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April 8, 2026

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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.

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“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.

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Solar, Wind Developers Detail Federal Permitting Impacts

A new report quantifies what has been stated widely in general terms: The federal permitting process is delaying, downsizing and deterring clean energy projects.

Crux on April 7 announced a market analysis based on a February survey of 50 wind and solar developers and permitting professionals. It found:

    • nearly 80% of developers are siting projects to limit exposure to federal permitting requirements;
    • federal permitting issues contributed to delays of six months on average for approximately 11 GW of impacted capacity among the survey respondents;
    • all the developers surveyed reported higher project costs from federal permitting, and 58% said their total increases were by 6 to 10%; and
    • developers surveyed want predictability and certainty in the permitting process more than speed or simplicity.

Federal review goes far beyond proposals on federal land. It can be triggered by such things as endangered species and their habitat, wetlands, water bodies, historic sites, federal financing, migratory birds and airspace obstructions.

The combined effects can be significant: All respondents said federal permitting was a contributing factor in project delays or cancellations.

The developers surveyed said they were looking not for weakened environmental protections but for consistent application of those protections. Asked what change they would most like to see, 72% said more predictable outcomes. Faster timelines (12%), simpler processes (8%), greater agency staffing (6%) and better community/stakeholder engagement (2%) were far down on the collective wish list.

The focus of the Crux analysis is clean energy, but the authors make the point that the “arduous and complex” development process cuts across all energy technologies, including the fossil fuels favored by the current administration.

The permitting process can serve to filter out projects with economic problems, community opposition and other problems, they say, but it has become onerous.

In an introduction to the report, Thomas Hochman, director of energy and infrastructure policy at the Foundation for American Innovation, wrote that the Inflation Reduction Act was passed without a companion package of permitting reform measures. It is still needed, he wrote, even as many provisions of the IRA wind down: “Time is money — and Congress now has an opportunity to drive down the carrying cost of deployment with bipartisan permitting reform.

“The exact contours of the deal are still to be seen, but the core components — reforms to [the National Environmental Policy Act], the Federal Power Act, the Clean Water Act and the [National Historic Preservation Act] — would benefit every energy source and every energy developer.”

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Arizona Task Force Issues Data Center Recommendations

Data centers are a hot topic for Arizona state officials in April, as the Arizona Corporation Commission has scheduled a workshop on the subject and the governor’s office has released a task force report with six data center-related recommendations.

The Arizona Corporation Commission workshop April 16 comes about a year after Commissioner Kevin Thompson opened a docket to review data center rate classifications and the possibility of more transparent rates.

Thompson said the docket could explore other topics such as behind-the-meter solutions for data centers and user-funded generation to help large customers meet their power needs.

“It’s important to balance the economic opportunities presented by data centers with the need to financially protect other ratepayers to ensure they are not bearing the rising energy generation and transmission costs associated with this burgeoning industry,” he said.

An agenda for the April 16 workshop was not yet available.

Revisiting Tax Incentives?

Gov. Katie Hobbs on April 2 released a report from the Arizona Energy Promise Taskforce, a group she established through a September 2025 executive order.

The 36-member task force consisted of private and public sector representatives, consumer advocates and subject-matter experts, whose goal was to address Arizona’s rapid growth in electricity demand. The work was managed by the Governor’s Office of Resiliency.

The task force report is divided into three sections, with one section devoted to data centers and other large loads.

The task force recommended an update to tax and financial incentives for large load customers. One possible next step is to propose statutory changes for the legislature to consider, “including eliminating the current tax incentive for data centers.”

Although task force members reached consensus on the recommendations, the Data Center Coalition, Microsoft and Google dissented on the recommendation regarding tax incentives.

Another recommendation is to require or incentivize large load customers to “proactively engage with communities and invest in community-identified priorities.” The report noted that siting and permitting large load facilities is becoming more difficult “due to local opposition and land-use conflicts.”

The task force also recommended helping local governments navigate large load development. That might include creating a technical assistance program for local jurisdictions and providing materials that explain to the public the energy, water and affordability considerations of large load facilities.

Other data center recommendations include:

    • supporting large load customer adoption of energy management tools;
    • exploring bring-your-own-capacity initiatives that work with utilities for project delivery; and
    • supporting the ACC’s data center docket “to prevent cost shifts, mitigate stranded asset risks and increase development transparency.”

In addition to the task force report’s large load discussion, the report includes sections on an Arizona strategic energy plan and a generation and transmission corridor strategic plan. The task force issued 31 recommendations.

“[The task force] came together and developed commonsense policies that lower costs, reduce bottlenecks and can help us deliver continued prosperity and economic growth,” Hobbs said in a statement.

Stakeholders Weigh In

Since Thompson opened the data center docket at the Arizona Corporation Commission in April 2025, comments have poured in from utilities, advocacy groups and Arizona residents.

In a July filing, Arizona Public Service said it had committed to serving about 3,296 MW of data center load, including 1,215 MW from existing facilities, with prospective customers expressing interest in about 17,000 MW.

“Through commission regulatory policy, customer contractual protections, and reforming rates for high-load-factor customers, Arizona can ensure that costs are fairly allocated … and large, high-load-factor customers do not shift cost to other customers,” APS wrote.

Southwest Gas also said it is seeing growth in its service territory, including inquiries from data centers and others with a high demand for natural gas. The company said it supports the commission’s efforts to address data center growth.

Resident Margo Itule wrote to the commission to highlight what she called “the dramatic dangers of data centers,” which she referred to as “energy vampires.”

“These mega corporations are harvesting and depleting our precious resources,” Itule said.

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TOs Ask FERC to Suspend Competitive Bidding in MISO and SPP

International Transmission Co., American Transmission Co., Ameren, Xcel, Entergy, Cleco and other transmission owners have asked FERC to suspend competitive bidding on transmission projects in MISO and SPP so the grid can be built out faster to accommodate the AI data center explosion.

The TOs argued in an April 7 complaint that MISO’s and SPP’s project solicitations impose “unjust and unreasonable” delays of 16 to 20 months — “just as harmful as broken permitting” — at a time when the U.S. “faces an unprecedented energy emergency and time is of the essence” (EL26-58). They characterized the grid operators’ competitive processes as a “morass” when demand is rising at rates not seen since World War II.

The group said FERC should either place a five-year moratorium on competitive bidding in MISO and SPP or exempt any transmission project needed to interconnect new generation or load from a solicitation process.

The collection of TOs, which includes Evergy, Oklahoma Gas and Electric Co., The Empire District Electric Co. and subsidiaries of ITC, Ameren and Xcel, calls itself the “Grid Acceleration Coalition.”

A pro-competition group, the Electricity Transmission Competition Coalition (ETCC), opposes the complaint, calling it “tone deaf” to concerns over ratepayer affordability.

“Without competition, a monopoly incumbent utility has zero incentive to reduce costs because the more they spend, the more their profits increase,” ETCC wrote.

The TOs asked FERC for fast-tracked treatment of their complaint by mid-July, before SPP would issue requests for proposals on two 765-kV projects from its 2025 Integrated Transmission Planning assessment: the Crawfish Draw-Woodward project and the Anthem-Seminole project in Texas and Oklahoma.

MISO’s and SPP’s competitive bidding processes inhibit the timely interconnection of loads and generation, hampering utilities’ ability to connect customers, preventing FERC from fulfilling its duty under the Federal Power Act to ensure access to electricity, and handicapping the race to develop advanced AI, the group argued.

The TOs cast doubt on claims that competition ultimately saves customers money, arguing that actual costs of projects exceed winning bids by 59 to 66%.

“The benefits of solicitations in MISO and SPP are (at best) unproven and, in all events, do not outweigh the certain harms from delay in those regions,” they wrote in the joint complaint. “Winners can promise the moon and then, after prevailing in the yearslong and opaque administrative process, leverage exceptions and escalators to blow through bids.”

The coalition predicted that competitive developers and their supporters would respond to the complaint with their “usual talking points” about the cost savings associated with Order 1000. But it said reviews of actual construction costs show anticipated savings have not appeared.

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“Competitive developers will have their anecdotes — of solicited projects completed on time and under budget, and of directly assigned projects that incurred delays or overruns. The coalition can meet those stories with examples of its own — solicited projects that are delayed for years and bust their budgets, and directly assigned that are completed timely and under budget,” the coalition said. “Building transmission is hard, and delays and cost increases are sometimes unavoidable. The important point, however, is that no publicly available study to date supports the proposition that solicitations systematically reduce construction costs or delays in MISO and SPP, accounting for differences across projects.”

The group reasoned that directly assigning transmission projects needed to connect new data center load would improve ratepayer affordability, given the White House’s Ratepayer Protection Pledge, which seven major technology companies reportedly signed on to. It said now that hyperscalers have committed to paying their fair share, bringing large loads online faster would help dilute costs among new customers.

The complaint argued that “bureaucratic red tape” brought on by MISO’s and SPP’s application of FERC Order 1000 “harms national security and economic growth.” It said electricity availability is the “binding constraint” to realizing the U.S.’s AI potential.

“And if we are serious about winning the AI race, that looming need must be solved now. If we choose in 2026 to add two years of delay to transmission projects in MISO and SPP, we will seriously undermine our nation’s ability to meet that challenge,” the coalition said, referencing its 16- to 20-month figure. It said the most “consequential” AI technologies likely would be developed between 2028 and 2035.

Among other projects, the coalition pointed to MISO’s 345-kV Wisconsin Southeast long-range transmission project, which was partially accelerated due to large loads. MISO reassigned some substation work associated with the project to incumbent ATC after originally awarding it to Chicago-based developer Viridon Midcontinent. (See MISO Reassigns Competitive Substation Project to ATC on Data Center Rush.)

The TOs said instead of MISO letting ATC take the lead without delay, the RTO assigned the project to a “nonincumbent developer — one with vanishingly little experience and not even authorized to operate in Wisconsin.”

The TO coalition added that it seeks “prospective relief limited to MISO and SPP” and isn’t asking FERC to rescind any projects that MISO or SPP already awarded to developers or reverse in-the-works solicitation processes.

MISO said it is reviewing the complaint and will file its response at FERC in the coming weeks.

Pro-competition Group Calls Complaint ‘Tone Deaf’

In an April 7 statement, the ETCC condemned the complaint and said it flies in the face of the Ratepayer Protection Pledge and President Donald Trump’s executive order to reduce anti-competitive regulatory barriers.

The organization said its data show that six recent winning bids in SPP reduced costs on average by 21% from the RTO’s estimate, and eight MISO winning bids lowered the RTO’s cost estimate by an average of 38%.

“The complaint is tone deaf to the electricity affordability crisis facing Americans. Suspending competition for five years in MISO and SPP would expose consumers in these regions to unchecked cost escalation for years, guaranteeing higher utility bills,” ETCC Chair Paul Cicio said. “MISO and SPP competitive transmission projects have been shown to have a better track record of adhering to cost containment and completion schedules than noncompetitive projects. A moratorium would move us backward at precisely the wrong time.”

ETCC said it will urge the U.S. Department of Justice to review the complaint.

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RFF Report Says 1.5-degree Climate Target No Longer Possible

Too many emissions are baked in to the atmosphere for the world to limit global average temperature rise to 1.5 degrees Celsius, which was the target for the 2015 Paris Agreement, Resources For the Future said in its Global Energy Outlook 2026 report.

The report summarized and compared eight reports with 14 forecasts on energy and the environment out to midcentury from groups and companies such as the International Energy Agency, Bloomberg New Energy Finance, BP and ExxonMobil. RFF harmonized those results to provide an apples-to-apples comparison, Senior Research Associate Emily Joiner said during a webinar April 7.

The scenarios include six baseline projections in which current trends continue, six based on announced policies and two ambitious climate scenarios where warming is held to 2 C by the end of the century.

“It’s evident from current emissions trajectories and still peaking emissions that the world will exceed 1.5 C of warming, and because of this, we chose to exclude 1.5 C scenarios this year,” Joiner said. “Second, global energy demand continues to grow strongly, with projections of generation to 2050 being revised upwards over the past few years of outlooks. Third, as electricity demand has grown, so too has the demand for electricity generated from coal, leading to a slower-than-previously-predicted transition away from the fuel.”

There is some variation in the numbers, but the report notes that the world has either already reached the 1.5-degree target, or it will soon.

“In the last three years, global temperatures averaged between 1.44 and 1.55 C above preindustrial levels,” the report said. “Although average temperatures could temporarily recede due to natural fluctuations in Earth systems, it is clear that the world cannot meet its 1.5 C goal.”

The fourth major trend is how different parts of the world are diverging, with the report splitting it into the west (the Americas, Europe, and Russia and its Commonwealth of Independent States) and the east (the rest of Asia, Africa, the Pacific and the Middle East).

Coal in the U.S. is getting a boost from the Trump administration and the growing demand for electricity. Emergency orders under Section 202(c) of the Federal Power Act are keeping about 21 GW of plants open, while plant owners have announced $175 million for upgrades to other plants, making them more likely to stay open, the report says. By 2050, cumulative carbon emissions from longer-lived coal could be 4,125 million metric tons by midcentury, which is equal to almost 90% of U.S. emissions from 2024.

“While the east and west consumed similar amounts of coal at the turn of the century, by 2024 the east used almost six times more,” Joiner said. “Coal declines in both regions under all scenarios, but the pace varies pretty widely.”

China and India are still building more coal plants than they retire, but projections are for China’s coal use to drop by midcentury, while India’s shows some growth in the next decade before leveling out. The studies RFF tracks in the report have revised their forecasts for Asian coal use upwards since 2024.

Power demand globally has been growing this century, and that trend is expected to continue for the next quarter century.

“From 2000 to 2024, world power generation roughly doubled,” the report says. “Over the next 25 years, growth ranges from a low of 59% … to more than doubling again under ambitious climate scenarios.”

Renewables are projected to make up most of that growth, with wind and solar accounting for 40 to 72% of world electricity generation by 2050. Nuclear generation grows under all scenarios, but the projections vary widely, from 31% to doubling under the ambitious climate scenarios.

While the world is not going to limit climate change to 1.5 C, and net-zero emissions by 2050 also is off the table, the goal was always going to be a stretch even when it was hatched at the 2009 U.N. Climate Change Conference in Copenhagen, RFF CEO Billy Pizer said.

“Even when we were talking about 1.5 degrees in 2009, we knew it was very aspirational,” Pizer said on the webinar. “It was going to be very difficult to achieve. I would also just note, you know, the 1.5-degree target, or the 2-degree target, those were always sharing the stage with net zero, at least over the last decade, as a way to articulate what we really mean.”

The world is at a dynamic place for climate negotiations and activity, he added. The report was released as the Iran War continues, and it is unclear how long the disruption to global oil and gas flows will last.

Climate negotiators are unlikely to revisit the 1.5 C target anytime soon, especially given that it is existential for some island nations, University of Michigan professor Jennifer Haverkamp said.

“I don’t think it would be the best use of the negotiators’ time and energy to be trying to revise the targets now,” she added. “Maybe some years from now, after we get past the Iran War and the Trump administration and figure out just how big an issue AI is for electricity demand, countries might want to revisit it.”

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PGE Asks Oregon PUC to Approve $1.9B PacifiCorp Deal

Portland General Electric has asked the Oregon Public Utility Commission to approve its proposed $1.9 billion purchase of PacifiCorp’s Washington assets, saying the deal paves the way for continued investments in the Pacific Northwest.

The deal, which is subject to state and federal regulatory approval, was first announced in February 2026. PGE submitted its application with the PUC April 3. (See PGE to Acquire PacifiCorp’s Wash. Operations for $1.9B.)

Under the agreement, PGE would set up a new Washington utility to purchase three PacifiCorp generation facilities, 4,500 miles of transmission and distribution lines, and a 2,700-square-mile service territory containing about 140,000 electricity customers concentrated in Yakima, Walla Walla and nearby areas, according to PGE’s application (UP 443).

The new utility goes by the working name Gem and would be a separate corporate entity from PGE, which will own 51% of the company, with Manulife Investment Management holding the balance.

PacifiCorp’s approximately 150 employees will be offered employment with Gem after the deal closes, PGE said.

In written testimony, Sujata Pagedar, PGE senior director of rates and regulatory affairs, said the deal is part of PGE’s efforts to tackle affordability pressures, reliability requirements, wildfires and the integration of clean energy resources.

The purchase “reflects the movement toward consolidation in the utility industry over the past decades,” Pagedar said. She noted utilities have “experienced strong demand and evolving policies that require significant investment in infrastructure.”

“Combined with steady increases in operating costs, utilities face financial pressure on cash flows, balance sheets and credit metrics,” Pagedar wrote. “The strategic combination of two operating utilities in the Pacific Northwest will enable PGE and Gem to attract the capital needed to finance capital investments on favorable terms in the future.”

The facilities include the 477-MW gas-fired Chehalis Power Plant, as well as the Goodnoe Hills and Marengo wind farms, rated at 94 MW and 234 MW, respectively.

The service area includes 84% residential and 16% commercial and industrial customers, according to the application.

Pagedar said the transaction would not impact PGE’s upcoming participation in CAISO’s Extended Day-Ahead Market (EDAM).

PGE and PacifiCorp are among the utilities that withdrew from the first “binding” season of the Western Power Pool’s Western Resource Adequacy Program (WRAP). They exited after voicing concern that participants in SPP’s alternative day-ahead market Markets+ would gain outsized influence because WRAP is a program requirement for Markets+.

Both utilities have backed development of an alternative RA program geared toward non-EDAM participants. (See Pathways’ ROWE Could Offer Western RA Program, PGE Says.)

“A regional resource adequacy framework that is under development offers a market-aligned approach to providing sufficient power supply across the region, reducing the need for redundant resources, lowering costs, and improving system reliability during extreme weather events or unexpected outages,” Pagedar noted in the written testimony.

Pam Sporborg, PGE’s director of transmission and markets, is also co-chair of the West-Wide Governance Pathways Initiative’s Launch Committee. The initiative was created as an independent organization to oversee CAISO’s energy markets.

In separate testimony, PGE Senior Director Treasurer Christopher Liddle said the combination of PGE and Gem would “serve a greater number of customers, gaining size and greater geographic and earnings diversification due to Gem’s operations in another state.”

“As a larger company, funds invested in any given capital project will represent a smaller proportion of overall company assets and capitalization,” Liddle said. “The combined companies will gain a larger, experienced workforce to share across systems.”

“This is a targeted step toward ensuring the continued delivery of safe, reliable power to our nearly two million customers in the West and Intermountain West,” PacifiCorp CEO Darin Carroll said. “This will improve the company’s financial stability while simplifying our operations to support our long-term commitment to customers in each of our remaining states.”

PGE asked the PUC to approve the transaction on or before March 1, 2027.

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Constellation Asks FERC for PJM Tariff Waivers for Crane

Concerned its restart of the former Three Mile Island nuclear plant could be constrained for years, Constellation Energy is asking FERC for waivers to parts of PJM’s Open Access Transmission Tariff.

Constellation’s March 31 request to FERC (ER26-2028) entails transferring capacity interconnection rights from Units 3 and 4 at its Eddystone Generating Station near Philadelphia to Unit 1 at Three Mile Island near Harrisburg, which it renamed the Crane Clean Energy Center.

As it stands, numerous regionally planned transmission projects must be completed before Crane can be fully deliverable, Constellation said.

Those projects have scheduled in-service dates as late as December 2030 but many of them already have experienced years of delays and could be delayed further, Constellation said.

Constellation has moved the expected completion date for Crane forward to the second half of 2027, and Constellation CEO Joe Dominguez said during a March 31 conference call with financial analysts that the company still expects to meet that goal despite the potential delays outlined in the FERC filing.

“I want to assure you we are working on that with PJM, and we continue to expect to start this unit in ’27,” he said.

The subject was not raised again during the call, either by Constellation officials or by analysts.

A company spokesperson elaborated April 7 via email:

“The Crane restart remains on track for the second half of 2027, and we continue to expect to be able to deliver energy to the grid at that time. While PJM projected 2031 for full deliverability of the facility based on the preliminary results of its first phase interconnection study, Constellation is actively engaged with various parties, including our utility partners, to evaluate a range of potential options to move that schedule forward.”

A PJM spokesperson said: “PJM recognizes the urgency of bringing new generation online as quickly as possible. We expect to clear up to 30 GW of projects for interconnection this year, including Crane. We are committed to connecting resources quickly and safely while maintaining the reliability of the grid and the integrity of the interconnection process.”

As of April 7, the PJM Independent Market Monitor and The New Jersey Division of Rate Counsel had motioned to intervene on the request in the FERC docket.

Constellation in its request to FERC noted the transmission projects identified as contingent facilities were planned and approved before Constellation asked PJM to include Crane in its Reliability Resource Initiative, the effort to expedite interconnection of new capacity in a market with potential capacity deficits looming. (See PJM Selects 51 Projects for Expedited Interconnection Studies.)

These contingent facilities include hundreds of miles of new 500-kV and 765-kV lines that are as far away as West Virginia and have a timeline stretching to December 2030, Constellation wrote.

Rather than wait for the work to be completed, the company is requesting a tariff waiver to remove Eddystone 3 and 4 from capacity resource status and a waiver allowing it to transfer Eddystone’s capacity interconnection rights to Crane.

Eddystone 3 and 4, each about 50 years old, had been scheduled for retirement May 31, 2025, but U.S. Department of Energy 202(c) orders have kept the two 380-MW gas/oil units online. (See DOE Extends Eddystone Emergency Order Through May.)

However, DOE specifically directed that the Eddystone units are not considered capacity resources and makes the case for transferring its capacity interconnection rights, Constellation pointed out.

Constellation added the waivers it seeks entail no known harm to third parties, no delay to PJM Transition Cycle No. 2, no effects to other projects and no market power concerns — the Independent Market Monitor already determined there were no market power concerns from deactivating Eddystone 3 and 4.

“Simply put, this is a Goldilocks opportunity,” Constellation wrote. “These circumstances present a one-time opportunity for the commission to ensure that more than 800 MW of baseload, dispatchable capacity can support customers and the grid as quickly as possible.”