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April 16, 2026

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ISO-NE Details Proposals to Cut Costs of Day-ahead Ancillary Services

ISO-NE has detailed proposed changes to its day-ahead ancillary services (DAAS) market to address higher-than-expected costs.

The RTO is working to expedite a series of market reforms, initially recommended by its Internal Market Monitor, intended to increase market participation and lower costs.

The NEPOOL Markets Committee heard about the proposed changes April 14. The RTO aims to implement the changes Oct. 22, subject to FERC’s approval.

The implementation of the DAAS market has led to around $1 billion in incremental costs since ISO-NE launched the market in March 2025, according to the IMM. This cost vastly exceeds the estimate included in ISO-NE’s initial impact assessment, which, based on market data from 2019 to 2021, concluded that the new market would increase costs by an average of $140 million annually.

Already elevated prices following the launch of the market were exacerbated by prolonged cold weather that led to record wholesale costs over the past winter. (See 2025/26 Most Expensive Winter in History of ISO-NE Markets.)

“Changes in market fundamentals alone do not fully explain the observed level of DAAS costs,” the IMM wrote in a February memo. “Participation has been lower, and offer prices higher, than assumed in the [impact assessment].”

While ISO-NE announced its support of three “narrowly targeted” DAAS market changes in February, New England states and consumer advocates have continued to push the RTO to act as quickly as possible.

“The unprecedented cost increases documented by the IMM are imposing substantial and unanticipated burdens on electricity consumers across New England, including those in New Hampshire, and demand urgent attention to protect ratepayers,” wrote New Hampshire Gov. Kelly Ayotte (R) in a letter to the ISO-NE board in mid-March.

The IMM’s recommendations include:

    • Increasing the strike price to more accurately reflect the short-run marginal costs of most resources participating in the market.
    • Decreasing the forecast energy requirement to reflect the low levels of participation of front-of-the-meter renewables in the day-ahead market.
    • Potentially reducing the non-performance factor associated with the 10-minute reserve requirement.

At the April 14 Markets Committee meeting, ISO-NE gave an overview of its proposals to implement the first two recommendations. It plans to discuss its proposal for the third recommendation at the Reliability Committee meeting on April 22, and present on estimated cost effects at the Markets Committee in May.

Increased Strike Price

In the DAAS market, the strike price is a settlement component used to determine closeout charges. When the real-time locational marginal price (LMP) exceeds the strike price, resources committed in the market receive the day-ahead reserve clearing price plus the strike price, but forgo real-time revenues associated with higher real-time prices. If a resource does not fulfill its day-ahead obligation, the difference between the strike price and the real-time LMP is a key component for determining its net settlement liability.

ISO-NE has said a lower strike price will increase resources’ opportunity costs, increasing offer prices in the DAAS market. A strike price lower than a resource’s short-run marginal costs would not increase the resource’s incentives but would increase closeout risks, potentially reducing market participation, said Ben Ewing of ISO-NE.

Increasing the strike price would have the reverse effect but generally would reduce resources’ performance incentives by lowering the financial liability associated with failing to perform, the RTO has indicated.

“Generally, setting a higher strike price value will tend to lower consumers’ costs,” said Matthew White, chief economist at ISO-NE, in testimony submitted to FERC in 2023 (ER24-275). “This is because a higher strike price value lowers sellers’ opportunity costs of acquiring day-ahead ancillary service obligations. That, in turn, will tend to decrease sellers’ day-ahead ancillary service offer prices, and lower the total costs.”

In the wake of high DAAS prices, ISO-NE proposes to establish a strike price floor “based on characteristics of an efficient [combustion turbine] using the lowest-cost distillate fuel.”

Combustion turbines have received about 65% of DAAS awards cleared, while combined cycles have received about 29%. All other resources have received less than 7% of awards.

ISO-NE’s proposal is intended to increase the strike price so that it’s “better aligned with the [short-run marginal costs] of most sellers,” Ewing said. He acknowledged this change would reduce incentives for some gas-fired resources during low-load periods, but that the change should largely maintain incentives during high-load hours or periods with elevated reliability risk.

Based on historical DAAS market data, ISO-NE’s proposed methodology would lead to an average strike price floor of $141/MWh, which would increase the strike price in about 90% of hours, he said.

He added that ISO-NE analysis indicates the change would lead to a 41-47% decline in the amount of DAAS awards that retain the full incentives of the current design during low-load hours, compared to a 12-16% decline in the number of awards that receive the full incentives during high-load hours.

Forecast Energy Requirement Reduction

Under the current rules, the forecast energy requirement (FER) constraint in the DAAS market equals ISO-NE’s day-ahead energy forecast. It determines the need for energy and energy imbalance reserves, the latter of which is a new ancillary service intended to close the gap between the demand forecast and the amount of demand that clears in the day-ahead market.

ISO-NE noted that front-of-the-meter wind and solar resources consistently clear less day-ahead energy than they are forecast to produce, causing the FER to underestimate their contributions. On average, about 40% of forecast front-of-the-meter wind and solar energy clears in the day-ahead market.

“As a result, the DAM may commit additional resources or clear other forms of supply in place of [wind and solar resources] to meet the load forecast,” Ewing said. “Procuring more supply than is needed to satisfy a reliability requirement can be costly and inefficient.”

To address the issue, ISO-NE proposes to reduce the FER demand quantity by the difference between the amount of wind and solar forecast and the amount of wind and solar that clears in the day-ahead market. ISO-NE data indicate this would reduce the FER demand quantity by an average of 422 MW, Ewing said.

The change “directly addresses the inefficiency observed by the IMM,” can be made relatively quickly and will not lead to issues if renewable resources owners begin to offer a larger share of energy into the day-ahead market, he added.

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CPUC Considers New Rate Design for Data Centers, Large Loads

The California Public Utilities Commission is considering whether new tariff rates are needed for data centers and other large loads to help prevent those entities from creating stranded assets and shifting costs to other ratepayers.

The tariffs would be part of new rate design policies for residential and nonresidential customers, the CPUC said in an order instituting rulemaking (OIR) that was approved at an April 9 voting meeting.

The commission wants to create new rates that more accurately reflect the cost of providing service, send price signals that support efficient use of grid infrastructure, and allocate costs fairly across all customers, the CPUC said in the OIR.

The CPUC asked stakeholders whether rate designs and tariff service agreement terms have been adopted in other states or regions for data center customers. Specifically: Have other states or regions created a separate customer class for data center customers? If so, should these rates be applicable in California?

California Senate Bill 57 requires the CPUC to assess the ways in which new large data center loads will affect rates. Electricity affordability is an urgent issue due to recent rate increases from wildfire-related costs and rapid load growth, such as from data centers, the commission said in the OIR.

In July 2025, the CPUC partly approved a new rule that will make it easier for artificial intelligence data centers and other large customers such as EV charging stations to complete transmission connection projects in Pacific Gas and Electric’s territory. (See CPUC OKs New PG&E Rule to Speed Tx Connections for AI Data Centers, Others.)

In February, the CPUC ordered load-serving entities to procure 6 GW of new capacity to meet forecast data center and electric vehicle loads — among other new demand — in the state. (See CPUC Orders Massive 6 GW of New Capacity to Feed Data Centers, Other Loads.)

And in March, the commission approved construction of new transmission facilities for a 49-MW data center in Sunnyvale, but to do so, it relied on a process typically used for distribution projects. (See CPUC OKs Data Center Tx Upgrades Using Distribution Refund Approach.)

Along with large loads and data centers, wildfire mitigation costs have “grown substantially since 2019” for the state’s investor-owned utilities, the CPUC said in the OIR.

From 2019 to 2024, the CPUC authorized IOUs to recover about $40 billion in wildfire costs. In 2024, PG&E’s wildfire revenue requirement was about 27% of the utility’s total revenue requirement. For SCE and San Diego Gas & Electric, the wildfire revenue requirement was about 17% of the IOUs’ total revenue requirement. These amounts translated to an average annual cost of $250 to $490 for residential customers.

Wildfire costs are forecast to continue to rise in the coming years based on the IOUs’ 2026-2029 wildfire management plans, according to the OIR.

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CenterPoint Asked DOE Not to Extend Emergency Order for Culley Coal Plant

Prior to the U.S. Department of Energy’s March extension of emergency orders for the F.B. Culley Generating Station, owner CenterPoint Energy asked the department not to re-up the stay-open mandate.

According to a letter obtained by Indiana’s consumer advocate Citizens Action Coalition, CenterPoint warned that necessary expensive upgrades and the lengthy outages they would require to keep the coal plant running are “neither practical nor financially responsible.”

The Feb. 17 letter from CenterPoint Indiana Operations President Mike Roeder to Energy Secretary Chris Wright explained that maintaining Culley’s Unit 2 “will require substantial investment to support an inefficient and increasingly unreliable asset, rather than advancing affordable and reliable service for customers in southwestern Indiana.”

Roeder requested DOE allow its original Dec. 23, 2025, emergency order under Section 202(c) of the Federal Power Act to expire and abstain from issuing future emergency edicts.

According to CenterPoint’s data for the 48 days between Dec. 23, 2025, and Feb. 8, 2026, Culley Unit 2 was:

    • On outage due to equipment issues for 26 days.
    • On reserve shut down (available but not economically dispatched by MISO) for five days.
    • Available but limited to between 45 MW and 78 MW net output “due to maintenance issues” for the remaining 17 days.

Roeder said unavailability and underperformance dogged a struggling Unit 2 during MISO’s maximum generation emergency on Jan. 24 and continued through the dayslong winter storm.

“Unit 2’s performance during the recent MISO cold weather event underscores a pattern of unreliability of that unit. Although the unit was dispatched on Jan. 24 and Jan. 25, 2026, Unit 2 was limited to 45 MW (net) due to a significant derate. One day later, on Jan. 26, systemic equipment failures forced another outage, further demonstrating the unit’s ongoing inability to provide dependable service,” Roeder wrote.

CenterPoint estimated that for Unit 2 to become operational, it could require more than $20 million of repairs and replacements, including between $1.9 million and $2.5 million for acid cleaning of the boiler and new boiler tubes alongside an “unavoidable” $14 million to $18 million turbine overhaul.

Roeder said Unit 2’s turbine-generator is “operating beyond the original equipment manufacturer’s overhaul specifications, significantly increasing the risk of catastrophic mechanical failure.” He estimated the plant would require a 10-week outage for the work.

Roeder said CenterPoint may encounter “additional operational factors” that could drive repair costs even higher.

“These factors make clear that extending the life of Unit 2 is neither practical nor financially responsible, underscoring the need for a more prudent and economically sound path forward,” he said.

Roeder included Indiana Gov. Mike Braun (R) in the correspondence.

DOE did not honor CenterPoint’s request and cited emergency conditions and “year-round resource adequacy concerns” within MISO when it ordered Culley in late March to remain online for another 90 days through at least June 21, 2026.

But Roeder called DOE’s narrative into question. He said MISO and the Organization of MISO States’ 2025 Resource Adequacy Survey showed that members expect to meet their capacity needs through 2031. He also invoked NERC’s 2025 Long-Term Reliability Assessment, which expects the RTO to have a surplus ranging from 3.4 GW to 5.8 GW on hand for summer 2026.

“We have adequate generation capacity — without Unit 2 — to meet MISO’s planning reserve margin requirement through the 2027/2028 planning year, reflecting our commitment to continued system reliability,” Roeder wrote.

Roeder pointed out that Unit 2 accounts for less than 1% of the total installed capacity in MISO Midwest and said CenterPoint’s integrated resource plans since 2016 have shown that Culley’s retirement is the best way to dodge the “costly investments to maintain operational reliability and environmental compliance” that keeping the unit online would demand.

CenterPoint planned to retire Culley at the end of 2025.

Citizens Action Coalition (CAC) Program Director Ben Inskeep said CenterPoint’s letter demonstrates there’s no grid emergency as DOE purports and “that coal plants are too unreliable, expensive and polluting to continue operating.”

“The federal government’s unlawful orders directing utilities to keep dilapidated and unreliable coal plants open at a massive and growing cost to consumers is an outrageous abuse of power that will cause Americans’ energy bills to continue to increase,” Inskeep said in an April 16 press release accompanying the letter’s reveal.

The CAC called Culley’s level of outages and derates through the coldest portion of winter “shocking.”

The CAC is one of multiple public interest organizations challenging DOE emergency orders at the D.C. Circuit Court of Appeals. (See Groups Contest Indiana Coal Plants’ Emergency Extensions at D.C. Circuit.)

MISO contains multiple coal units DOE blocked from retiring. In addition to Culley Unit 2, DOE also forced Northern Indiana Public Service Co.’s R.M. Schahfer Plant and Consumer Energy’s J.H. Campbell Plant in Michigan to stay open.

At an April 16 MISO Market Subcommittee meeting, Independent Market Monitor Carrie Milton reported that coal use in winter 2025/26 fell across MISO year-over-year despite DOE’s efforts to keep multiple coal plants online.

CenterPoint, along with Indiana’s other four investor-owned utilities, is facing an affordability inquiry before the Utility Regulatory Commission for growing customer bills. (See Indiana Commission Opens Affordability Inquiry into Utilities.)

“We have a real short-term crisis here,” URC Chair Andy Zay said at the commission’s March 24 hearing. “I think we’re creeping up into what we call the lower-middle class with this affordability crisis. The reality is, on Main Street, there are people that simply can’t afford to pay these bills.”

The commission is conducting a series of 10 listening sessions across the state throughout April. Zay said the commission would review residents’ narratives and decide whether to take formal or informal action.

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ERCOT Prelim Forecast: 430% Demand Increase by 2032

ERCOT has filed a preliminary long-term load forecast for discussion at the April 17 Texas Public Utility Commission open meeting that predicts 367 GW of demand by 2032, a staggering 430% increase over its current peak demand of 85.5 GW.

The grid operator attributed much of the forecast to large loads identified by transmission and/or distribution service providers’ (TDSPs) submissions based on criteria established in ERCOT’s 2026 Regional Transmission Plan, as required by state law.

Staff expressed concern in the filing about using the preliminary forecast values as a modeling input for its 2026 reliability assessment or other transmission and resource adequacy analysis. They want to consult with PUC staff to evaluate whether it is appropriate to adjust the forecast, noting state law allows it “if the adjustment is supported by actual historical realization rates or other objective, credible, independent information.”

ERCOT projects 2026’s summer peak load will fall between 90.5 GW and 98 GW. The preliminary forecast projects demand to hit 112 GW this summer.

The grid operator cautioned the forecast is not a prediction of what will be built, but a preliminary snapshot to inform its transmission planning and resource adequacy reporting, and that adjustments should be expected as the data is further studied, reviewed and finalized for use in the planning process.

“Texas is experiencing exceptional growth and development, which is reshaping how large load demand is identified, verified and incorporated into long-term planning,” ERCOT CEO Pablo Vegas said in a statement. “As a result of a changing landscape, we believe this forecast to be higher than expected future load growth.”

The forecast was developed from data that included ERCOT’s base economic forecast and information provided by TDSPs that work directly with large load customers (75 MW and above) and others.

Data centers, cryptocurrency mining and industrial and oil and gas processes comprise the bulk of the large loads. Data centers alone account for 228 GW of the TDSP’s 243 GW submissions for 2032. Oncor, with a North Texas footprint that is ground zero for large loads, has submitted 109 GW of the large loads.

ERCOT said in March that its queue of interconnection requests from large load customers has hit 410 GW. (See ERCOT Large Load Interconnection Queue Hits 410 GW.)

That has led to the grid operator’s proposed batch process, in which it will study clusters of interconnection requests rather than individually. ERCOT staff are working on a transitional batch study, called Batch Zero, that will streamline the interconnection process and set the stage for subsequent batches. They plan to bring their proposal to the Board of Directors for its consideration in June. (See ERCOT Batch Process Rules Headed to Stakeholders.)

Assuming board and PUC approval, the transitional Batch Zero study would begin July 10 and run into 2027. Loads that had validated studies as of March 4 will be eligible for Batch Zero. Loads without validated studies will have to wait until March 1, 2027, when Batch 1 is scheduled to begin.

A first cut filed with the PUC April 10 indicates 14 GW of requests meet the requirements to be included as base load in Batch Zero. An additional 9.2 GW still could qualify as base load when their studies are checked for validity. And 18.5 GW more requests could be included as studied load in Batch Zero but face a July 10 deadline to be deemed as base load should their studies be valid.

ERCOT said in its 2025 State of the Grid report that average annual electric consumption in its region is increasing by 5% over multiple years. The market has added 62 GW of new generation, primarily renewables and batteries, since 2021. An additional 450 GW of active requests sit in ERCOT’s generator-interconnection queue, as of January 2026.

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MISO Rethinks Maintenance Margin Limits to Deter Capacity Outages at Peak Times

MISO said it will pay attention to its maintenance margin while it considers changes to its 31-day limit on outages for capacity resources.

MISO staff said the RTO’s maintenance margin — used to schedule planned generation outages and grant capacity accreditation exemptions — is at times off-base in its risk-to-supply adequacy judgment when owners request downtime for maintenance.

MISO has been toying with the idea of altering its 31-day outage rule, which has been in effect since FERC approval in August 2022. (See MISO Re-examining Monthlong Outage Limit for Capacity Resources.) Now, MISO said its maintenance margin could use some work to maintain reliability.

“We will be evaluating it and making sure it’s accurate. Our goal is to make sure it’s completely accurate,” MISO Market Design Engineer James Curtis said during an April 14 Reliability Subcommittee teleconference.

Curtis said the maintenance margin shows too much wiggle room for outages in high-risk months in summer and winter. He said the maintenance limit allows 40 GW of planned, urgent and emergency outages for June 2026.

“I think we can all agree that 40 GW of outages in the summer is totally inappropriate,” MISO Market Design Manager Davey Lopez said. “That’s why we’re having this discussion.”

Curtis said when MISO’s maintenance margin is set too high, resources can take outages that put reliability at risk while still getting accreditation and non-compliance penalty exemptions.

MISO’s maintenance margin was introduced in 2013 and uses the average of the past 30 years of load data to calculate available reserves. MISO said the 30-year amalgamation results in only typical operating days, when it also should represent days with choppier operations. MISO said the 5 GW of import capability it assumes from neighboring regions when calculating the margin is too optimistic. It said a more realistic average ranging from 1.4 GW to 2.5 GW depending on the season is in order.

“It is critical that the maintenance margin is accurately representing the number of megawatts that can go on outage without causing reliability risk to the grid,” Curtis said.

MISO said it observed an average 20 GW in unplanned outages over summer 2025, a 42% spike over previous years, which contributed to tighter operating margins and ultimately four maximum generation emergencies.

Curtis said generation owners are planning outages “intentionally to avoid” MISO’s capacity replacement non-compliance charge by “straddling seasons” so the outage can occur in a month of one season and continue into another month of the next season, exceeding the monthlong limit without technically violating the limit.

Curtis said while MISO anticipated some of that type of behavior, it didn’t expect it to be at the scale generation owners are using it.

MISO expects capacity resource owners to either procure replacement capacity or pay penalties if they are offline for more than 31 days in a single season. They must notify the RTO 120 days in advance of planned outages to be exempt from capacity accreditation reductions. If MISO’s maintenance margin is above zero for a given period, resources can get planned outage exemptions for their accreditation.

MISO imposes a capacity replacement non-compliance charge when resource owners conduct outages longer than 31 days and fail to replace the zonal resource credits they signed up for. The charge is calculated by multiplying the capacity shortfall by the sum of auction clearing prices and the area’s cost of new entry.

Minnesota Power’s Tom Butz said he didn’t see how a more exacting maintenance margin would allow generation owners to take proper, long-term maintenance outages when necessary. Butz said MISO might consider allowing longer outages in spring and fall.

Butz previously asked for a better understanding of MISO’s maintenance margin and what calculations are used to determine when the system is tight.

“It just seems like it’s a post card that comes in the mail,” Butz said, adding that the maintenance margin seems like the “black box of black boxes.”

Curtis said MISO wants make sure generation owners have the necessary time for planned outages “so they’re not taking forced outages when something breaks.” He said MISO plans to discuss outage limits and monetary penalties further in upcoming meetings of the Resource Adequacy Subcommittee.

MISO will continue discussions on how its maintenance margin could change at subsequent Reliability Subcommittee meetings.

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FERC to Rule on Large Load Interconnection ANOPR in June

FERC announced that it needs until June to act on the Advance Notice of Proposed Rulemaking (ANOPR) initiated by the Secretary of Energy asking it to claim jurisdiction over the interconnection of large loads to the transmission system.

Secretary of Energy Chris Wright had asked for a ruling, which would have proceeded to the NOPR stage, by April 30.

“Our nation stands at a pivotal moment as we face rapid growth in demand from data centers and other large-scale consumers that are reshaping our transmission landscape,” FERC Chair Laura Swett said in a statement. “I want to reassure the public that we are addressing this challenge head-on, working tirelessly and collaboratively with stakeholders and federal partners to deliver real solutions. I encourage everyone to stay tuned as we build a resilient energy future together.”

FERC must balance speed with the need to respond to arguments in a voluminous docket because failure to do so would leave its actions vulnerable to court appeals. Hundreds of comments and replies totaling 3,500 pages have been filed in RM26-4, and in cases like it appeals are the norm. (See Parties Warn FERC Jurisdictional Fight Could Slow Data Center Connection Effort.)

Since the ANOPR was issued in October 2025, FERC has been approving rules for specific markets meant to speed up data center interconnection.

It directed PJM to implement transparent rules to accommodate substantial loads co-located with generation resources. (See FERC Directs PJM to Issue Rules for Co-locating Generation and Load.)

It also approved SPP’s High Impact Large Load initiative in January, which is meant to accelerate the interconnection of large loads and generators built to serve them. (See FERC Approves SPP Large Load Interconnection Process.)

FERC has approved other proposed tariffs and agreements for specific large load interconnections, while rejecting proposals that exceed its jurisdiction or lack reasonable cost allocation.

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FERC Demands $1.1B in ‘Large and Brazen Fraud Case’

In “one of the largest and most brazen frauds in the history” of FERC, American Efficient has been ordered to pay a civil penalty of $722 million and disgorgement of unjust profits totaling about $410 million.

FERC’s ruling, issued late April 15, said the company “stole half a billion dollars from hardworking Americans by collecting compensation for fake ‘energy efficiency resources.’”

“This FERC will not stand for such scams,” Chair Laura Swett said in her opening comments at the April 16 monthly commission meeting.

“It’s particularly sad” the scheme emerged at a time when regular ratepayers have difficulty paying their bills, Commissioner David Rosner said at the meeting. This company is “an egregious outlier,” he added.

According to FERC, American Efficient’s affiliates began participating in PJM’s capacity market in 2014 and in MISO’s capacity market in 2017. The fraud involved “hijacking a regulatory mechanism intended to promote energy efficiency and converting it into an ATM for American Efficient’s worthless paper-shuffling scheme.”

“American Efficient operated a sweeping money-for-nothing scheme to extract capacity payments from PJM and MISO by falsely claiming ownership and control of energy efficiency resources,” according to a FERC news release about the ruling.

“Through this scheme, American Efficient bought sales data for EE products, papered those transactions as if it was acquiring rights to each product’s load reduction-related potential, and then monetized that sales data in the PJM and MISO capacity markets under the guise of offering actual capacity,” the commission said in its ruling.

Once the truth “about American Efficient’s business model emerged over time,” MISO and ISO-NE disqualified American Efficient from their capacity markets.

The independent market monitors for PJM and MISO later referred American Efficient to FERC for potential enforcement action. The commission’s Office of Enforcement began investigating the company in 2021, and in 2024 the commission issued the Order to Show Cause that started the proceeding.

In company comments included in the ruling, American Efficient says it does exactly what the FERC set out to achieve: “bringing within RTO/ISO capacity markets the benefits of permanent energy reductions by providing payments tied to those reductions.”

The company also “contends that it provides benefits by aggregating demand reductions from millions of individual product installations that would not otherwise be accounted for.”

American Efficient says FERC doesn’t have the authority under the Federal Power Act to order disgorgement. It argues that “if Congress wanted the commission to be able to order disgorgement of unjust profits under the FPA, it would have provided express authorization to do so, as it did in a section of the Natural Gas Policy Act (NGPA) that specifically identifies restitution.”

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Ariz. Utilities Confident About Summer 2026 Despite WECC Warnings

Despite harsh weather and unprecedented load growth expected throughout the Western Interconnection, Arizona utilities said they are well prepared to meet demand reliably in summer 2026.

“We do feel we have sufficient capacity to meet projected demand this coming summer,” said Grant Smedley, director of energy marketing and trading at Salt River Project. “We have sufficient fuel, and those generators are ready and maintained.”

Smedley’s comments came during an April 14 summer preparedness workshop hosted by the Arizona Corporation Commission.

Presentations from SRP and other Arizona utilities were preceded by an overview of conditions in the Western Interconnection by James Hanson, manager of operations analysis for WECC.

Hanson noted that March 2026 had been the hottest March on record in more than a dozen states. The heatwave decimated snowpacks in the Colorado River basin and parts of California. (See California Snowpack Near Record Lows as Summer Approaches.) Fire danger is expected to be above normal throughout much of Arizona and New Mexico through June.

A weather forecast for April through June shows an above-average chance of above-average temperatures throughout much of the Western Interconnection. In contrast to situations where a heat wave in one part of the interconnection is balanced by cooler temperatures in another region, the heat shown in the early summer forecast is widespread.

“When everyone’s hot, that excess energy is not available,” Hanson said. “It is serving local needs, and imports become very tight.”

The concerning weather trends are a backdrop to what Hanson called “unprecedented growth” in energy consumption and peak demand. Much of the load growth is due to large loads such as data centers.

Electricity demand is expected to grow by 25% across the Western Interconnection through 2035, with an even higher growth of 42% projected in the Southwest subregion.

Peak demand is projected to grow 20% over the next decade, from 160 GW in 2026 to 191 GW in 2035. The Southwest is projected to see 10 GW of peak demand growth over the next 10 years, or an annual average growth rate of 3%. The only WECC subregion with a higher annual growth rate is Mexico, at 4%.

“The West’s planned resource buildout will not keep up with anticipated load growth over the next decade, particularly in the Basin and Northwest subregions,” WECC said in its 2025 Western Assessment of Resource Adequacy, released in January.

Although 177 GW of new resources are planned, about 90% of those are inverter-based resources, such as solar, wind and batteries.

“Most of the new resources are weather-dependent, which creates uncertainty,” the WECC report said.

Commissioner Kevin Thompson called the high percentage of inverter-based resources “scary.”

“That’s absolutely bonkers to me,” he said.

Growing Peak Demand

SRP, Arizona Public Service and Tucson Electric Power each set peak demand records in August 2025, while exceeding their peak demand forecasts.

Utility representatives explained how they planned to meet the challenges of summer 2026.

Tim Rusert, director of power supply services at APS, said the company added 33,000 new customers in 2025, the most since 2007. In contrast to a demand growth rate of less than 2% from 2022 to 2025, the growth rate for 2026 is expected to be 5.3%.

“But we’re prepared. We’re focused on reliability,” Russert said.

The summer peak forecast for APS is 8,648 MW. The utility has 9,974 MW of accredited resources, or about 1,326 MW of reserves. With a 15.4% planning reserve margin, APS is exceeding its longstanding minimum reliability requirement, Rusert said.

Following a 2023 request for proposals, APS has added 1,000 MW of accredited capacity, including solar, storage, wind and natural gas. Two new gas turbines came online at the Sundance power plant in late 2025; eight more turbines are under construction.

“We maintain a balanced generation mix, which gives us reliability in all conditions,” Rusert said.

Resource Diversity

SRP’s peak demand forecast for the coming summer is 8,869 MW — about 300 MW higher than summer 2025. In addition to its peak retail load, SRP is planning for 1,112 MW of reserves and 22 MW of sales to small Arizona entities, for a total of 10,003 MW.

An expected capacity of 10,489 MW exceeds that amount. Capacity includes 5,665 MW of natural gas resources; 2,544 MW of renewables and storage; 1,455 MW of coal-fired resources; and 826 MW of nuclear resources.

“That diversity has served us really well over the course of our history,” Smedley said. “That’s going to continue to be a really significant focus for us moving forward.”

New resources for SRP include the 55-MW Copper Crossing Energy and Research Center project, SRP’s first owned and operated solar facility. The project uses three different types of solar panels, and SRP will compare their performance. The site also will test three types of solar trackers and three different inverters and will use sky cameras to estimate cloud impacts to solar production.

At TEP, the summer peak forecast is 2,513 MW, slightly higher than the summer 2025 peak of 2,500 MW, said Lauren Briggs, director of resource planning.

TEP’s planning reserve margin target is 16.5%. But with new resources coming online, TEP expects to exceed that in 2026 with 22.1%.

New resources include the 160-MW Babacomari solar project and the 100-MW Wilmot II solar and four-hour storage project. Both are now in service.

Roadrunner Reserve II, a four-hour, 200-MW storage project, is expected to be in service in May.

TEP also counts coal, natural gas, wind, demand response and power purchase agreements among its resources.

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N.Y. Energy Summit Discusses Renewables, Storage

ALBANY, N.Y. — Renewables and storage remain central to New York’s energy vision, even as the path to realizing that vision becomes harder or merely different.

Some discussions April 15 at the New York Energy Summit veered toward the “harder,” as panelists offered assessments and strategies for the obstacles facing the state’s continuing efforts toward decarbonization.

These can be intentional obstacles created by a federal government focused on fossil fuels or inevitable collateral results of New York’s dense regulatory landscape. But the effects are similar: Most types of renewable energy development are moving far more slowly than hoped despite strong support.

“The past 16 months have been lively! There have been some changes made!” Marguerite Wells, executive director of the Alliance for Clean Energy New York, said as she introduced a panel on utility-scale wind and solar.

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

“Depending on how you count, there’s been anywhere between 16 and 20 adverse actions that have been taken against renewables” by the second Trump administration, agreed Zack Hutchins, director of public relations for Boralex.

Onshore wind and solar are central to New York’s near-term planning for renewable generation but still constitute only a small percentage of the total energy portfolio. The state’s high aspirations for offshore wind are paused until a more supportive administration returns to Washington. New nuclear is being planned but may be a decadelong prospect.

The growing need for power and the advanced age of existing generation are such that new gas-fired generation is being considered.

So the renewables community wants to keep skin in the game.

From left: Claire Dépit-Strömbäck, Community Choice Energy Alliance; Adam Cohen, NineDot Energy; Mark Scher, Applied High Voltage; William Acker, New York Battery and Energy Storage Technology Consortium; Sebastian Engelhart, Elevate Renewables; and Michael Slattery, Agilitas Energy, hold a panel discussion at the New York Energy Summit in Albany on April 15. | © RTO Insider

Walter Crenshaw, senior director of operations at AES, said his company is rushing to safe-harbor its projects as it navigates whipsaw policy changes and pursues market share.

“This time period also overlaps with this tremendous growth and demand that we’re all trying to satisfy. And so we have this kind of dual effect, which has been really hard on the industry,” he said.

There are ways to reduce adversity, Hutchins said: “One of the big things that we’re concentrating [on] at Boralex is trying to eliminate or reduce our federal interaction as much as possible.” This includes not triggering environmental reviews because those appear to be a quagmire.

The renewables industry has a steadfast supporter in the New York government, he added.

“The state reaction and the way that the state has stood up to help support contracted projects, mature projects — one of the shining lights of the past 16 months is just the step up in the level of collaboration,” Hutchins said.

The state’s long-running effort to streamline its regulatory structure is appreciated, Crenshaw said. “New York has done a good job with aggregating land-use permitting through ORES [the Office of Renewable Energy Siting], which I usually hold up as a model to our Virginia policy people and others in PJM and then in the Southeast.

“Having the very clear guidelines on land-use permitting in New York has been huge. It’s a lot of things, but we know what we need to do.”

That is the intent, said Georges Sassine, senior vice president for large-scale resources at the New York State Energy Research and Development Authority. He likened all the bottlenecks that once existed to “death by 1,000 paper cuts” and said they are being eliminated systematically. Individually, they are small, but collectively their removal will make a big difference.

As NYSERDA, ORES and other agencies have been streamlining the development process, NYISO has been streamlining the interconnection process. Wells asked the panel about the effect of NYISO queue reforms.

“We’re being forced to make these decisions about what is really viable much earlier than we did in the past,” Crenshaw said.

“It’s moved us towards larger projects as well,” Hutchins said, “because interconnection costs, they don’t scale. You can have a $14 million interconnection on a 60-MW facility, and same on a 200-MW facility. That’s been one of the big changes with Boralex’s approach.”

From left: ACE NY Executive Director Marguerite Wells; Walter Crenshaw, AES; Vincenzo Zarrillo, JLC Infrastructure; Georges Sassine, NYSERDA; and Zack Hutchins, Boralex, hold a panel discussion at the New York Energy Summit in Albany on April 15. | © RTO Insider 

One recurring problem is labor, Wells said. Workers are trained to build renewables, and then the construction pipeline thins out, so they make a lateral move to another industry. Then the renewables pipeline perks up again, so more workers need to be trained.

In 2026, there are 1,500 MW of renewable capacity being built onshore, and 1,000 more is scheduled to start this year. Combined with the offshore wind construction, this is the most ever, she said.

“It’s a good problem to have, but it’s a challenging problem,” Sassine said. “How do you prioritize all of these different projects? And unfortunately, we’re not in a place where we can prioritize; we have to build all of them.”

And yet not all will be built.

Sassine acknowledged the simmering problem with large-scale renewables proposals that have seen significant cost increases and are not able to proceed to construction under the inflexible terms of their subsidy contracts with the state. (See related story, Another Mass Cancellation of Renewable Contracts Brewing in N.Y.)

“If your cost structure is dramatically changing and the projects are uneconomic, you’re being forced to face a tough business decision on whether you want to cancel these contracts with us or even cancel the projects altogether,” he said. “So these are very difficult decisions. We want you to build, but also, at the same time, we want to be protecting ratepayers.”

Distributed Resources

Small-scale solar has taken off in New York, a contrast to inherently slower-moving utility-scale solar development.

“I know that’s old news, but it’s important to remember the highs as we now clearly face a number of headwinds,” Gabrielle Stebbins, senior director of distributed energy resources at the Center for Sustainable Energy, said as she introduced a panel discussion on distributed solar.

From left: Gabrielle Stebbins, Center for Sustainable Energy; Oliver Sandreuter, Lodestar Energy; Kristina Persaud, Advanced Energy United; Jeff Lee, Nautilus Solar; Peter Muzsi, Core Development Group; and Ben Cuozzo, New York Power Authority, hold a panel discussion at the New York Energy Summit in Albany on April 15. | © RTO Insider 

Oliver Sandreuter, director of business development at Lodestar Energy, said the industry must rush to protect what it has now, through safe harboring, but also act to protect its future.

“It’s a critical period of time to go on offense from a policy, regulatory standpoint, as we think about what comes next,” he said. “A lot of that is, thankfully, state-driven conversation, and we are fortunate to be here in New York that has been, as mentioned, a critical leader in DG [distributed generation] deployment. We are, I think, one of, if not the only, state that can claim we are ahead of schedule and under budget with our DG goals.”

Kristina Persaud, senior principal at Advanced Energy United, said the solar industry needs to present itself as the solution at a time of pressing need for new electrons on the grid and mounting concerns overpaying for those electrons.

“We need to think about the speed to market, and we need to think about grid optimization, and solar checks all those boxes,” she said. “It’s the most cost-effective new generation. The speed to market compared to other things, it’s unbelievable.”

Jeff Lee, business development director at Nautilus Solar, said changes are coming. “I think our industry has a very bright future for the next few years with the implementation of safe harboring and so on,” he said, but after that, “it’s a brave new world.”

“New York has been a top 10 market for solar over the past several years,” said Peter Muzsi, vice president of business development at Core Development Group. “I think we will continue to evolve. There still will be solar, even after the” investment tax credit ends.

But there is and will continue to be local opposition to solar, some panelists said.

Moratoria are proliferating steadily, Lee said, as is disinformation.

“One partner of ours mentioned they had an honest question about how solar panels that are not even moving, just sitting there on fixed tilt, are going to attract UFOs,” he said. “These are not isolated incidents … and I see everyone nodding their heads here on the panel.”

“I’ve heard some very bizarre things, that solar panels reflect heat back at the sun and amplify the sun, and that’s what caused global warming,” Persaud replied. “Education is huge here. It helps with NIMBYism, community engagement, some of that pushback.”

Lee wondered if a semi-organized, pseudo-official truth effort might help tamp down some of these misconceptions or limit their impact. But Stebbins tamped down that idea.

“Unfortunately, a lot of times, once folks have bought into the concerns or the disinformation, you end up talking yourself into a backwards pretzel. Because by saying that is not true, you’re providing more petrol to the fire.”

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NERC SC Agrees to Shutter Standards Grading Process

In their monthly open meeting April 15, members of NERC’s Standards Committee voted to disband a group formed three years ago to upgrade the ERO’s functionally defunct standards grading process.

In 2016 the SC created a team comprising the chairs of the SC, Operating Committee and Planning Committee (the latter two being predecessors to the Reliability and Security Technical Committee), along with representatives from the regional entities and NERC staff, to grade selected standards annually, in response to a directive by the ERO’s Board of Trustees to research whether revised standards resulted in improvements. But the process was performed sporadically at best and has not been conducted at all since 2022.

The SC and the Compliance and Certification Committee formed the Standards Grading Task Force in 2023 to develop improvements to the process, but they “struggled to find a recommendation on the path” forward, SC Chair Todd Bennett, of Associated Electric Cooperative Inc., told members.

Bennett cited several factors for the lack of results, including “competing priorities in the industry,” resource constraints and the perception among stakeholders that because the grading process does not produce standard authorization requests leading to new standards projects, there is “no net benefit” to participating.

Another reason for rethinking the standards grading task force is the upcoming changes to the standards development process, driven by the recommendations of the Modernization of Standards Processes and Procedures Task Force adopted by the board in February. Bennett said the MSPPTF’s proposals — which would see the SC disbanded by the end of 2027 and the standards process revamped to work more efficiently with the benefit of artificial intelligence — led NERC to conclude that the standards grading task force, and the grading initiative overall, were no longer needed.

“I don’t think that we’ve lost anything other than a mandated plan to do this annual review of a subset of standards … that [has] yet to display any real benefits,” Bennett said. “The capability [to improve existing standards] is still there, if a [potential] correction is identified by NERC, one of the subcommittees or an industry group.”

The proposal passed with no votes against it and a single abstention by Kimberly Janas, of the Illinois Attorney General’s Office.

Standards Actions

Members next voted to approve the addition of six supplemental candidates to the standard drafting team for Project 2023-09 (Risk management for third-party cloud services).

NERC selected the candidates from nominees submitted by industry in a solicitation approved by the SC at its February meeting after four of the SDT’s original 13 members left the project. (See Members Seek Clarity on NERC Standard Committee’s Future.)

The expansion will leave the project with 15 team members, including the chair and vice chair. NERC Manager of Standards Development Jordan Mallory explained that ERO staff felt the project needed a full complement because of “the very heavy lift this team has to do.” Also, despite the absence of a deadline imposed by FERC or NERC’s board, Mallory said the cybersecurity issues addressed by the project mean the team will “need to move relatively quickly” to finish the standards. The proposal passed unanimously.

The committee then voted to authorize posting the proposed standard PRC-029-2 (Frequency and voltage ride-through requirements for inverter-based resources) (found on page 16 of the agenda), the product of Project 2025-05 (Ride-through revisions) for a formal comment and ballot period.

In Order 909, issued last August, FERC directed NERC to modify its standards to account for IBRs equipped with choppers: equipment that protects offshore wind projects during grid faults. FERC ordered NERC to submit the updated standards by August 2026. (See FERC Approves IBR Ride-through Standards.)

Because of the approaching deadline, Manager of Standards Development Alison Oswald explained to the committee, NERC felt it necessary to shorten the normal 45-calendar-day comment period to 30 days. The committee therefore approved a waiver allowing this reduction, along with shortening any additional comment and ballot periods to as few as 20 calendar days and the final ballot period from 10 calendar days to as few as five.