC oversight, or the fifth, which prompts a shutdown while problems are addressed.

The March 13 announcement of annual assessments for nuclear plants is a reminder of the level of regulation the NRC applies as it faces pressure by the Trump administration to streamline and speed up its regulatory process to facilitate a dramatic expansion of the U.S. nuclear power sector.

This has prompted concerns about the NRC being able to maintain its independence and its core mission of upholding the safety of aging infrastructure that harnesses potentially dangerous technology to produce 18% of U.S. electricity — 784,781 GWh in 2025.

The five reactors flagged for additional attention are Hope Creek in New Jersey, South Texas Project Unit 2, V.C. Summer in South Carolina and Watts Bar 1 and 2 in Tennessee.

PSEG’s Hope Creek got a notice of violation for “Inadequate Identification and Correction of Water Intrusion into Emergency Diesel Generator Lube Oil System” despite multiple indications of a degraded condition. This resulted in loss of probabilistic risk assessment function greater than the allowed outage time.

STP’s South Texas Project Unit 2 was flagged for “Failure to Establish Adequate Preventative Maintenance Instructions Leading to Multiple Component Failures” that resulted in “a partial loss of offsite power, an unplanned reactor trip, and subsequent loss of a safety-related motor control center during recovery activities.”

TVA’s Watts Bar 1 and Watts Bar 2 were dinged for “Failure to Maintain Public Address System” as procedure dictated. From February 2019 to June 2025, TVA failed to characterize as “loss of function” the continuous and progressive failure of multiple speakers important to emergency response and failed to take corrective action or implement compensatory measures.

All of these were determined to be of low safety significance — a white violation, the second-lowest color on a scale that runs from green to white to yellow to red. Other findings at each of the four reactors were classified green — non-violations or non-cited violations.

The NRC website lists numerous green but no white findings for the fifth reactor, Dominion’s V.C. Summer. The NRC’s March 11 letter to Dominion said V.C. Summer was being placed on the supplemental oversight list with the other four reactors because of a “white” finding in the third quarter of 2025.

This might be the “Inadequate Maintenance Strategy Resulting in Turbine-Driven Emergency Feedwater Pump Inoperability,” but that is listed as an “apparent violation” on the NRC website, with no color code.

The “green” findings at the five reactors span a wide range of failures or missteps. They include:

    • Failure to Control a Locked High Radiation Area.
    • Incorrect Rod Control Setup Resulted in Unanticipated Control Rod Withdrawal.
    • Failure to Maintain Quality of Lubricants.
    • Degradation of Main Generator Current Transformer 152C Causes Automatic Turbine and Reactor Trip.
    • Change to Emergency Diesel Generator Operating Procedure Without Obtaining a License Amendment.
    • Failure to Demonstrate Effective Control of a Maintenance Rule Scoped System.
    • Failure to Translate High Head Safety Injection Pump Maximum Shutoff Head into Motor Operated Valve Thrust Calculations.
    • Failure to Remove Rubber Shipping Grommet During Emergency Feedwater Pump Governor Installation.

The NRC deemed all the “green” findings notable enough to report, even if they were not worthy of citations or increased oversight.

Individually and in the aggregate, they are deemed not a threat to safety. But as a whole, they hint at the vast range of potential human errors in these huge, complex systems and point to the degree of scrutiny the NRC applies in seeking and documenting those failures.

President Donald Trump took aim at the NRC’s layers of regulation in one of four May 2025 executive orders intended to streamline nuclear power development. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.)

The order that focuses on the NRC (EO 14300) seems to be aimed at expediting the approval of new reactors and technology, a stated priority for Trump. But it is blunt in criticizing the entire approach of the nuclear watchdog, as when the president cited “a myopic policy of minimizing even trivial risks.”

He wrote: “Instead of efficiently promoting safe, abundant nuclear energy, the NRC has instead tried to insulate Americans from the most remote risks without appropriate regard for the severe domestic and geopolitical costs of such risk aversion.”

And: “Beginning today, my administration will reform the NRC, including its structure, personnel, regulations and basic operations.”

Where this directive translates to action and what it means for routine processes such as the annual assessments for 95 nuclear reactors remain to be seen, but clarity may be coming.

The baseline inspections now total 2,012 hours per year, according to a Feb. 6 NRC memo recommending revisions. Attachments to the memo include a specific 38% suggested reduction in hours, organizational changes and potential changes to more-than-minor findings.

These last changes could include reducing the number of publicly reported green findings in a way that would not reduce their effectiveness but would reduce the chances of the public getting the wrong impression about the safety implications of those findings, or about the performance of the reactor’s license holder.

The NRC’s website indicates three of 28 planned revisions of rules in response to EO 14300 had been completed as of March 6.

And in January, the Department of Energy eliminated or rewrote numerous safety rules including ALARA, a longstanding core principle that dictated nuclear operators must keep radiation exposure As Low As Reasonably Achievable.

As this wholesale revision moves forward, cutting-edge technology and Cold War-era infrastructure are mingling in NRC’s purview: Dozens of advanced reactor designs are in various stages of completion while nuclear plants that went on the drawing boards in the 1960s and 1970s continue to operate with the equipment and technology of that era.

Constellation’s Limerick Clean Energy Center made news in January with the announcement the NRC had approved the nation’s first-ever wholesale replacement of a nuclear plant’s analog safety systems with a single digital system. (See NRC Approves 1st Digital Conversion of Nuclear Plant Safety Controls.)

This is all the more remarkable when considering that even at 40 years old, Limerick is among the newer plants operating in the U.S. — commercial nuclear power construction all but ceased in the early 1990s.

Operators of some the oldest existing facilities are considering relicensing requests that could extend their operating lifespans to 80 years.

So how did the oldest components of the aging fleet fare in the NRC’s annual assessment?

Constellation’s Nine Mile Point Unit 1 entered commercial service Dec. 1, 1969, and its R.A. Ginna on June 1, 1970. Both recorded capacity factors above 94% in 2022-2024, compared with a national median of 91%. And neither got a writeup from the NRC in 2025.

Nine Mile Point Unit 1 got a handful of “green” findings, none of which were cited as violations. Ginna got just one “green” finding — a non-cited violation for failing to rectify a grease packing condition in a valve actuator the vendor had warned about.

On the other end of the scale, Southern Nuclear’s Vogtle 3 and Vogtle 4 are the newest reactors (and the only “new” ones) in the U.S. fleet, entering commercial operation on July 31, 2023, and April 29, 2024, respectively.

Vogtle 3 got two non-cited “greens,” but it was the same finding reported under two categories.

Vogtle 4 got three different “green” findings a combined eight times under three categories, none resulting in citations.

One of them stands out as a strikingly low-tech flub in such a high-tech setting: propping open fire doors without maintaining a fire watch.

The number of reactors placed on expanded supervision in 2025 is slightly less than the annual average in the 2020s. Nine were flagged in 2024, six in 2023, six in 2022, two in 2021 and four in 2020. Of those, one was placed in the third performance category and the rest in the second performance category.

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EDAM Utilities Moving to Develop RA Program

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.

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BPA’s Exit from WEIM Necessary for Markets+ Preparation, Staff Says

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.”

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Abbott Appoints Rhode to Texas PUC as 5th Member

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.

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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.

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

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.