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April 15, 2026

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Western Hydro Output Expected to Increase Despite Snow Drought, EIA Says

Hydropower generation in the Northwest and Rockies is expected to increase 17% from 2025 levels despite snow drought conditions, the U.S. Energy Information Administration said.

The EIA reported April 14 that it expects hydropower generation in the region to hit 125 billion kWh (BkWh) in 2026, a 17% increase compared with 2025 but 4% below the 10-year average. The agency’s projection follows “record warm winter temperatures” in the West and a heat wave in March that led to early snow melt, according to the EIA’s Short-Term Energy Outlook.

In the Northwest, “Hydropower generation in December 2025 and January 2026 was unusually high due to a series of atmospheric rivers that led to devastating flooding in the region,” the EIA stated. The agency said its outlook is based on water supply forecasts from the National Oceanic and Atmospheric Administration.

Nationwide, the EIA expects hydropower generation to increase by 5% in 2026 but remain 1.8% below the 10-year average following snow drought conditions. In 2026, the report expects hydropower generation to be 259 BkWh, representing 6% of the United States’ electricity generation.

The EIA report shows hydropower is a reliable source of base load generation even during snow drought, according to Malcolm Woolf, president of the National Hydropower Association.

“Yes, there was snow drought, but actually hydropower generation is expected to increase 5% in 2026,” Woolf said. “We are still in a historic multi-year drought cycle, so hydropower production is not expected to reach records, but it’s not going to be as bad as the 2024 record low generation year.”

Though some people may assume the opposite, “the modeling shows that climate change is water change … and that actually means more hydro generation,” according to Woolf.

Still, droughts can impact a dam operator’s bottom line and create serious concerns from season to season, Woolf said.

Another challenge is managing spill levels to prevent dams and reservoirs from overflowing during an atmospheric river event. Spilled water is a missed opportunity to produce electrons, Woolf noted.

He pointed to the Bonneville Power Administration, which markets power from 31 federal dams in the Columbia River Basin. The agency must spill a certain amount of water over the dams instead of running it through turbines to protect migrating salmon, Woolf said. (See BPA Explores Rate Alternatives Following Order to Increase Dam Spills.)

However, new technology, including better climate modeling and fish-friendly turbines, can optimize the system and enable dams to produce power when the grid needs it the most, Woolf said.

“I think what you’re hearing from the EIA report is that climate change isn’t impeding that,” Woolf said. “If anything, it’s actually increasing the amount of water available for hydropower.”

Meanwhile, the EIA forecasts California’s hydropower generation in 2026 to be 28.5 BkWh, 6% less than 2025 but 15% more than the 10-year average.

The Golden State’s reservoir levels were above the 30-year historical average as of April 1, with the two largest reservoirs, Shasta and Oroville, at 114% and 124% of the historical average, respectively, the EIA stated.

“The state of California also experienced three consecutive weeks of no drought or drier than normal conditions,” the EIA stated. “However, according to the California Department of Water Resources, snowpack conditions as of April 1 were well below normal with Northern Sierra Nevada at 7%, Central Sierra at 25%, and Southern Sierra at 39%. Additionally, warmer-than-normal temperatures in March led to some early snowmelt across the state.”

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MISO Load Forecast: Data Centers Drive 163-GW Peak by 2035

MISO expects to manage a 163-GW demand peak by 2035, and potentially 230 GW by 2046 in a high-demand environment, according to the RTO’s first crack at comprehensive long-term load forecasting.

The grid operator said data center load is the most consequential variable in its 20-year view of load growth.

MISO’s projections show a 163-GW coincident peak in 2035. That could become more than 180 GW by 2046 at a 2% compound annual growth rate. But the RTO said a 3% CAGR could have it topping 230 GW in peak demand in two decades.

The RTO managed an approximately 121-GW coincident demand peak in 2025.

The latest figures show that what was considered unlikely two years ago has become the norm. The RTO’s “high” scenario from its less intensive load forecasting effort in 2024 now mirrors its “current” trajectory. (See MISO Switches to In-house Load Forecasting to Gauge Soaring Demand.)

“What was previously upside is now base case,” Brad Decker, of MISO’s Strategic Insights Group, said during an April 13 stakeholder workshop on the forecast.

Decker said the 20-year forecast reflects “evermore announcements and expectations” for data center infrastructure through 2035.

MISO said it’s in an AI “super cycle,” with 22 GW of data center demand alone projected by 2030. It found that data centers could proliferate at an 18% CAGR through 2046.

“Data centers are scaling quickly and introducing a lot more local planning dynamics,” Decker said. “A single project can rival the load of a mid-size city.”

Decker said MISO discovered that since its most recent load check-in in 2024, trends are “tilting” toward more traditional generation resources to handle the ballooning load, combined with “softer expectations” for electrification-driven load growth.

Additionally, loads are poised to become more consistent with the “structural” change of around-the-clock data center demand, Decker said. He said MISO’s system load factor is set to increase from about 63% currently to nearly 70% by 2040.

However, Decker said the trajectory of AI is uncertain, including “monetization challenges” that could slow investment and consolidate the industry. He said there “are signs” of obstacles already, comparing data center announcements to restaurant reservations in which only five to six people ultimately show up for a reservation for 10.

MISO included a lower growth case that contemplates a slowdown in data centers in its range of possibilities. In that scenario, it might experience a 1.1% CAGR and manage an approximately 150-GW peak by 2046.

During the Board of Directors’ meeting in March, CEO John Bear said the expected 2% rate “is quite a bit away from the 0.4%, 0.2%” annual growth the RTO had been managing for years.

At the workshop, Executive Director of Markets and Grid Research DL Oates said MISO focused on piloting a long-term load forecast because of demand brought on by data center growth.

“The growth expected going forward is quite different than what we’ve experienced,” Oates said.

If MISO is to oversee a 163-GW peak in less than a decade, it needs significantly more generation. The RTO reported in March that its expedited interconnection queue could soon add 19 GW in nameplate capacity to the footprint. It said it is ready to clear or has cleared 11 GW of projects to connect and is studying an additional 8 GW for interconnection. (See MISO: NERC to Dial Down RTO’s Risk Level; Members Create Large Load Working Group.)

MISO’s standard generator interconnection queue, on the other hand, contains 192 GW, which is set to dwindle. (See MISO Plans to Change Accounting Practices as Record Queue Exits Could Raise Rates.)

The grid operator also reports it is sitting on 76 GW in generation with approved interconnection agreements that have yet to be built. It’s urging developers to bring their projects online as quickly as possible or let it know if those projects cannot be completed.

Oates said the pilot long-term load forecast won’t be used in 2026 in the 20-year futures scenarios that influence long-term transmission planning, but it would be incorporated in subsequent years. The informational nature of the pilot long-term load forecast is nevertheless valuable and will serve as a guide for gathering data from members, he said.

“We’re trying to get this long-term load forecast on a predictable, annual cadence,” he said.

In future annual load forecasts, MISO plans to refine its member data collection process, improve geospatial load growth results, and incorporate extreme weather and its influence on load. It also has hired energy analytics company Kevala to update its projections for distributed energy resources.

Decker said that once MISO factors in demand-side projections, it would produce a gross load forecast in addition to its net load forecast.

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Expert Warns Quantum Horizon Closer than Expected

With new generations of computers capable of breaking most existing forms of encryption potentially only a few years away, there is no time to waste when it comes to future-proofing technology, a computing expert warned attendees at a webinar hosted by the Midwest Reliability Organization.

The MRO webinar focused on the security risks posed by quantum computing, a form of computing based on the properties of subatomic particles that is believed to be capable of performing certain calculations exponentially faster than any other available computer.

Such machines could provide significant benefits in the form of accelerated drug discovery and chemical development, but will also endanger public key cryptography, which accounts for the vast majority of data encryption on today’s internet along with user, device and application authentication.

Although decoding the public keys generated by current methods requires vast amounts of resources and energy under traditional conditions without a mathematically linked private key, experts believe they will be trivially easy to crack with quantum computers.

The primary speaker at the webinar was Garfield Jones, senior vice president of global strategy and research at security firm QuSecure. He quoted recent research from Google indicating cryptographically relevant quantum computers (CRQCs) — the industry term for quantum computers capable of breaking public key encryption — may be easier to achieve than previously thought and therefore available within the next three years, far earlier than most estimates.

“When I first started this [work], we were looking at [the year] 2050” as the date when CRQCs would become a reality, Jones said. “Then we started looking at 2035, and now we’re looking at 2028 [or] 2029. Technology moves really, really fast, so that’s why we have to be up front and actually get aware and prepared for this.”

Adding to the urgency is the fact that digital spies don’t need to wait until CRQCs are available to steal data. Jones and other experts believe many threat actors are pursuing a “harvest now, decrypt later” (HNDL) strategy in which they store stolen encrypted information from target companies in anticipation of the development of CRQCs to decrypt it.

HNDL attacks are aimed at data in transit from one device to another. This kind of data is protected with public key encryption, as opposed to data in use — which is currently being processed in a user’s computer or smartphone and thus cannot be secured — and data at rest, which is kept in a physical storage medium, ideally under symmetric encryption keys.

No Shouting from Rooftops

The good news for electric utilities, Jones said, is that action is underway in multiple sectors to prepare for the world of post-quantum cryptography (PQC). Executive orders issued by Presidents Biden and Trump aimed to prepare the country for a PQC future by directing the Cybersecurity and Infrastructure Security Agency to publicize categories of products in which PQC is available and directing agencies to support quantum-safe protocols by no later than 2030.

Jones also reminded listeners that the National Institute for Standards and Technology in 2024 released a set of encryption tools designed to resist quantum cracking attempts and can be used with current technology. He urged utilities to adopt the new tools as soon as possible to ensure safe transmission of data in the future and to continue to monitor NIST for new algorithms to improve the initial set.

This work will not be accomplished overnight, Jones acknowledged. Utilities must not only adopt PQC in their internal systems after decades of accumulated experience working with traditional methods, but also push their vendors to do so as well. Robust implementation and funding plans will be needed to ensure long-term commitment.

Asked how experts can be sure a nation-state or other adversary does not already possess a CRQC, Jones answered simply, “We don’t.” He clarified that he thought it unlikely that the milestone had been reached because of the resources needed, but also warned listeners not to underestimate the ingenuity of their opponents.

Jones observed that programming advances have reduced the estimated computing resources needed to break public key encryption by a factor of 10 and suggested the advent of quantum decryption is not likely to be publicized.

“I don’t think there’s one right now, but when one does come online — I mean, if I owned it, I wouldn’t shout from the rooftops. I would just start using that [like] we did [in] World War II,” Jones said, referring to the successful efforts by Allied intelligence to break Germany’s Enigma encryption. “Just keep sending that data, and I’ll just keep reading every single thing.”

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BPA Narrows Estimate of Energy Deficits over Next 10 Years

The Bonneville Power Administration said it continues to face steep energy deficits under “firm” water conditions over the next 10 years, but the outlook is slightly better than what the agency foresaw a year ago.

The finding comes out of BPA’s most recent Pacific Northwest Loads and Resources Study, also known as the “White Book,” which offers a 10-year outlook on the agency’s ability to serve its load obligations with its own federal resources.

The study provides predictions for BPA’s own load and resources, as well as the entire region’s retail loads, power supply obligations and resources. The findings are used in long-term planning for BPA and the Columbia River Treaty, and they provide a record of information for customers and other regional planning entities.

“Firm” water conditions represent the agency’s lowest estimate for flows in the Federal Columbia River Power System, a conservative planning scenario intended to ensure the agency maintains system reliability and avoids overextending its contract obligations. BPA noted that under “median” conditions, which reflect historical flows, it would remain in surplus for the entire study period.

The 2026 White Book, released April 13, projects annual energy deficits across the 10-year span under firm conditions, ranging from 535 average megawatts (aMW) in operating year (OY) 2027 to 834 aMW in 2036 — with a peak deficit of 937 aMW in 2036. In comparison, the 2025 White Book showed deficits ranging from 426 aMW in 2026 to a peak of 1,012 aMW in 2036. (See BPA Predicts Energy Deficits Over Next 10 Years.)

“The 2026 White Book shows a slight improvement in deficits annually in seven of the 10 years,” BPA noted in the report, attributing that change to a decrease in federal load obligations during the first half of the study period and the impact of a planned uprate of the Columbia Generating Station nuclear plant during the latter half. (See BPA Approves $700M Plan to Boost Columbia Generating Station Output.)

The outlook is more volatile for the entire Pacific Northwest, which under firm conditions could see a surplus of 337 aMW in OY 2027 but decline steeply to a deficit of 3,514 aMW in 2035. The first deficit appears in 2029 (747 aMW) then begins accelerating in 2031 (2,135 aMW).

“This result was mainly driven by the increasing PNW retail loads,” Rachel Dibble, BPA vice president of generation asset management, said in a letter accompanying the White Book.

Dibble noted also the Pacific Northwest analysis consisted of a “forecast of regional firm loads and resources, based on expected retail loads and different levels of generating resources that vary by water conditions.”

“The scheduled decommissioning of existing resources, the extent of forecasted load growth, the availability of uncommitted PNW independent power producer generation to meet regional load, and new resource additions are key variables in the results of this analysis,” she wrote.

BPA said the total retail load, contracts and generation forecasts used in the White Book were up to date as of February.

“While [BPA] Provider of Choice contracts were signed in December 2025, Bonneville will not have a full understanding of its Provider of Choice load obligations until Tier 2 elections are made in summer 2026. Thus, Provider of Choice updates are not included in this issue of White Book,” the agency wrote. (See BPA Signs New Multiyear Contracts with over 130 Customers.)

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FERC Accepts SPP’s Western Interregional Transmission Coordination

FERC has accepted SPP’s tariff revision that establishes procedures governing interregional transmission coordination in the Western Interconnection between the grid operator and its neighboring planning regions following its RTO Expansion (ER26-1311).

SPP’s proposal also included a method for allocating interregional projects between SPP’s Western region and the planning regions that the commission found to be just and reasonable. FERC said in the April 10 order that the interregional coordination procedures and cost-allocation methodology comply with Order 1000’s requirements.

In a separate concurring statement, Commissioner David Rosner commended the RTO for reaching consensus with its new Western neighbors on the tariff provisions but also highlighted “broader deficiencies” with the commission’s current interregional transmission coordination framework.

He said that since 2011, Order 1000 has resulted in “exactly zero” interregional projects, noting that interregional transmission “time and time again over those 15 years” has made “meaningful” contributions to grid reliability during extremely stressful periods.

“It is imperative that the commission and industry advance meaningful action on interregional transmission planning as soon as possible,” Rosner wrote, saying he is ready to “take swift action” on any future industry filings. “Absent such filings, I intend to work with my fellow commissioners to move this critical ball forward.”

Pointing to NERC’s Interregional Transfer Capability Study, he said it identified a 35-GW gap that, if left unaddressed, “will contribute to a grid that is less reliable.”

“This is a concerning finding that we must address,” Rosner said.

The commission noted the tariff revisions deviated from the common interregional cost-allocation language by assigning project costs to the SPP region according to its existing mechanisms, as applied only to projects in the Western Interconnection. However, it said the revisions comply with Order 1000 because they ensure any project costs in the Western Interconnection allocated to the SPP region on a pro rata basis are allocated only according to SPP’s commission-accepted regional cost allocation method.

FERC found several other variations from the common tariff language to be just and reasonable because it said they clarify the appropriate handling of sensitive information and ensure that costs for projects no longer viable to SPP’s regional transmission needs are not allocated to its region.

The commission also accepted the RTO’s proposal to define CAISO as a “planning region.” It agreed with SPP that while CAISO is not contiguous with and does not neighbor the RTO’s new Western region, including it as a planning region will promote interregional transmission coordination.

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Company Briefs

PacifiCorp Dumps Renewable Energy Plans in 4 States

PacifiCorp updated its integrated resource plan to eliminate renewable energy plans in four states.

The utility has no plans to add more wind or solar facilities in Wyoming, Utah, Idaho and California from 2027 through 2045 following the repeal of tax credits in the Inflation Reduction Act. The company said the tax credits had reduced the cost of wind and solar projects by about 30%.

More: WyoFile

AES Withdraws from California Battery Project

AES withdrew its application to develop the Seguro battery system in Escondido, Calif.

The company intended to use a former horse ranch to house a 320-MW battery storage project but said it will prioritize other development efforts after facing intense local opposition.

More: Canary Media

VW to Stop Producing ID.4 at Tennessee Plant

Volkswagen announced it will cease production of its ID.4 EV at its Chattanooga plant and will shift focus to the Atlas and Atlas Cross Sport.

In January, the electric SUV was the slowest-selling vehicle in the U.S. The next generation of the Atlas will begin production this summer.

More: Chattanooga Times Free Press

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State Briefs

CONNECTICUT

Eversource Backs out of 3 State Solar Projects

Eversource informed the Department of Energy and Environmental Protection that it will opt out of three power purchase agreements worth 54 MW of solar power.

Eversource Deputy General Counsel Duncan R. MacKay sent a letter to DEEP and legislative leaders on March 27, saying the agency’s latest round of clean energy purchases was overpriced and likely will result in an increase to the public benefits charge. For those reasons — as well as a lack of “comprehensive” energy strategy — MacKay said the company would decline to enter the contracts.

Officials said it is still unclear what impact the decision will have on the projects moving forward.

More: CT Mirror

MAINE

Legislature Passes Data Center Moratorium

A bill that would place a statewide moratorium on large data centers passed both Democratic houses and awaits appropriations.

The bill bans data centers larger than 20 MW until November 2027. It also creates a Data Center Coordination Council that will provide input, facilitate planning considerations and evaluate policies to address the facilities. Democrats cited the potential costs to ratepayers and widespread local opposition, including in Bangor.

More: Maine Morning Star; Bangor Daily News

Gov. Mills Approves Plug-in Solar

Gov. Janet Mills signed a bill that will allow residents to install small, portable solar energy systems in their homes.

The measure allows customers to use certain small solar generation and battery systems that plug directly into wall sockets, similar to gas generators. One estimate found an 800-W system could save the average customer more than $250 annually.

More: Portland Press Herald

MICHIGAN

Sault Tribe to Adopt Data Center Moratorium

Members of the Sault Ste. Marie Tribe of Chippewa Indians voted unanimously to approve a moratorium on the development of AI data centers on tribal lands.

Tribe members cited concerns about the strain on local resources, long-term land use impacts and the uncertainty of whether a facility would yield long-term economic benefits.

The moratorium will remain indefinitely.

More: Michigan Advance

MINNESOTA

PUC Approves Xcel VPP

The Public Utilities Commission approved Xcel Energy to build and operate its own virtual power plant.

Under the Capacity*Connect program, Xcel will spend $430 million to deploy up to 200 MW of batteries, in 1- to 3-MW increments, over the next two years.

Xcel said it will place the batteries around local communities strategically to test how each can mitigate grid constraints.

More: Canary Media

NEW YORK

ORES Awards Permit to 99-MW Wind Farm

The Office of Renewable Energy Siting and Electric Transmission approved a siting permit to Liberty Renewables for a wind farm in Cayuga County.

The 99-MW Agricola Wind project calls for the construction of up to 24 turbines and will operate for 25 years.

The farm is expected to be operational by 2028.

More: Renewables Now

VIRGINIA

SCC Approves Dominion Energy Tx Project

The State Corporation Commission approved Dominion Energy’s request to build new high-voltage transmission lines through Loudoun County.

The SCC approved the shortest route at 8.3 miles for the 230- and 500-kV lines. It also said burying the lines underground was not practical due to an estimated $1.5 billion cost, much to the dismay of the project’s opponents.

More: Loudoun Now

ONTARIO

IESO Awards Contracts for 1.3 GW of Solar, Wind

IESO approved 14 renewable projects with a combined capacity of more than 1.3 GW under the first window of the Long-Term 2 procurement process.

The 20-year contracts will go to 12 solar and two wind projects. The three largest contracts will procure 200 MW each from the Dunns Valley Solar plant, the Gichigami Wind Project and the Northern Breeze Wind Project.

All projects are expected to begin commercial operations by May 1, 2030.

More: Renewables Now

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Federal Briefs

Brown Analysis: Iran War has Cost Americans $17B at the Pump

The Iran war has cost the U.S. economy roughly $17 billion solely by increasing gasoline and diesel prices, according to an analysis from Brown University researchers.

The analysis said much of the higher costs come from surging diesel prices, which have risen 48% since the war began. In all, Americans have paid an additional $8.8 billion for gasoline and an extra $8 billion for diesel.

More: Heatmap

EPA to Weaken Coal Ash Rules

EPA announced it will weaken cleanup requirements for hundreds of coal ash deposit sites.

The agency said it would repeal a 2024 Biden administration rule that required companies to examine the condition of coal ash sites at inactive power plants, and ease standards for monitoring and protecting groundwater near some sites.

The new plan would return much of the decision-making to states, while also letting local permitting agencies bypass national standards on a case-by-case basis.

More: The Guardian; The New York Times

EPA Tells Scientific Research Staffers to Relocate

EPA is making some of its staffers relocate and is reassigning a larger share of employees as part of its efforts to reorganize its scientific research.

The agency is reassigning 124 staffers, 35 of whom are being asked to relocate.

The move comes as the Trump administration attempts to eliminate its Office of Research and Development and conduct scientific research in a new office housed within the office of the administrator.

More: The Hill

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PJM MIC Briefs: April 8, 2026

Stakeholders Endorse Issue Charge on Dual-fuel Switching Downtime

PJM’s Market Implementation Committee endorsed an issue charge to explore how dual-fuel gas generators should reflect the downtime needed to switch fuels in their requirement to offer into the energy market.

Constellation’s Erik Heinle said the proposal would enhance reliability by ensuring resource limits are recognized by PJM. The issue charge was jointly sponsored by Constellation and PJM.

PJM’s Brian Chmielewski said, from a markets perspective, staff is interested in talking through the apparent inconsistencies between the parameters resources may submit and their limits. On the operations side, there’s interest in having more flexibility to preserve stored oil fuel.

Language was added to the problem statement ahead of the meeting to reflect stakeholder concerns about oil fuel inventories being depleted during winter events when gas prices are high. Since PJM’s scheduling software prioritizes cheaper offers, a dual-fuel unit might be asked to switch from gas to oil even when dispatchers would prefer to preserve stored fuel for later in the event.

Asked why the issue should be considered separate from ongoing work to consider how resources are committed, Heinle said Constellation is seeking to have the change in place ahead of next winter. He said because the issue charge is focused on a narrow issue and is likely to require only manual revisions, it could be advanced more quickly as a standalone item.

The issue charge was revised during the meeting to address stakeholder concerns that it was overly prescriptive around the possible solution and to reflect PJM’s desire to have more flexibility around when oil is burned.

PJM’s Kevin Hatch said resources going offline while switching fuels would be able to use the transition time as an exception from the must-offer requirement. The requirement is applicable to resources with a capacity commitment.

PJM Seeks Changes to LOC Eligibility for Flexible Resources

PJM presented proposed revisions to make flexible resources ineligible for lost opportunity credits (LOC) if they submit inflexible offers in the real-time (RT) energy market.

The changes would update the tariff’s definition of a flexible resource, inserting the phrase “all available schedules separately specify” ahead of “a combined start-up time and notification time of less than or equal to two hours; and a minimum run time of less than or equal to two hours.” A resource would be disqualified from receiving a LOC payment if it commits on a flexible schedule in the day-ahead (DA) energy market by submits inflexible offers in the RT market.

The issue stems from how PJM’s intermediate term SCED (IT SCED) software would evaluate an inflexible offer from a flexible resource. If the unit was committed in the DA market on a flexible cost-based offer because it would fail the market power mitigation test under a modeled transmission constraint, the start-up and notification parameters of an inflexible offer could be longer than the lookahead IT SCED uses. If the constraint does not manifest, IT SCED would be unable to schedule the unit.

PJM Presents Quick-fix Manual Changes for Fuel Cost Policies

PJM presented a quick-fix proposal to rework how it calculates penalties when a resource submits a cost-based offer that violates its fuel cost policy. The quick fix process allows a problem statement, issue charge and proposed solution to be considered concurrently.

Because LMP is a component of the penalty formula, the penalty could be negative if prices are negative when the violation is identified — effectively becoming a credit.

The proposed changes to Operating Agreement Schedule 2 would set the penalty at the greater of the existing rate or zero.

Monitor Investigating Fractional Clearing Contributing to High Regulation Prices

The Independent Market Monitor is looking into situations when a marginal resource being assigned a regulation commitment below 1 MW leads to high regulation clearing prices.

Chief Economist Howard Haas said costs can “explode” when partial or fractional commitments (between 0.1 and 1 MW) are the marginal resource in the regulation market  — depending on offer parameters and realized differences between market clearing LMP forecasts and realized LMP lost opportunity.

The Monitor is working with PJM to optimize how resources’ parameters interact with the regulation market design. Differences between the economic dispatch range and the regulation range and between bid in ramp and actual ramp may make regulation prices highly sensitive to differences between forecast and actual LMPs.

One of the Monitor’s initial recommendations is for a resource’s Reg Max parameter to be tied to its energy market Eco Max parameter. LOC would be determined on the basis of Reg Max falling below Eco Max.

PJM’s Michael Olaleye said the regulation redesign implemented in October 2025 has made price formation and procurement more efficient and positioned the market for increased renewable penetration. Uplift has fallen from 14% to 2% and the market now more accurately captures the cost for a resource to reduce its output for energy or regulation purposes.

He stressed there are no errors in how PJM clears or prices regulation resources and staff is monitoring the optimization engine results for improvements.

Manual 15 Biennial Review Changes Endorsed

Stakeholders endorsed revisions to Manual 15: Cost Development Guidelines intended to clarify how to update the format of the variable operating and maintenance (VOM) adder and the functioning of the opportunity cost calculator.

Under the changes, resource owners may change the VOM format only once per calendar year at the time of submission. Subsequent changes would not be permitted until the start of the following calendar year.

The changes state that, when simulating the hours of operation with the greatest energy market revenue excluding short run marginal costs, the opportunity cost calculator will model a unit as being dispatched between its economic minimum and maximum.

An additional paragraph states the adders the calculator produces are normally a dollar per megawatt-hour value, except when environmental or operational limits limit how often a unit can be started or operated during a compliance period. In cases when the resource is limited by starts per period, the adder is a dollar per start value and can only be applied to start-up costs. If the limit is run hours per period, the adder is dollars per hour and can only be included in no-load costs.

1st Read on Manual 11 Changes to Advance Commitment Offer Selection

PJM presented revisions to Manual 11: Energy & Ancillary Services Market Operations to distinguish between offer selection for advance commitments and resources scheduled in the day-ahead market.

Resources with start-up or notification times exceeding a day — those with advance commitments — would be scheduled on their cheapest cost-based offer available at the time they are committed, with updates not permitted. Resources with shorter start-up or notification times would be scheduled on their cheapest cost-based offer at the close of the day-ahead market.

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PJM OC Briefs: April 9, 2026

Manual 1 Revisions Endorsed

The PJM Operating Committee on April 9 endorsed a package of changes to Manual 01: Control Center and Data Exchange Requirements, including the elimination of a requirement that actual meter test results should be provided to the RTO. (See “Stakeholders Delay Vote on Manual 1 Revisions,” PJM OC Briefs: Jan. 8, 2026.)

Stakeholders held off on approving the language in January so that PJM staff could address concerns that without a reporting requirement, the RTO would be left to assume meter data are correct. Language was added stating that the provisions in generation interconnection agreements requiring periodic meter tests must be respected, recognizing PJM can request meter tests, and that discrepancies discovered should be resolved on by the settling parties. It also notes PJM holds five years of settlement data.

March Operating Metrics

PJM saw an average hourly load forecast error rate of 1.75% in March and an average peak hour forecast error of 1.68%. There were five days when the daily peak forecast error rate exceeded the 3% benchmark:

    • high temperatures on March 1 pushed loads 3.25% down;
    • low temperatures in several zones on March 13 led to a 3.95% underforecast;
    • cold weather on March 15 led to a 3.71% underforecast;
    • much higher temperatures than forecast on March 19 contributed to a 5.98% overforecast; and
    • temperature forecast error in several zones on March 22 led to loads coming in 4.23% higher than expected.

There were two spin events, four shared reserve events, one high-system-voltage action, three geomagnetic disturbance warnings, 19 shortage cases and 11 post-contingency local load relief warnings in March.

Three of the shortage cases occurred on March 1 starting at 7:35 p.m. because of a loss of generation. Nine were on March 12 between 7 and 7:40 p.m. owing to resource ramping limitations and solar generation falling off as load increased. Seven cases from 5:05 to 5:35 p.m. on the following day were attributed to ramp limitations and higher-than-forecast load.

The first spin event was on March 1 at 7:29 p.m. and lasted 11 minutes and 9 seconds. There were 2,416 MW of generation and 643 MW of demand response assigned, of which 1,335 MW and 499 MW responded, respectively, for an overall response rate of 60%. There were 1,225 MW of reserve penalties assessed.

The second event was on March 5 at 2:24 a.m. and lasted three minutes and 59 seconds. There were 1,996 MW of generation and 656 MW of DR assigned, of which 268 MW and 439 MW responded, respectively, for a 27% response rate.

Monitor Update on Synch Reserve Performance

The Independent Market Monitor presented the results of outreach to the owners of 14 resources that underperformed during a March 1 synchronized reserve event and found that communication issues are becoming less of an issue, while personnel and parameter issues continue to pull the response rate down.

The Monitor has been reaching out to owners of underperforming resources for months as part of an effort with PJM to address a lingering poor response rate for synchronized reserves.

There were 2,538 MW dispatched during the event, of which 72% responded. The Monitor has long recommended that PJM count overperformance when calculating the fleet-wide response rate; when adding that in, the response rate increases to 91%.