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April 17, 2026

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NERC Board Approves Large Loads Level 3 Alert

With electric sector stakeholders growing increasingly concerned about the reliability impacts of data centers and other computational large loads, NERC’s Board of Trustees agreed April 16 to send industry a Level 3 alert detailing essential actions for registered entities to help reduce risks to the grid.

The board also approved an updated agreement between NERC, the Northeast Power Coordinating Committee and Nova Scotia Power, reflecting changes to Nova Scotia’s electric regulatory structure.

Alert to be Issued in May

A Level 3 alert is NERC’s most urgent advisory, the only type of alert that requires specific actions from utilities and requires board approval. The ERO has issued only two previous Level 3 alerts: the first, in 2023, concerned protecting grid assets from extreme cold weather, and the second, in 2025, related to inverter-based resources’ performance and modeling.

NERC plans to issue the alert by May 4, Director of Reliability Risk Darrell Moore told trustees. It follows a September 2025 Level 2 alert, the responses to which led NERC to conclude in a March report that the industry is unprepared for the reliability challenges posed by the rapid growth of computational large loads, with many utilities lacking a formalized definition of “large load” and most not having taken any steps to meet NERC’s recommendations. (See NERC: Large Load Responses Show Action Needed from ERO.)

The Level 3 alert will include seven essential actions for transmission owners, planners and operators, planning coordinators, reliability coordinators and balancing authorities:

    • Develop lists of modeling data, settings and parameters needed from computational large loads for distribution to TOs.
    • Study the stability margin for areas with computational loads at least every year.
    • Revise the definition of “qualified change” and set up studies of local area protection, stability limits and other factors in relation to computational loads.
    • Establish a commissioning process for computational loads.
    • Implement system-side corrective actions to ensure no loss of firm load for computational loads due to normally cleared faults.
    • Install dynamic fault recording devices to help study electrical performance of computational load facilities during system disturbances.
    • Improve communication capabilities with large loads for better situational awareness.

Entities will be required to respond to a list of 30 questions (29 multiple choice and one text) by Aug. 3 to evaluate their implementation of the essential actions. NERC will provide a report to FERC on the responses within 30 days of the deadline.

Moore added that, “out of an abundance of caution,” NERC’s management also was seeking “limited delegation” to NERC CEO Jim Robb of the board’s authority to alter the alert before publication. Moore said this request would give Robb and his team the flexibility to make needed updates in response to feedback from FERC, NERC’s standing committees or trade groups without going back to the board.

Board Chair Suzanne Keenan thanked NERC staff for their work and reminded trustees that “for this … alert, what would have normally been done sequentially is being done in parallel,” echoing statements by Robb in 2025 about the ERO’s large loads work. (See NERC Navigates Turbulent Reliability Landscape in 2026.) NERC’s Standards Committee recently approved a project to develop standards focusing on “near-term” risks associated with computational large loads, and the ERO also is operating a task force to examine other actions to help industry.

Amendment to Nova Scotia Agreement

In the meeting’s other action item, trustees voted to accept an amendment to the memorandum of understanding between NERC, NPCC and Nova Scotia Power. The amendment must be approved by all parties to the MOU before it takes effect.

NERC and NPCC signed the current MOU with Nova Scotia Power in 2010, NERC Senior Vice President for Regulatory Oversight Howard Gugel told trustees. The ERO has similar MOUs with every other Canadian province and the appropriate regional entity that govern how NERC’s standards are applied and how compliance monitoring and enforcement are performed.

In 2024, the Nova Scotia General Assembly passed the Energy Reform Act, leading to the establishment of IESO Nova Scotia the following year. IESO-NS since has taken over the functions of planning coordinator, planning authority, resource planner and transmission planner, and is expected to begin performing the transmission operator and balancing authority functions in 2027. The act also created the Nova Scotia Energy Board and “provided [it] with the authority to adopt, monitor and enforce NERC reliability standards in Nova Scotia.”

The changes will make Nova Scotia’s energy regulation “a little bit more consistent with the way the other provinces work,” Gugel said, but the existing MOU “was tied into the way things were previously done.”

The amendment will:

    • Add IESO-NS as a party to the MOU;
    • Provide a mechanism and structure for NPCC to perform compliance monitoring and enforcement activities for NERC standards;
    • Replace references to the previous regulators with the NSEB; and
    • Update contact information for the relevant parties.

As with the Level 3 alert, the board also agreed to delegate Robb the authority to “finalize and execute the … MOU on behalf of NERC,” along with General Counsel Sonia Rocha.

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FERC Pulls Plug on NOIs Covering DR and Utility Political Spending

FERC has closed two notices of inquiry (NOIs) that date back five years but have never advanced: one to eliminate the state opt-out for demand response and the other for new rules aimed at ensuring regulated utilities do not spend ratepayer money on lobbying.

Both were issued under former Chair Richard Glick, who in 2022 was blocked from a new term by former Sen. Joe Manchin (I-W.Va.), and were not moved forward by his successors. Chair Laura Swett has made a point of ending such “zombie proceedings.”

“These particular proceedings have languished since 2021 and 2022, respectively,” Swett said at the commission’s open meeting April 16. “And it’s our responsibility as regulators to either act on proceedings or to close them out. If the record doesn’t support action, we do not want to leave the industry in limbo for years at a time, and I will continue my commitment to work through those dockets as efficiently as we can.”

The DR opt-out docket looked to end a FERC rule dating back to 2008’s Order 719, which allows state regulators to prevent their consumers from participating in wholesale DR programs (RM21-14). (See FERC Limits State ‘Opt Out’ on DR.)

FERC then issued Order 745, which led to the Supreme Court decision in EPSA that found the commission was well within its authority to regulate demand response.

Lower courts then used the EPSA precedent to block state opt-outs for similar wholesale services provided by retail customers, such as energy efficiency, storage and distributed energy resources under Order 2222, the original NOI said.

“After careful consideration of the record, we agree with commenters that raised concerns regarding the removal of the Demand Response Opt-Out, stating that the demand response landscape has not changed significantly enough to warrant such action by the commission at this time,” FERC said in the order ending the NOI (RM21-14). “We also note the strong opposition to removing the state opt-out expressed by state organizations such as the National Association of Regulatory Utility Commissioners (NARUC) and regional state regulatory associations.”

In a speech the day before the open meeting, Swett said she wanted to push FERC precedent to the edge, but found this wasn’t one of those areas despite court victories against state opt-outs for similar resources. (See Swett Wants to Push Right Up to the Edge of Precedent as FERC Chair.)

“The important caveat of that — there were two things: it was legal durability and also whether or not it would be worth it for those specific situations,” Swett said at a news conference after the meeting. “And taking a hard look at this docket, which has been open for years, the demand response environment has changed. And so my colleagues and I have consensus that this particular approach would no longer be something that would be necessary, and that is why we closed it.”

‘Turning Point’

The order prompted a dissent from Commissioner David Rosner, who argued FERC and the wholesale markets need every tool in the toolbox to meet demand growth and DR is an important option.

“The electricity system is at a turning point,” Rosner said in his dissent. “New electric customers can individually use as much energy as a city. There are two primary ways to meet this growth and power these new, large customers. One path is to enable faster and cheaper grid integration by offering the option to use load flexibility, or behind-the-meter generation, which can reduce impacts on the transmission system, require significantly less infrastructure and lower costs. The other path is to rely on only the status quo, which can be time-intensive, require significant new infrastructure and increase costs.”

While Rosner wants more uniform wholesale market rules around DR, he agrees with the push to close old dockets.

Commissioner Judy Chang filed a concurrence, saying FERC may need to reconsider the opt-out in the future but that maintaining the status quo makes sense for today. Her concurrence focused on how to expand DR in the markets today, noting that PJM’s last capacity auction had half the amount of DR as 2014/2015 despite clearing short and that Order 745 has done little to add DR to energy markets.

“To increase demand response participation, the commission, state regulators and market operators need to collaborate on market designs and participation models that balance: 1) practical limitations on customers’ ability and willingness to curtail demand, and 2) confidence that system operators can rely on demand response resources to respond quickly and predictably when called,” Chang said. “This means that state and federal regulators as well as market operators need to engage more to understand and resolve friction that might arise when demand-side resources are integrated into market structures. Such frictions may involve end users’ metering requirements, parameters around billing periods, or frequency of calls on customers to curtail their load.”

Utility Political Spending NOI

The order terminating the utility political spending NOI (RM22-5) did not draw any separate statements, with all the commissioners agreeing existing accounting rules were sufficient to stop utilities from spending ratepayer money on political activity.

“Based on consideration of the record, we find that the concerns raised in the notice of inquiry are better considered on a case-by-case basis, consistent with longstanding commission practice,” FERC said in the order.

FERC’s long-standing precedent holds that any efforts to influence public opinion have little or no benefits for ratepayers and should be paid for by shareholders, the order notes.

Ratepayers should not be forced to pay for the lobbying by their utilities, Rosner said during the open meeting.

“The good news is the solution here, I think, is pretty simple,” Rosner said. “If you’re a jurisdictional utility, ask your trade association to itemize your bill. If you’re not already doing this, be transparent in your rate filings in your accounting, [and] follow the instructions on our uniform system of accounts that have been in place for decades.”

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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.