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April 9, 2026

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N.Y. Reports Progress on Energy Storage Buildout

New York has far exceeded the interim target on its energy storage road map — 1.5 GW of capacity by the end of 2025 — but has more work ahead as it pursues 6 GW by 2030.

The 2026 “State of Storage” report issued April 1 by the Department of Public Service (DPS) paints an optimistic picture of progress but notes that only 529 MW of the 1,952-MW storage portfolio was installed as of March 31 (Case 18-E-0130). The other 1,423 MW of contracted or awarded capacity is in various stages of planning or construction but not yet online.

Previous “State of Storage” reports showed 480 MW of storage in service in March 2025, 396 MW in March 2024 and 130 MW in October 2022.

DPS in the report said state-incentivized commercial storage systems of up to 5 MW capacity have an average total installed cost of $666/kWh. At 268 MW, this class of battery energy storage system (BESS) constitutes the majority of in-service projects. Residential systems averaged $638/kWh. Bulk systems larger than 5 MW that provide wholesale market services averaged $524/kWh.

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When New York boosted its storage goal to 6 GW, it proudly called the road map to that goal “nation leading.” (See NY Sets Strategy to Reach 6 GW of Energy Storage.)

In terms of stated goals, it did lead the nation, but in terms of progress, New York has been far behind the leading states.

As of April 2026, Texas has 12,740 MW of operational storage. As of November 2025, California had 16,942 MW of storage capacity online.
The U.S. Energy Information Administration reported in February that developers plan to add 12.9 GW of BESS in Texas and 3.4 GW in California in 2026.

DPS in the report said there has been progress in New York in cost reduction, workforce development and safety requirements.

However, wholesale markets could “better accommodate and make use of energy storage resources,” DPS writes, such as through a participation model for storage as a transmission asset (SATA).

A NYISO SATA proposal introduced in 2024 is expected to reach final tariff development and filing in 2026, the report notes.

‘Dramatic Need’

When New York Battery and Energy Storage Technology Consortium (NY-BEST) Executive Director William Acker spoke to RTO Insider in March, three weeks before the release of the 2026 report, he too flagged SATA.

He said New York lacks a compensation model that recognizes the value of storage to the state’s aging grid, as it limits the need to expand capacity to meet load growth.

“I think we clearly have a dramatic need for this technology in New York state,” Acker said. “Our challenge is making sure that the rule sets are right, and particularly that the energy storage is properly counted toward reliability, as far as T&D as we’re looking at these buildout solutions going forward.”

Another significant headwind for storage development in New York is the state’s regulatory structure, he said. “And it’s not just for storage, actually building anything is difficult.”

Acker pointed to one of the bullet points in a January 2026 NYISO report on the causes of New York’s high electricity prices: Of the 106 projects that had completed the NYISO interconnection process since 2019, only seven had begun construction. An earlier NYISO report tallied 4,315 MW of capacity leaving the system since 2019 and only 2,274 MW being added.

An added hurdle for storage: It is not permitted at the state level, leaving it vulnerable to local moratoria and restrictions imposed by officials worried about fire after three highly publicized BESS blazes in as many months in New York in 2023.

This remains a vexing issue for NY-BEST. Fires are rare and they most often strike older technology placed in outdated configurations, Acker said.

But when BESS fires do happen, they stick in the public mind.

New York added some of the nation’s strongest BESS fire codes Jan. 1, he said. “We’re hopeful that as people understand that better, we can open up more of the siting around the state. But really, that’s I think the major barrier right now.”

Acker sees other signs of progress.

“So, what’s changed over the past year really has been quite a few projects being approved and moving forward with the new and necessary incentives,” he said. “But actual commissioned projects, I don’t think has increased that much.”

Three weeks later, the 2026 “State of Storage” report would bear out Acker’s estimation: In-service storage capacity rose 10%, from 480 MW in 2025 to 529 MW in 2026, while storage capacity contracted but not yet in service jumped 54%, from 923 MW to 1,423 MW.

Another step forward was New York launching its first index storage credit solicitation in July 2025, Acker said. When bidding closed in January 2026, the state had received proposals for 46 projects comprising roughly 6 GW of power capacity and 30 GWh of storage capacity.

“The index storage credit,” Acker said, “makes for a method to give more confidence in the future revenues of the project, and clearly, it received a lot of attention from the developer space.”

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Xcel Files Large Load Tariff Proposal in Colorado

Xcel Energy is seeking approval for a large load tariff in Colorado that includes an optional clean transition tariff to encourage the development of carbon-free resources.

Public Service Company of Colorado (PSCo), an Xcel subsidiary, filed the proposal with the Colorado Public Utilities Commission on April 2.

The proposal is intended to address concerns “over the immense energy needs of new, large customers, such as data centers,” Robert Kenney, president of Xcel Energy Colorado, said in a release.

“Addressing those concerns by updating rules and policies will help make sure we manage this growth responsibly as we protect customers,” said Kenney, who noted the potential jobs, investments and innovation that large load customers bring.

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The tariff would apply to new customers with an electric load of at least 50 MW and to existing customers that are expanding by 50 MW or more. Large customers would pay for the power infrastructure needed to serve them, including transmission, substations, interconnection upgrades and new electric generation.

“This ensures that existing customers are not paying for the needs of the large load customers,” Xcel said.

In other provisions, customers would be required to provide credit support such as a guaranty or cash deposit. The minimum service period would be 15 years. Customers would be able to cancel service with 24 months’ notice but could be required to pay an exit fee.

Clean Transition Tariff

PSCo also proposed an optional clean transition tariff (CTT), aimed at supporting the acquisition of certain carbon-free generation resources.

A CTT resource is one that uses “emerging carbon-free electric generation technologies or long-duration storage technologies,” PSCo said in its filing. Examples include geothermal, hydroelectric, hydrokinetic, nuclear, renewably sourced hydrogen or fossil resources with carbon capture and storage. “Commercially mature” wind, solar, short-duration storage and carbon-emitting resources would not be eligible.

Under the proposal, the CTT resources may be those identified through PSCo’s resource planning process but not chosen for development or procurement. Alternatively, they could be emerging-technology projects that would not be selected through the company’s least-cost procurement process.

The customer would choose the resources and pay for them through agreements with PSCo, which would have discretion to evaluate project feasibility and negotiate the ownership structure.

The PUC has not yet set a procedural schedule for considering the tariff. Xcel asked that the new tariff become effective May 3.

Xcel is also working on large load tariffs in Minnesota, Wisconsin and Texas, CEO Bob Frenzel said during a fourth-quarter earnings call in February.

Large Load Tariffs Spreading

As the number of large load customers grows across the U.S., so does the adoption of large load tariffs.

In its Database of Emerging Large-Load Tariffs (DELTa), the Smart Electric Power Alliance found 77 either in place or being considered at utilities around the country. Large load tariffs have not been considered or adopted in only 12 states. (See SEPA Tracks 77 Large Load Tariffs Nationally with DELTa Database.)

A November 2025 study by RMI looked at the most common safeguards in 65 large load tariffs. Those included a minimum contract term, minimum monthly billing, collateral requirements and exit fees. Twelve of the tariffs reviewed allow large customers to transfer to another customer contracted capacity that is no longer needed — along with financial responsibility for the capacity.

PSCo’s commitment to filing a large load tariff came out of a PUC proceeding on the company’s Just Transition Solicitation, its proposal for how much energy it needs to serve customers for the next five years, with coal plant retirements factored in. The proposal also aims to reduce emissions and support communities where coal plants are retiring.

During the proceeding, environmental groups including the Natural Resources Defense Council, Sierra Club, Southwest Energy Efficiency Project and Western Resource Advocates backed the idea of a CTT.

Many companies developing large data centers might be willing to pay more for resources that help them meet clean energy goals, the groups said.

“At a high level, the clean transition tariff should allow large customers to voluntarily pay to be served by innovative, zero-emission resources that Public Service would not otherwise procure,” the commission said in November in its Phase I decision on the JTS.

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Spill at Northwest Dams Risks Causing ‘Catastrophic Harm,’ Feds Tell 9th Circuit

Federal agencies urged the U.S. 9th Circuit Court of Appeals to pause a lower court’s order that would increase spill levels at eight dams on the Columbia and Snake rivers, saying the order risks increasing rates and causing costly blackouts.

In the April 7 motion for stay pending appeal, the federal defendants said U.S. District Judge Michael H. Simon’s order aimed at protecting migrating salmon and steelhead “substantially increases the risk of catastrophic harm to the public through blackouts.”

Represented by the U.S. Department of Justice, the federal defendants include the U.S. Army Corps of Engineers, the Bureau of Reclamation, the National Marine Fisheries Service and the U.S. Fish and Wildlife Service.

“A stay pending appeal is warranted,” the motion stated. “Absent a stay, the elevated spill levels will cause irreparable harm to the public by increasing the cost of electricity, reducing grid stability and substantially increasing the risk of blackouts. Blackouts in neighborhoods disrupt communities, blackouts in hospitals cost lives and blackouts in military installations threaten national security.”

The agencies said the Bonneville Power Administration, which is not a party to the suit, expects the spill levels “to result in a loss of generation capacity of 1,000 average MW in August and 500 average MW in September.”

BPA has said it expected to end fiscal year 2028 with $397 million in financial reserves. But with the court order, the agency anticipates ending 2028 with $196 million in reserves.

BPA has launched a rate proceeding to tackle the issue. (See BPA Explores Rate Alternatives Following Order to Increase Dam Spills.)

In an email, Charisa Gowen-Takahashi, an attorney with Earthjustice who represents the plaintiffs, said the federal agencies’ request to block the injunction “is yet another attempt to stall on preventing extinction.”

“These salmon need help urgently,” Gowen-Takahashi added. “The stakes are too high for further delay.”

The Public Power Council filed a separate appeal the same day as the agencies’ motion.

In a news release, PPC said the appeal seeks to mitigate the order’s impact on electricity costs and grid reliability.

PPC CEO Scott Simms said Simon failed to account for the systemwide consequences of his order.

“An appeal is necessary to restore balance,” Simms said in a statement. “The law requires consideration of all authorized purposes of the Columbia River system – not just one – and that balance was not fully achieved here where the science supports the conclusion that the threatened fish species are recovering.”

The Inland Ports and Navigation Group also has appealed.

‘Overblown’

The issue stems from a Feb. 25 court order in which Simon granted a preliminary injunction sought by the states of Oregon and Washington, tribes and environmental groups. (See Judge Orders Spill at Northwest Dams to Aid Salmon, Despite Energy Concerns.)

The order requires the U.S. Army Corps of Engineers and the Bureau of Reclamation to spill large amounts of water over the eight dams to protect migrating salmon and steelhead in the Columbia and Snake rivers instead of running it through turbines.

The long-running case now concerns an environmental impact statement and a biological opinion from 2020 that the court ordered the federal agencies to prepare for the Federal Columbia River Power System.

In challenging the analysis, the plaintiffs alleged the Army Corps’ plan failed to adequately protect salmon.

The parties stayed the case after striking a deal with President Joe Biden, which included, among other things, $1 billion toward salmon restoration. President Donald Trump upended the deal in June 2025, claiming it would negatively impact energy production, shipping channels and water supply for local farmers. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams.)

When the case resumed, plaintiffs sought injunctive relief beginning March 1, urging the court to require federal defendants to increase spill levels, lower reservoir levels and implement emergency conservation measures for the salmon.

In granting the request, Simon said the injunction includes a provision for the federal agencies to adjust spill for emergency power generation and transportation needs. However, he rejected arguments that increasing spill levels could impact power generation, saying the granted relief is “narrowly tailored and essentially maintains the status quo.”

The order would impact eight dams on the lower Snake and lower Columbia rivers: Ice Harbor, Lower Monumental, Little Goose, Lower Granite, Bonneville, The Dalles, John Day and McNary.

In their April 7 motion, the federal agencies contended that under the previous deal, parties agreed to spill levels less than plaintiffs sought in their injunctive relief request.

When Trump assumed the presidency, “Plaintiffs now insist that substantially higher spill — particularly in August, when the agreement allowed reduced spill — is crucial to avoid imminent harm to fish, despite agreeing until 10 months ago that less spill protected the fish just fine,” the federal defendants contended.

Following the plaintiffs’ win, “initial estimates indicated the injunction could impose approximately $140 million/year in increased power costs,” according to Simms.

Commenting on PPC’s appeal, Gowen-Takahashi said she expected the move, adding that “we think the 9th Circuit will agree that we can protect salmon while making sure we have a reliable supply of energy in the Northwest.”

“We’ve heard complaints like this before about reliability and costs when the courts have previously ordered more spill over the dams for salmon,” Gowen-Takahashi said. “But those fears were overblown then, and they are overblown now.”

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ISO-NE, PJM Market Monitors Concerned about Vistra Acquisition of Cogentrix

Vistra’s acquisition of Cogentrix Public Utilities would increase market power and could undermine competition in ISO-NE and PJM, market monitors for the RTOs argued in comments filed April 7 (EC26-63).

The ISO-NE Internal Market Monitor urged FERC to require more analysis and consider behavioral conditions to address potential issues, while the PJM Independent Market Monitor said it opposes the transaction in the absence of mitigation measures.

The acquisition would add 1,625 MW to Vistra’s 3,567-MW portfolio in New England, the ISO-NE IMM noted. The combined total would equal about 16% of installed capacity in New England. In PJM, the acquisition would increase Vistra’s portfolio from 14,270 MW to 17,098 MW, the PJM IMM wrote.

“The transaction would result in a material increase in market concentration and structural market power, particularly within the dispatchable generation segment that is crucial to meeting the system’s energy and reserve requirements,” the ISO-NE IMM wrote.

The concentration of ownership would not fail FERC’s competitive analysis screen in either RTO. Vistra wrote in its application that Herfindahl-Hirschman Index (HHI) analyses indicated no screening violations and no potential competitive issues.

HHI threshold analyses are based on the sum of squared market shares of all participants. While FERC has long relied on HHI tests to evaluate market power, both market monitors argued that HHI screening is not adequate.

The ISO-NE IMM wrote that “the HHI and Competitive Analysis Screen do not provide a robust competitive analysis for the impact of the proposed transaction on the ISO-NE markets and the potential for the exercise of market power by the combined applicants.”

The inclusion of small-scale and intermittent resources in the HHI analysis “masks a heavy concentration of resources with sizeable market shares,” the market monitor wrote.

It said its pivotal supplier test and residual supply index metrics indicate the acquisition would create a portfolio that is pivotal “in a substantial share of real-time intervals, including the majority of high-load hours.”

It also wrote that initial analysis indicates the combined portfolio could have “both the ability and the incentive to profitably raise prices,” adding that existing market power mitigation measures may not be adequate to prevent this behavior.

The PJM IMM expressed similar concerns to those included in its recent comments about Talen Energy’s proposed acquisition of 2.5 GW of generation from Energy Capital Partners. (See Monitor Warns Talen Acquisition Will Increase PJM Market Concentration.)

The market monitor wrote that Vistra is a pivotal supplier in PJM’s energy and capacity markets and the acquisition would increase the company’s means and motive to exert market power.

It also reiterated its concerns about a broader concentration of generation ownership in PJM amid “extremely tight” market conditions.

“The current need for new generating capacity in PJM is an opportunity for increased competition and new entry,” Monitoring Analytics wrote. “Instead, ownership of existing generation is being consolidated in a small group of owners.”

New England does not face as tight market conditions, but growing demand, coupled with the region’s struggles to add new capacity, could create resource adequacy issues starting in the mid-2030s. ISO-NE forecasts the region’s reserve margin declining from about 17% in 2026 to 8% in 2034.

The ISO-NE IMM asked FERC to establish a hearing or settlement proceeding to enable more in-depth analysis and consider more requirements to mitigate potential issues.

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SPP Issues 1st Resource Advisory in West BA

SPP has issued a resource advisory for its West balancing authority area less than one week after expanding into the Western Interconnection.

The advisory is effective April 8 through April 13 at 12 a.m. (CT) and was issued to raise awareness of potential threats to reliability among entities responsible for operating transmission and generation facilities, SPP said. It cited load uncertainty, the increased potential for low output ahead of peak hours from wind and other variable energy resources, and possible resource outages.

Resource advisories are not unusual for SPP and are issued frequently during the shoulder months when generation and transmission outages are taken.

“The underlying factors are pretty typical for the region this time of year,” SPP spokesperson Meghan Sever said. “Nothing alarming, but exactly the kind of conditions our advisories are designed to flag early so operators can prepare.”

To mitigate reliability risks because of these factors, the RTO could use greater unit commitment notification time frames. That could include making commitments before standard day-ahead market procedures and/or committing resources in reliability status.

SPP completed its RTO Expansion into the West at midnight April 1. (See SPP Successfully Completes Western RTO Expansion.)

The grid operator considers resource advisories as the third and final level of normal operating conditions. They are two levels away from an energy emergency alert and do not require the public to conserve energy or take other actions.

SPP’s East BA area remains under normal operating conditions.

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We Energies Defers Oak Creek Coal Units’ Retirement Through 2027

We Energies announced it will extend the operating lives of coal-fired Units 7 and 8 at its Oak Creek Power Plant through the end of 2027, delaying retirement of the 60-plus-year-old plant for a third time.

At a combined 610 MW, the units entered service in the 1960s. They were scheduled to retire at the end of 2026.

The latest postponement conforms to a trend of We Energies asserting it still requires the units to meet rising demand in Wisconsin. In June 2025, the utility announced it would defer idling the units until the end of 2026, citing a need to meet periods of high demand. At the time, the plant was scheduled to retire at the end of 2025. That followed an earlier extension of a 2024 retirement date.

In a filing to the U.S. Securities and Exchange Commission, We Energies’ parent company, WEC Energy Group, said its April 1 decision is rooted in “two critical factors: reliability and affordability.”

“This past winter the Midwest power market experienced tightened energy supply and higher energy costs during the extreme temperatures. Keeping Units 7 and 8 available will better position [We Energies] to serve customers with safe, reliable and affordable energy on the hottest and coldest days of the year,” WEC said.

The parent company added that the units’ extension would serve as a “bridge until new dispatchable generation begins to come online, which is expected in late 2027.”

Based on WEC’s investor relations materials from late 2025, data center plans from Microsoft in Mount Pleasant and Vantage in Port Washington could effectively double We Energies’ energy demand by 2030. The two campuses are expected to require a combined 3.9 GW.

We Energies is currently working on constructing new natural gas plants in Oak Creek and Paris. The Public Service Commission approved construction of both plants in 2025.

WEC pledged in 2023 to stop burning coal at power plants by the end of 2032.

The Sierra Club unsurprisingly met the news with criticism.

“We Energies’ digging their heels in on fossil fuels continues to cost Wisconsinites with higher energy bills, more air pollution and climate impacts,” the environmental nonprofit said.

Jadine Sonoda, a campaign coordinator at Sierra Club Wisconsin, asked rhetorically if anyone is “surprised that Wisconsin’s largest and most profitable utility keeps squeezing us for more money?”

“Wisconsinites aren’t oblivious to We Energies’ scheming. We know We Energies can’t be trusted to make good on their promises to retire coal, and we know that they’ll turn to the PSC to approve any rate hikes they can get. Big Tech has been looking to build data centers in Wisconsin as a huge cash-grab, and We Energies wants in with their fossil fuels instead of prioritizing the affordable clean energy transition Wisconsin has been demanding,” Sonoda wrote.

We Energies and WEC’s Wisconsin Public Service both filed requests in early April with the PSC for rate increases in 2027 and 2028.

We Energies has filed a formal request for a 4.7% increase to base electric rates in 2027 and an additional 4.5% in 2028. The utility said the increases involve a $13 increase per month for a typical residential customer in 2027, and an $8 to $9 increase the following year.

The announcement stands to affect We Energies’ ask to recover more than a half-billion dollars in rates for the early retirement of Oak Creek. FERC in early 2025 set the request for settlement and hearing procedures. (See FERC to Weigh in on Cost Recovery of Oak Creek’s Early Retirement.) At the time, the company said it “no longer expects [Oak Creek] to provide net economic benefits to its customers due to the current regulatory climate.”

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CAISO Draft Tx Plan Includes $1.4B for Project Serving Silicon Valley Large Loads

CAISO’s 2025/26 draft transmission plan proposes more than $1 billion for an infrastructure project that would help power new data centers and other large loads in California’s Silicon Valley.

The $1.4 billion Tesla-Metcalf project is the largest proposed reliability project in CAISO’s 2025/26 proposed transmission plan, which includes a total of 38 projects for about $7 billion.

The Tesla project would add two 230-kV lines in the San Jose area to relieve congestion on existing 230-kV lines and various 115-kV lines. CAISO previously found NERC thermal violations on certain lines in the area.

Pacific Gas and Electric’s territory, which would house the Tesla project, has seen a dramatic increase in data center developer applications over the past year. As of August 2025, PG&E had applications for about 10 GW of new data center load, up from about 5.5 GW at the end of 2024.

Between Q3 and Q4 2025, about 2 GW of data center projects moved into PG&E’s final engineering phase, while an additional 50 MW began construction during that time. (See Data Centers Breeze Through PG&E’s Approval Process.)

The increasing rate of load growth stemming from new data centers, EVs and building electrification is expected to create new challenges for the grid, CAISO said in the draft plan. The ISO’s load is expected to increase by 1.8 GW by 2030 and 4.9 GW by 2040 due to data center growth alone, according to a California Energy Commission study in January.

CAISO’s plan also touched on energy affordability, which has become a primary concern at many California energy agencies this year — especially the state’s Public Utilities Commission.

“We recognize the concerns around electricity affordability and are committed in our annual transmission planning process to find ways to meet system needs efficiently and cost-effectively while also providing the best customer value over the long term,” Neil Millar, CAISO vice president of transmission planning and infrastructure development, said in an April 7 press release.

As part of the plan, CAISO proposed the use of reconductoring to increase transmission capacity without having to construct new lines. Staff landed on 12 reconductoring projects as a cost-effective solution to meet electricity demand forecasts.

The plan also includes the $1.68 billion policy-driven Trout Canyon-Lugo 500-kV line project in Southern California Edison’s region, The project, which consists of a new 180-mile-long line between the Trout Canyon and Lugo substations, is estimated to come online in 2035.

CAISO also proposed canceling the $1.1 billion Del Amo-Mesa-Serrano 500-kV project in SCE’s territory, which had been approved in the 2022/23 transmission planning process. SCE had raised the cost estimate to about $5 billion, and the ISO said the project no longer is required because the area now has enough resources and infrastructure due to an additional 2,000 MW of battery storage added downstream from the previously identified line overloads.

EDF Renewables asked CAISO to consider upgrades in the Fresno area, which could see “massive renewable curtailment” of over 7,000 GWh by 2040, the company said in comments to CAISO.

“This level of trapped generation indicates a severe lack of export capability that cannot be solved by battery storage dispatch alone,” the company said.

CAISO’s Board of Governors plans to vote on the 2025/26 transmission plan at its May 19 board meeting.

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Wary Local Officials Scrutinize Maryland Data Center Proposals

A proposal by Amazon Web Services to build a major data center next to a nuclear plant in Maryland has sparked scrutiny from local officials and the state ratepayer representative over its potential impact.

The data center arm of the online retail giant has yet to file a formal proposal, but plans outlined by Amazon officials at a March 26 public meeting described the eight-building project next to the Calvert Cliffs Nuclear Power Plant on the Chesapeake Bay.

The power plant, which produces 1,790 MW, is owned by Constellation Energy and is a potential partner on the data center project, Amazon officials said. The 50-year-old plant is Maryland’s only nuclear facility, accounting for 40% of the state’s energy, according to the U.S. Department of Energy.

The proposal is one of two data center projects being floated for development in Calvert County. Developer Natelli Holdings at a public meeting April 6 outlined a 300-MW project with four 200,000-square-foot buildings to house “computing, networking, routing and storage systems” for tasks, including AI work on a 133-acre site about five miles from the nuclear plant.

Existing Transmission Lines

Nicole Morales, spokeswoman for Amazon, told RTO Insider the hearing was part of its “due diligence” to ensure its project “won’t impact how other customers receive power and that we continue to pay for our full cost of electricity to power our operation.”

Amazon has released scant details about the project but emphasized the economic and employment benefits while highlighting the advantages of the site.

“This campus is unique in that it’s located directly adjacent to an existing nuclear power facility,” Michael Fredette, an Amazon representative, said at the hearing.

“It’s crosscut by three different extra-high-voltage transmission lines, which provides a good opportunity for a data center to come in and secure highly reliable, scalable power to both continue to scale up the overall generation capacity in the region, as well as to serve that load for data center purposes,” he said.

David Lapp, who heads the Maryland Office of People’s Counsel that protects ratepayer interests, told RTO Insider his agency is “sort of waiting to see what happens next.”

“We are very concerned about the impacts on existing customers,” he said. “The impacts can be through higher capacity market prices, higher energy prices, as well as transmission costs. So, we’re concerned about all three of those.”

If the project requires power from existing energy capacity, “there are significant risks” that may increase costs for existing customers, he said.

Economic Benefits vs. Burden

The Amazon proposal has emerged as data center developments are facing local responses, such as opposition over the heavy use of electricity, who pays for infrastructure upgrades, and the extensive water use for cooling.

After the AWS project became public, which surprised members of Calvert’s Board of County Commissioners who knew little about the project, a commissioner called for a 24-month moratorium on granting data center approvals to ensure public input on such projects is gathered.

Maryland, like other states, is evaluating how to reap the economic benefits of data centers, while balancing their burden on local infrastructure and ensuring the added demand does not push up electricity prices.

PJM estimated that data centers will grow from 4% of Maryland’s power demand in 2024 to 12% in 2029 and 16% in 2039. (See Maryland: The State Where ‘Transmission Has Come to Die’.)

A report by the Maryland Tech Council, a pro-technology trade group, noted the state faces a $3 billion budget deficit and concluded data centers “represent a transformative economic opportunity” at a critical moment.

“These capital-intensive development projects can help the state address the fiscal challenges that are being exacerbated by looming federal job and spending cuts,” the report said.

Another data center planned for Adamstown, Md., faced vigorous opposition from residents concerned about the disruption, noise and burden on utilities.

Transmission Investment

Becky Ford, speaking for Amazon at the meeting, said the proposal is a “potential project” that is “not a done deal” but one the company is “evaluating as part of our initiative to support our customer requirements.”

Because the target area is zoned “heavy industrial,” no new zoning will be required. She also addressed concerns that data centers typically have heavy water consumption.

The AWS plans say no new water will be required to cool the data center beyond the amount already used by the Constellation plant, she said.

“Once it’s been through their cooling system, it will come over to our facility and be used to cool our data centers, and then it will be sent back through the same process and at the same standards that currently exist,” Ford said.

Fredette said the company is “committed to continue paying our full share for electricity costs to power our data centers and provide the services to our customers.”

He said Amazon would “need to make a long-term revenue commitment to the transmission operator in this scenario, [Baltimore Gas and Electric], where we will have to pay for transmission-related costs regardless of if our load shows up. So, if a megawatt never spins, we are still contributing to existing and future transmission-related costs.”

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States, Environmentalists Argue DOE is Usurping Authority via 202(c)

States and environmentalists argue the U.S. Department of Energy is trying to usurp planning authority over generation through its use of the Federal Power Act’s Section 202(c).

DOE has used the “emergency” authority to force numerous coal-fired plants to continue operating past their planned retirement dates.

“Emergency powers, the Supreme Court recently warned, ‘tend to kindle emergencies,’” the states of Illinois, Michigan and Minnesota said in a joint brief. “This case proves the point. DOE’s emergency power has kindled a wildfire of purported emergencies spreading nationwide from Michigan to Indiana, Pennsylvania, Colorado, Washington and beyond. In the past year, DOE issued more 202(c) orders than in its entire history and shows no sign of stopping.”

The three states and a group of environmentalists, who filed another brief with the U.S. Court of Appeals for the District of Columbia, were responding to DOE’s first brief in the appeal of the order stopping the J.H. Campbell coal plant in Michigan from retiring in May 2025. The 90-day order has been renewed repeatedly since. The case is furthest along among all the appeals of 202(c) orders, with oral arguments scheduled for May 15. (See DOE Defends Use of Emergency Orders in Court Filing.)

DOE has clear authority over emergency responses, but it lacks authority over long-term resource adequacy planning. The FPA reserves that for the states, and in some cases the ISOs and RTOs regulated by FERC, the three states said. Long-term resource adequacy is handled through processes where rates are set prospectively and conform to the requirements of environmental law.

“DOE now attempts to bypass that robust process,” the states said. “Acting under its emergency power, DOE is unconstrained by the normal guardrails of utility law. Public process is unnecessary. Cost is no object. Rates are set retroactively. Environmental laws may be ignored.”

The orders rest on DOE’s legal effort to strip the word “emergency” of any independent meaning. The term is the lynchpin to DOE’s authority under 202(c) — allowing it to overrule environmental laws and renew the order after 90 days when needed “to meet the emergency.” Without a fixed meaning for emergency, 202(c) has no fixed limits, they said.

“DOE claims that its emergency authority is triggered the moment any future risk presents a need for long-term planning, without regard to its imminence or the availability of routine interventions to address that risk,” the states said. “And it claims authority to supersede state and RTO decisions about what units may retire and, based on its own unsubstantiated claims of years-away regional ‘needs,’ keep those plants running indefinitely through an endless cycle of 90-day orders.”

While the order suffers from numerous fatal legal flaws, the states said the court needs to hold that DOE is held only to a plain text reading of “emergency,” or DOE’s own regulatory definition of the term. Both compel the same conclusion: an emergency is something exigent, imminent and unexpected, the states said.

Environmental Defense Fund, Earthjustice, Natural Resources Defense Council, Sierra Club and other environmental groups filed another joint brief that made many of the same points.

“The department’s brief confirms that it is seeking to transform Section 202(c)’s rarely invoked emergency provision into a sweeping authority to address any potential electricity shortage, no matter how far off,” the environmentalists said. “This unprecedented power grab has supplanted the entities responsible for long-term grid planning under the Federal Power Act — states, utilities, grid operators and FERC.”

The order at issue in this case has torpedoed years of planning around Campbell’s retirement by Michigan regulators and MISO, which already had procured replacement generation. DOE claimed its order saved lives during a cold snap this past winter, but the environmentalists said it just racked up costs while exposing neighbors of the plant to more pollution.

“The department cannot square its secretary-knows-best approach with Section 202(c)’s limits,” the environmentalists said.

DOE can issue generation to stay online only where an emergency exists due to a “shortage of electric energy or of facilities for the generation or transmission of electric energy.”

DOE’s brief argued that 202(c) is not limited to “imminent shortages of electricity” because it reaches any shortages of electric power, even if a “blackout might not materialize for years.”

“The department’s contrary reading rests on its showing that an ‘emergency’ can be long-lasting, but it cites nothing to establish that an ‘emergency’ can encompass a crisis that may not emerge for years,” the environmentalists said. “The department’s desire to address such longer-term generation and reliability challenges cannot override the Federal Power Act’s clear assignment of that authority to others.”

If Congress had wanted 202(c) to be as expansive as DOE claims, it would have omitted the word emergency and allowed it to be used whenever a shortfall of electricity was anticipated, they said.

“The department’s fallback is that ‘emergency’ cannot require imminence because one dictionary and some courts have recognized that emergencies can be long-lasting,” the environmentalists said. “That is a non-sequitur. Whether an emergency can be long-lasting is a separate question from whether an emergency is defined by a need for immediate action.”

The structure of the FPA confirms that 202(c) is a stopgap to address exigencies, not a tool by which the federal government can fix longer-term problems.

“Other provisions of the Federal Power Act — including Sections 202(a), 202(b), and 215 — speak directly to the federal government’s limited authority over long-term resource adequacy and reliability planning, reflecting Congress’ intent to preserve primary responsibility for utility regulation with the states,” the environmentalists said. “This ‘backdrop of clear and limited delegations’ illustrates that Congress did not intend for the department to ignore these constraints and ‘unlock … extraordinary power’ based on a ‘declaration of emergency.’”

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PJM Estimates FERC Order to Require Over $1B in Transmission Rebilling

PJM estimates it may need to rebill over $1 billion in transmission charges under a FERC order requiring the RTO to eliminate the de minimis exception from the process it uses to determine transmission rates.

The order, issued March 6, affects transmission rates going back to June 2015. (See PJM Eyeing Tight Deadline to Eliminate De Minimis Exception, Rebill Decade of Tx Rates.)

The exception exempted from the cost allocation formula any zone responsible for less than 1% of the flow modeled on a transmission upgrade, unless the upgrade occurred within that zone. FERC’s order rejected a settlement between PJM and several transmission owners that would have resolved a complaint by Long Island Power Authority (LIPA) and Neptune Regional Transmission System challenging the exception (EL15-18, et al.).

In response to the order, PJM filed a request asking the commission to reconsider requiring resettlement or to exempt the rebilling from the typical interest charged. It also asked for an additional 270 days — on top of the 90 days the order allowed — to conduct the rebilling and included a list of clarifications to how it should calculate the resettlement amounts.

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

“The order on remand directed the largest ever resettlement the commission has ever required of PJM in scope, complexity and reach,” PJM wrote in its request. “Resettlements will affect all customers across the PJM region and may require resettling costs associated with over 1,200 transmission projects. While the exact amount of transmission charges that will need to be resettled is not yet known, PJM anticipates that complying with the order on remand will result in the need to resettle an estimated amount between $1.5 [billion] and $2 billion (plus interest).”

PJM proposed a three-step process for determining which projects will be subject to resettlement and how billing and credits will be allocated. It would first recalculate the cost responsibility assignments, transmission owners would submit new revenue requirement information and PJM would calculate refunds and surcharges, including interest. The filing stated PJM will need 270 days for the first step and two to three years for the remaining work.

The clarifications PJM sought include whether:

    • it can surcharge entities facing increased transmission rates under the recalculated rates;
    • it is responsible for paying refunds not collected through surcharges; and
    • the costs of reliability-must-run agreements are subject to resettlement.

It also asked how to address instances in which entities that were assessed transmission rates affected by the order have gone out of business since 2015.

PJM Associate General Counsel Jessica Lynch on April 7 told the RTO’s Planning Committee the resettlements could cause significant bill shocks for utilities and their customers, as well as liquidity challenges. The RTO’s preference is to recalculate billing for each of the 11 years affected by the order one at a time and send out refund and surcharge amounts when they are complete, which is expected on a roughly monthly cadence.