ERCOT unveiled a long-term load forecast for 2031 on April 8 that adjusts projections provided by transmission providers and accounts for the uncertain nature of data centers and other large users.
The numbers still are staggering. Even reducing the amount of utilities’ projected loads based on historical data, the study forecasts demand to reach 145 GW in 2031. That is less than transmission providers’ projections of 218 GW in 2031.
The grid operator’s current peak demand is 85.5 GW, set in August 2023.
“Several people are looking forward to [this], with bated breath,” Bill Flores, chair of ERCOT’s Board of Directors, told COO Woody Rickerson before he presented the adjusted methodology to the directors.
The new treatment of load projections is a result of state legislation passed in 2023 (House Bill 5066) that updated regional transmission planning rules and required ERCOT to consider prospective loads identified by transmission providers. Previously, state laws prohibited the grid operator from factoring in load that was not financially committed or signed.
The legislation also directs ERCOT to file an annual report quantifying the capability of existing and planned generation and load resources. Staff plan to meet that requirement by using their semiannual Capacity, Demand and Reserves (CDR) report, as they did in December 2024 by using the TSPs’ load forecast.
“We’re going to pivot away from using that forecast in this year’s May CDR,” Rickerson told the board. He noted the legislation’s “most impactful difference” was ERCOT accepting transmission providers’ officer-attested letters, which he attributes to much of the future data center load growth.
delaying the in-service date by 180 days for all new large loads;
reducing new data center demand to 49.8% of the requested forecasts; and
reducing officer-attestation loads to 54.55% of forecasts.
Rickerson said the reductions represent a “measured percentage of power being used” versus the forecasts.
“An important part to keep in mind here is that this is a forecast based on the most recent data we have, and we’ll continue to update that as we move forward,” he said. “Those numbers were derived from loads that had been forecasted that we can now see and measure. Those numbers, as we move forward, can change as forecasts become more accurate.”
The problem, Rickerson said, is how to count the large loads (75 MW or more) that data centers, hyper-scalers and crypto miners are planning.
The board questioned Rickerson on the accuracy of data provided by transmission providers.
“Data centers are not something that we were forecasting or looking at four, five years ago, so this is new information. How fast it builds out is something we’re all going to learn together,” he said.
Rickerson said the quality of data needs to be adjusted “based on just the leading edge of historic numbers.” As ERCOT gets more of those numbers, he said, the grid operator’s adjusted load forecast and the transmission providers’ aggregate projections likely will merge into one.
ERCOT CEO Pablo Vegas said Senate Bill 6, an omnibus energy bill being considered in the 2025 Legislature, includes provisions addressing the inputs into transmission providers’ forecasts.
The ISO will begin incorporating the adjusted load forecast in transmission planning, resource adequacy and outage coordination analyses. Rickerson said a good-cause exception may be required from the Public Utility Commission.
There could be some good news in the future over the escalating demand ERCOT faces.
Pia Orrenius, a senior economist with the Federal Reserve Bank of Dallas, followed Rickerson’s presentation by saying the Texas economy is “likely slowing.”
“[Business] outlooks have recently turned pessimistic,” she told the board, noting surveys of Texas businesses are “flashing some warning signs.”
“Growth is likely to slow further … and will probably slow further than we’re currently forecasting,” she said. “The main reason is tariffs. They’re going to lead to higher prices. Consumption and investment will slow and possibly decline.”
MISO’s proposal to use a temporary “fast lane” in its interconnection queue to speed up necessary resource additions would give utility-owned generation preferential treatment, according to protesters’ comments filed with FERC on April 7, with a group of former commissioners saying it should be a nonstarter.
The RTO filed its proposal to install the fast lane by the beginning of summer with FERC on March 17. (See MISO Says Queue Fast Track Design Settled, Ready for FERC.) The plan would have projects designated as essential by regulators traversing a separate queue equipped with dedicated, individual studies instead of the cluster-style studies MISO uses in its ordinary queue (ER25-1674).
MISO staff have said its current interconnection procedures are not up to the task of processing new projects expeditiously because of a buildup of projects with study delays. The grid operator has proposed using the special process for the next four years to overcome capacity deficits.
The plan drew a letter from eight former FERC commissioners — Democrats and Republicans alike — to express “deep concern.” The group, which includes past Chairs Richard Glick, Neil Chatterjee, Joseph T. Kelliher and Pat Wood III, said creating a special, expedited interconnection study treatment in the queue “presents the opportunity for self-dealing by utilities to advance their affiliated generation.”
The former commissioners said the fast lane’s process, in which a proposed generating facility must either be owned by a load-serving entity or have a power purchase or similar agreement with proof of load, appears unworkable. The group pointed out that independent competitive generation projects have historically been unable to finalize offtake terms and arrangements in contracts until they are assigned network upgrade costs in the queue. They called the plan a threat to FERC’s policy of open-access transmission.
They also questioned whether regulators would use an independent process or seek to avoid undue discrimination when selecting projects for special study treatment. They said PJM and CAISO’s recent adoption of queue expressways differ from MISO’s, which is “not narrowly tailored and allows affiliated generation to receive preferential treatment.”
“It has been nearly 30 years since FERC first planted the flag of open access when the commission issued Order No. 888. We have come too far to reverse course now, especially when, as other regions have demonstrated, more narrowly tailored options to expedite the generator interconnection process for resource adequacy purposes are available,” warned the former commissioners, which also include James Hoecker, Donald Santa, Nora Mead Brownell and John Norris.
States Divided
Support for the proposal among MISO’s states fell along retail choice lines.
The Illinois Commerce Commission said it believed the fast lane would discriminate against retail choice jurisdictions and give preferential treatment to vertically integrated states. While state identification of need would work for those that use integrated resource plans, it wouldn’t work for Illinois, which relies on competitive markets to ensure resource adequacy, the ICC said.
Illinois is MISO’s only true retail choice state; Michigan allows up to 10% of a utility’s retail electric sales to be purchased from alternative suppliers.
“Unless the proposal is amended, the projects in Illinois will be at a disadvantage,” the ICC argued. MISO’s proposal as is does not contain “workable language” to include Illinois or Michigan in short-term reliability considerations, it said.
Rolling out the special queue lane in a staggered manner wouldn’t be a solution, either, the ICC said, because by the time MISO established specialized rules for Illinois, the state would have suffered “irreparable economic harm” from the delay.
Vistra, which operates resources in downstate Illinois’ Zone 4, agreed. The company said the fast lane would bestow undue preference for generation in vertically integrated states, violating the Federal Power Act, and give LSEs a leg up over independent power producers.
Vista said MISO is failing to ensure the fast lane would be limited to interconnection requests needed to meet resource adequacy or reliability requirements. The company argued that a request from a regulatory authority to study a resource does not mean it will meaningfully contribute to resource sufficiency.
“If MISO is going to take the exceptional step of allowing select resources to bypass the queue in the name of meeting near-term reliability needs, then there must be a reasonable basis for concluding that these resources can meet the specific reliability needs identified by MISO,” Vistra said.
The Michigan Public Service Commission expressed concern that the plan could worsen “inherent inequities” unless applicants for expedited treatment show they have analyzed whether existing projects in the queue could solve the resource adequacy problem they seek to address. Absent that step, MISO could facilitate discriminatory practices and “do grave harm to fundamental principles of open-access transmission that have been core tenants of FERC’s regulatory framework since the issuance of Order 888 in 1996,” the PSC said.
It also said it doubted MISO’s commitment to bringing projects online as soon as possible because its plan includes a three-year grace period beyond its proposed three-year-out commercial operation date for expedited projects.
Earthrise Energy, which also owns generation in southern Illinois, said FERC should direct MISO to amend its filing so it includes a separate plan for Illinois and Michigan.
But the proposal drew plenty of support from vertically integrated states, including two governors.
Missouri Gov. Mike Kehoe, whose state turned up a capacity deficit in MISO’s 2023/24 Planning Resource Auction, said it is “committed to swift action to meet the needs of this moment.” He said that the express lane can help the industry meet unprecedented load growth reliably.
Indiana Gov. Mike Braun also supported the fast lane, saying it’s “essential for energy development” in his state.
“We are committed to providing reliable, affordable energy to all Hoosiers, but we cannot move as swiftly as necessary without MISO being equally as swift,” Braun wrote. MISO is right to recognize it needs urgency and a unique means to manage a confluence of accelerated load growth, a rash of resource retirements and lagging resource additions.
The Organization of MISO States framed the plan as a “necessary but limited mechanism” to maintain reliability across the footprint. OMS said most of its members support “enabling an alternative pathway other than the standard queue to meet immediate resource adequacy needs.”
The Arkansas, Louisiana, Mississippi and Texas commissions supported the proposal. Entergy operating companies, which make up the lion’s share of MISO South, were similarly on board.
Entergy Texas noted that it needs to bring its Legend and Lone Star gas plants — worth 1.2 GW collectively — online by 2028 to serve growing demand. Entergy Louisiana noted that it needs three new gas plants of its own at 2.26 GW to serve a new Meta data center. Entergy Arkansas said MISO’s queue backlogs “unreasonably impede” new generation coming online.
Questions over Fairness for IPPs
IPPs predicted that the fast lane, which wouldn’t use a megawatt cap to limit entries, would soon form a “second, unmanageable queue that would paralyze the MISO interconnection process.”
They also echoed Vistra’s concerns that regulators could make errors deciding which projects are essential and questioned “MISO’s decision to delegate many of the key terms and conditions of interconnection service to state and local regulatory authorities outside of FERC’s jurisdiction and leave those processes ripe for arbitrary and unduly discriminatory outcomes in violation of the FPA.”
They echoed the former FERC commissioners’ discrimination arguments and said the plan would put those developing competitive generation at a disadvantage while creating opportunities for LSEs to engage in self-dealing.
Public interest organizations, including the Sierra Club, Natural Resources Defense Council and Union of Concerned Scientists, called the proposal a “queue-jumping mechanism for preferred projects.”
Alliant Energy battery storage in Portage, Wis. | Alliant Energy
“In MISO’s own telling, such a proposal is necessitated by MISO’s failure to maintain a process that timely processes interconnection requests from new generation. And as a result of this failure, MISO now claims that it needs to create a separate interconnection process to ensure that these preferred projects are able to come online by the time they are needed for grid reliability,” the groups said. They added that MISO was missing a “technical quantification” of its RA need in its proposal.
NextEra Energy said the “gravity of harm that will be caused … cannot be overstated” and predicted that the proposal would give vertically integrated utilities free rein to “self-build their own generation solutions, bypassing gigawatts of independent generation stranded in MISO’s legacy interconnection queue.”
The Coalition of Midwest Power Producers (COMPP) lambasted the filing as well. It said MISO didn’t quantify its resource inadequacy and wrongly omitted Michigan’s Zone 7 and Illinois’ Zone 4 from the plan. COMPP said together, those two zones contain about 31 GW of load, just 3 GW less than the whole of MISO South. It asked FERC to reject the filing.
The Clean Grid Alliance (CGA) said the expedited proposal is redundant because MISO already has efforts underway to speed up its queue, including study automation help from tech startup Pearl Street, higher fees and the capping of annual entrants at 50% peak load.
CGA said expedited generation would be allowed to claim transmission capacity that otherwise could be available for projects in the traditional queue, causing harm to developers. It also said MISO didn’t seem to be considering that some of its 56 GW with signed generator interconnection agreements would overcome delays to come online and handily manage a projected shortfall of a few gigawatts. (See MISO Members Grapple with 54 GW in Incomplete Gen, Predict Storage Expansion.)
“Rather than meaningfully parsing out data from its queue and even attempting to match queued generation to sub-region resource adequacy shortfalls, MISO merely makes conclusory statements and cites to its reports that claim there is a resource adequacy shortfall,” CGA argued.
LSEs: RA Needs Above All
Michigan-based Consumers Energy said that even though the 1,603-project, 296-GW interconnection queue appears to be able to deliver on resource adequacy, more than 70% of projects drop out of the queue.
Consumers said the high withdrawal rate, coupled with supply chain, permitting and study delays, translates into waiting times for projects that regularly exceed three years. On the other hand, a fast lane is a “tool that can help identify necessary projects and provide a path for a limited number of these resource adequacy projects to get connected in time to meet customer needs.”
Duke Indiana said the fast track would be a solid plan, pointing out that NERC’s 2024 Long-Term Reliability Assessment indicated that MISO may experience a 4.7-GW shortfall in 2028 “if the current expected generator retirements occur without the addition of significantly more generation.”
DTE Energy, Alliant Energy, Ameren and WEC Energy Group likewise filed in support, all stressing MISO’s resource adequacy needs.
Transmission owners said the proposal is “tailored” to avert conflicts between expedited projects and those in the queue’s usual definitive planning phase by allowing both to be processed in tandem. TOs also said the plan is “intentionally targeted and time-bound with a built-in sunset date, at the latest, by the end of 2028.”
MISO has acknowledged its stakeholders are concerned over the potential for discrimination between generation projects and whether a need really exists to create a dedicated fast track in the queue. But staff maintain the proposal is necessary and won’t be unduly preferential.
“We have a significant resource adequacy need we’ve been projecting for a few years,” MISO’s Andy Witmeier said at a Dec. 6, 2024, workshop. He pointed to the warnings MISO delivers on a quarterly basis in front of its Board of Directors.
Witmeier said MISO is confident that it has enough “inherent barriers” in place to the fast lane that there won’t be a “mad rush” where developers enter projects “willy nilly.” He said projects must be recognized and accepted by a state to meet a known need before they are able to gain entry.
“MISO has always been open to queue reform and trying to make the process better … and more efficient for all users,” Witmeier said, noting that in the five years he has worked on the queue, the RTO has continually made improvements.
He said it is prepared to hire additional consultants, contractors or temporary personnel to take on the additional work of the fast lane, resulting in higher processing fees for interconnection customers, though it should be straightforward. MISO won’t create special studies; it will just conduct its usual interconnection studies on a condensed timeline by focusing on a single generating unit, he said. “We know how to study interconnection requests.”
MISO on April 7 announced it will scrap its plan to use an existing demand response participation category to get aggregators of distributed energy resources participating on a limited basis a few years ahead of its full implementation of FERC Order 2222 in 2030.
During a DER Task Force meeting, MISO counsel Michael Kessler said the RTO decided that trying to bend the interim plan to all Order 2222 requirements as FERC recommended would be “unduly burdensome.” Kessler said MISO plans to inform FERC by July that it will abandon its DR participation idea rather than try to make it fully compliant with the rule.
FERC accepted MISO’s second try at Order 2222 compliance Jan. 16, granting the RTO until mid-2029 to prepare before fully accepting DER aggregators into its markets in 2030. (See FERC Permits 2030 Finish Date for MISO Order 2222 Compliance.)
The commission accepted MISO’s explanation that its underlying computer systems need work over the next four years. However, it told the RTO its plan to allow DER aggregations in its markets earlier in a two-phase rollout needed to be either deleted or revised significantly.
MISO proposed to use a two-stage approach to Order 2222 compliance. First, it would use an existing DR resource participation category to get DER aggregations participating sooner — albeit on a limited basis — and providing energy, contingency reserves and capacity through behind-the-meter generation or controllable load. MISO would have begun registering DER aggregations under its DRR Type I model by Sept. 1, 2026, and would have allowed participation to begin by June 1, 2027. DER aggregations would have been limited to 1 MW or larger under the model.
But in its Jan. 16 order, FERC said MISO’s proposed 1-MW size threshold is too large, as Order 2222’s minimum for participation is only 100 kW.
The commission also said MISO’s DR placeholder doesn’t address the coordination, data requirements or means to discourage double-counting of resource contributions required under Order 2222. It decided the RTO missed the mark on using an existing participation model to eke out partial compliance.
FERC gave MISO 180 days to either explain how the DRR Type I participation model could comply with Order 2222 or strike the first phase of participation from its compliance plan. MISO decided over the last few weeks that it would not salvage that aspect for a separate filing to allow DER aggregations to provide some services by the middle of 2027.
Kessler said MISO attempting to make its planned, interim step complaint with Order 2222 would likely require the same system changes that aren’t doable until full compliance with the rule in late 2029 through mid-2030.
FERC last week approved U.S. LNG developer Venture Global to commence service on the remainder of the facilities at the Calcasieu Pass LNG Terminal in Louisiana, according to a filing.
Venture Global recently asked FERC for permission to begin operations at its entire Calcasieu Pass LNG export facility and TransCameron pipeline project, the final step before moving to commercial operations.
FERC last week approved a 122-mile natural gas pipeline expansion cutting through East Tennessee.
The Ridgeline pipeline will stretch from Smith County to the TVA’s Kingston power plant. To fuel the plant, Enbridge’s pipeline company plans to extend its pipeline all the way to Roane County.
Construction is set to begin in the fall and be completed by fall 2026.
BLM Extends Public Comment Period for Oregon Lithium Project
The Bureau of Land Management last week extended the public comment period for a lithium exploration project in Oregon to April 25.
BLM has been reviewing Jindalee Resources’ proposal to explore federal land for lithium since 2022. The agency published its resulting environmental assessment in late March and gave the public just five days to review and comment. BLM received more than 1,500 comments in those five days.
The proposal includes drilling at more than 260 sites across 7,200 acres of sagebrush desert in Malheur County, near the Oregon-Nevada border, in search of lithium.
SouthCoast Wind and utility companies in Rhode Island and Massachusetts last week announced a three-month extension to finish contract negotiations for the 147-turbine wind farm planned south of Martha’s Vineyard and Nantucket.
The new June 30 deadline marks the third delay since Rhode Island and Massachusetts jointly unveiled plans in September to buy power from SouthCoast Wind following a solicitation that included Connecticut. Supply chain delays and inflationary pressures have driven up developer costs, prompting some companies, including SouthCoast, to renege on existing pricing agreements in hopes of a more lucrative deal. That has put more pressure on utilities and ratepayers to cover the rising expenses.
Polis Signs Bill Recognizing Nuclear as Clean Energy
Gov. Jared Polis last week signed a bill that will have the state recognize nuclear energy as “clean energy.”
This year’s bill passed the Legislature with bipartisan support, with a 43-18 vote in the House and a 29-5 vote in the Senate.
Nuclear energy production in Colorado has been dormant since 1989, when the state’s only nuclear power plant, Fort St. Vrain in Weld County, ceased operations.
MidAmerican Energy last week filed a request with the Utilities Commission seeking approval to add a 0.4% capital investment charge to the bill of residential gas customers.
MidAmerican spokesman Geoff Greenwood said the charge, which would add about 17 cents to the average residential bill, would “cover costs that Mid-American has already paid out that are associated with certain natural gas system costs.”
Gov. Moore Issues Executive Order that Could Delay EV Sales Penalties
Gov. Wes Moore last week issued an executive order that could delay initial penalties for EV manufacturers who do not meet sales goals under a prescriptive state plan that is supposed to take effect next year.
The order will maximize the Department of Environment’s enforcement discretion “to ease compliance” with the rule – including by declining to enforce penalties for model years 2027 and 2028. Moore’s order stated that President Donald Trump’s tariffs and actions on electric vehicles, including rescinding funding for charging infrastructure, also pushed Maryland to intervene to assist manufacturers.
Maryland adopted Advanced Clean Cars II, which requires EVs to account for 43% of cars sold in the state by a manufacturer in the 2027 model year. The number grows to 51% in 2028, eventually reaching 100% by the 2035 model year. The state also adopted a similar rule for larger vehicles such as trucks. Moore’s order also opens the door for the DOE to avoid enforcing penalties on those vehicles for model years 2027 and 2028, unless the agency releases an assessment on the rule by Dec. 1.
DPU Acts Against National Grid over Billing, Service Issues
The Department of Public Utilities last week took action against National Grid, limiting how much it can collect from customers after months of billing failures and fining the company millions of dollars for service issues in 2023.
The DPU told National Grid in its letter that it was not allowed to bill customers for several months of energy usage, saying, “For each customer who has not received a bill since the beginning of the peak season, the company shall waive charges for any usage occurring more than 60 days prior to the date the company sends the customer its next bill. For customers who did not receive a bill for more than 60 days, the company shall either waive collection of amounts owed for usage more than 60 days prior to the date of said bills or, if the customer has already paid, the company shall credit or refund such sums to each customer.”
The DPU also fined National Grid $15 million “for service quality failures in 2023.”
Senate Committee OKs Bill to Give Governor Power to Appoint 3 PSC Members
A bill that aims to give the governor and the Senate the power to appoint and confirm three of the Public Service Commission’s five members passed the Energy, Technology and Federal Relations Committee with a 9-4 vote.
Currently, all five members are elected by voters in five separate districts and can serve two four-year terms back-to-back. If the bill were to be signed into law, only two of the members would be elected by voters in the state’s two congressional districts. The other three would be appointed by the governor and would need confirmation by two-thirds of the Senate.
A similar bill introduced in the House earlier this year failed to get out of committee.
The Scranton Zoning Board last week voted 3-2 to approve what will be the city’s first commercial solar farm.
Bear Peak Power of Denver will construct the 3.2-MW farm with 6,580 solar panels on 13.7 acres.
Further reviews could take 12-18 months, with construction beginning after that. If so, it could be until late 2026 or early 2027 before the facility is operational.
PacifiCorp Changes Plans for Dave Johnston Coal Plant
PacifiCorp last week altered its plans for the Dave Johnston coal-fired power plant while solidifying plans to stop burning coal at the Naughton power plant by the end of this year.
Rather than fully retiring two of four coal-burning units at the Dave Johnston plant in 2028, the utility now plans to convert those units to natural gas in 2029 and continue their operation. A third coal unit will be shut down in 2027, as previously planned, and the fourth, which had no retirement date, will now be converted to natural gas in 2030.
The company’s plans for the Jim Bridger plant and the Naughton plant didn’t change. Two of four coal units at Jim Bridger were converted to natural gas last year, and the company still plans to retrofit the other two units there with carbon capture technology by 2030 or 2032. At Naughton, the first of three coal units was converted to natural gas in 2020. PacifiCorp confirmed it still plans to take the two remaining coal units offline by the end of this year and resume operating them on natural gas in 2026.
Delta Utilities Acquires CenterPoint’s Distribution Companies Serving La., Miss.
Delta Utilities last week announced it has acquired CenterPoint Energy’s three regulated natural gas local distribution companies that serve Louisiana and Mississippi.
The sale includes around 12,000 miles of main pipeline serving about 380,000 customers.
Brookfield Asset Management is said to be putting the final touches on a deal to acquire Colonial Pipeline, the largest U.S. fuel transportation system, for more than $9 billion including debt, according to people familiar with the matter.
Colonial’s pipeline system stretches more than 5,500 miles from Houston to New York’s harbor. It moves more than 100 million gallons of fuel daily, including gasoline, jet fuel, diesel and heating oil, according to its website.
A deal could be formally announced in the coming weeks, barring any last-minute snags, the sources added.
APA Solar, a solar racking company, last week announced it is planning to build a new 30,000-square-foot headquarters building in Ridgeville Corners, Ohio.
The company said it will invest $19.5 million and hire 133 people as part of the expansion. The investment follows an upgrade in 2023 in which the company invested $10 million to expand its Henry County manufacturing facility.
Construction of the headquarters is expected to be completed in early 2026.
Lithium Americas Reaches Final Investment Decision for Thacker Pass Mine
Lithium Americas last week said it has reached a final investment decision for constructing the first phase of the Thacker Pass lithium mine in Nevada.
The Thacker Pass project is a joint venture between Lithium Americas and U.S. automaker General Motors. Phase 1 of the project is expected to be completed in late 2027. Once open, it is expected to produce 40,000 metric tons of battery-quality lithium carbonate per year in its first phase, enough for up to 800,000 EVs.
LA JOLLA, Calif. — As the U.S. Department of Energy explores using federal land for data centers powered by nuclear energy, experts say public-private risk sharing will be crucial to making nuclear viable.
The DOE on April 3 issued a request for information related to developing data centers on federal land, with 16 potential sites identified as “uniquely positioned for rapid data center construction, including in-place energy infrastructure with the ability to fast-track permitting for new energy generation such as nuclear,” according to a news release.
The issue of nuclear energy and data centers also was discussed in La Jolla, Calif., during the joint spring conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB) on April 4.
WECC’s 2024 Western Assessment of Resource Adequacy (WARA) found that annual demand in the Western Interconnection will grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and twice the 9.6% growth forecast in 2022 resource plans. (See West to See ‘Staggering’ Load Growth, WECC Report Says.)
WECC said large loads are a major factor in the rapid demand growth, including data centers, factories and cryptocurrency mining. Electrification also plays a role.
While there is widespread support for nuclear energy, which holds the potential to supply large amounts of baseload emissions-free electricity, there is a need for risk sharing, especially in the beginning as the industry navigates costs, construction cycles, regulations and other challenges, said Marcus Nichol, executive director of new nuclear at the Nuclear Energy Institute.
“The utilities that might own and operate and build these, they’re willing to take on some risk,” Nichol said. “We’re actively working with them to help reduce the risk so that it’s more manageable. But they need help to be able to take this on.”
Nichol noted that there are federal tax incentives in place, and U.S. Sen. Jim Risch (R-Idaho) introduced the Accelerating Reliable Capacity Act in December to accelerate investment in commercial nuclear projects by minimizing cost overrun risk.
States also are “looking at their own state-tailored policies to be able to help contribute to taking on some of the risk,” Nichol said. Some data center developers also are looking to “contribute and take on some of the risk as well,” Nichol added.
For example, Constellation Energy plans to reopen Three Mile Island Unit 1 under a power purchase agreement with Microsoft to sell about 835 MW to serve the company’s data centers. (See Constellation to Reopen, Rename Three Mile Island Unit 1.)
Amazon, meanwhile, has committed $1 billion to early stage development work, said Nate Hill, head of energy policy at Amazon.
“From Amazon’s perspective, we’re willing to put our capital at risk to help get some of these early stage projects off the ground,” Hill said. “Because, I mean, when you think about it, like some of the costs of these projects could be more than the market cap of some utilities. So, there’s going to have to be risk sharing.”
Katie Rogers, manager of reliability assessments at WECC, noted that the numbers could change as WECC learns more about how much of the demand will be realized.
Still, the industry must move toward holistic grid planning and share the burden, Rogers said.
“It feels very much like that we maybe need to have a different approach to how we plan the grid, and maybe not looking at, you know, one person carrying or one subset of people carrying all the risk if it has broader implications to the grid,” Rogers said. “It needs to be looked at holistically with everything.”
FERC has accepted ISO-NE’s compliance proposal for Order 2023, setting the stage for sweeping changes to the RTO’s interconnection procedures.
The April 4 ruling came nearly eight months after ISO-NE’s proposed effective date of Aug. 12, 2024, and followed months of stakeholder requests for rapid action to preserve the transition timeline and prevent significant delays to projects in the interconnection queue (ER24-2009, ER24-2007).
FERC’s ruling largely accepted ISO-NE’s proposal but directed the RTO to make relatively minor changes in an additional filing.
Order 2023 and the follow-up ruling, Order 2023-A, require transmission providers to transition from serial interconnection processes to cluster study processes, in which interconnection requests will be studied simultaneously.
In comments submitted to FERC, developers generally supported the filing, though several groups requested changes, such as a shorter cluster study timeline and reduced study deposit requirements. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.)
Allco Finance had urged the commission to reject the proposal due to impacts it would have on distribution-level projects and argued ISO-NE does not have jurisdiction over state-level interconnection procedures. But FERC ruled the complaint was outside the scope of the proceeding, finding the company had not demonstrated ISO-NE failed to comply with Order 2023 or Order 2023-A.
Despite arguments from some stakeholders that ISO-NE should adopt the 150-day cluster study timeline outlined by Order 2023, the commission accepted the RTO’s proposal for a 270-day process. ISO-NE said a 150-day timeline would be infeasible for the region.
FERC agreed the 270-day timeline “reflects ISO-NE’s unique regional issues and the comprehensive scope of its studies, including electromagnetic transient studies for inverter-based resources.”
The commission also approved ISO-NE’s proposal to reduce the cluster restudy timeline from 150 to 90 days, noting the RTO “will use the same base case data as the cluster study and will involve fewer interconnection requests, thereby allowing interconnection requests to proceed expeditiously through the interconnection study process.”
FERC also accepted ISO-NE’s proposal to require a flat $250,000 deposit and a $50,000 application fee for the cluster study, writing that “extending the $250,000 deposit to smaller generators is reasonable due to regional differences because … project size is not a ready indicator of study cost or complexity for interconnection requests in New England.”
It rejected arguments by Glenvale Solar that ISO-NE’s proposed deposit requirements are prohibitive for smaller projects participating in the process, saying the “proposed flat deposit structure reasonably approximates study costs in New England.”
The commission also approved ISO-NE’s proposal for a $500,000 initial commercial readiness deposit, writing that the amount will help deter speculative interconnection requests. Order 2023 requires commercial readiness deposits to be twice the size of study deposits.
“While higher than the pro forma [Large Generator Interconnection Procedures], we find the variation is justified because the $500,000 amount reflects historically high network upgrade costs in ISO-NE,” FERC wrote.
Optimism Around Transitional CNR Study
FERC also accepted ISO-NE’s initial prohibition of using surety bonds for deposits, despite Order 2023’s direction to do so, saying the RTO demonstrated it needs more time to develop the procedures for accepting the bonds. The order directed the RTO to submit more information about when it will begin accepting surety bonds for commercial readiness and study deposits.
ISO-NE’s transition process for adopting the changes also largely complies with Order 2023, FERC wrote. The commission wrote that the creation of a transitional capacity network resource (CNR) group study helps to appropriately balance “the need to move expeditiously to the new cluster study process with the need to respect the investments and expectations of interconnection customers at an advanced stage in the existing interconnection process.”
The transitional CNR group study is intended to allow projects with complete system impact studies to gain capacity interconnection rights without needing to go through the full cluster study. Going forward, interconnection customers will achieve capacity interconnection rights through the cluster studies.
In recent months, project developers have raised alarms that FERC’s inaction on ISO-NE’s compliance proposal could threaten the ability to align the transitional CNR study with the qualification activities for ISO-NE’s 2025 reconfiguration auction (RA). (See New England Generators Remain in Limbo on Interconnection Reform.)
ISO-NE had said it would need a ruling by March 31 to align the transitional CNR group study with the 2025 RA qualification process due to a show-of-interest submission deadline at the end of April. On March 31, FERC took the unusual step of informing ISO-NE and stakeholders that it planned to issue an order in the coming days. (See FERC Announces Impending Order on ISO-NE Order 2023 Compliance.)
Alex Lawton of Advanced Energy United, who has been vocal about the importance of the transitional CNR study, said he’s optimistic FERC’s ruling will enable ISO-NE to proceed with the study.
A representative of ISO-NE said the RTO “is reviewing the April 4, 2025, order in detail and assessing next steps.”
The ruling also accepted independent entity variations related to site control requirements, the opportunity to reduce project size prior to a cluster restudy, energy storage modeling and the evaluation of alternative transmission technologies.
FERC directed ISO-NE to make a series of relatively minor changes to its proposal within 60 days, including to correct multiple “unexplained deviations” from the pro forma language, and to add pro forma language that was omitted. The commission also found the proposal did not comply with Order 2023’s ride-through requirements.
The commission accepted ISO-NE’s proposed Aug. 12, 2024, effective date and the June 13, 2024, deadline for interconnection customers to have a valid interconnection request to be eligible to participate in the first cluster study. While the RTO briefly reopened its interconnection queue April 1, requests submitted after this date will not be eligible to participate in the transitional cluster study. (See ISO-NE to Reopen Queue as it Continues to Wait on Ruling from FERC.)
The Edison Electric Institute, GridWise Alliance and WIRES asked FERC on April 3 to end a proceeding that has been open for five years to consider cuts to transmission incentives (RM20-10).
The commission opened the rulemaking in March 2020 and supplemented it a year later to propose eliminating the existing RTO membership transmission incentive for utilities that have been participating in an organized market for more than three years. The proposal would have focused project-specific incentives on the benefits to customers from transmission investment.
“The commission’s current transmission incentives policy is working to the benefit of customers, transmission owners and the public interest,” they said in a joint filing. “With the rising demand for electricity, the commission’s existing transmission incentives policy has become even more essential.”
A lot has changed since the rulemaking launch, they said, including a rapid and unforeseen return to demand growth because of large data centers, reshoring of industry and general electrification pressures. The COVID-19 pandemic led to an economic slowdown and uncertainties in the economic forecasts on which the industry relies.
FERC also issued Orders 1920 and 1920-A, which are intended to identify considerable new transmission portfolios that might also introduce new risks to development because of the selection of larger and more complex projects, the groups argued. The world also is entering into a period of greater geopolitical tensions and competition, in which promoting domestic energy independence and security is considered a heightened priority.
While the three trade groups want FERC to abandon the rulemaking, they argued even if the commission wants to go forward, it should take more comments so parties can update the record for the changes over the past half decade.
President Donald Trump has declared a national energy emergency, in which he emphasized the urgent need to revamp and expand the grid to meet growing demand and ensure reliable supply, they noted.
“This infrastructure is not only essential for accommodating the increasing power demands from various sectors, but also for maintaining and enhancing the overall resilience and efficiency of the nation’s energy system, which itself underlies the broader economy,” they said. “A reliable, resilient and efficient energy delivery system is the foundation to providing cost-effective electric service to customers of all kinds, thereby aligning with the administration’s broader goals of fostering economic growth and energy security.”
The incentives date back to the Energy Policy Act of 2005, which acknowledged that increased levels of transmission infrastructure were needed to keep costs reasonable and the system reliable. FERC implemented them in 2006 with Order 679, which established tailored incentives to address risks and challenges associated with transmission development.
“After nearly two decades, it is undeniable that the commission’s transmission incentives policy has provided the signal and support for transmission investments that ultimately benefit electric customers,” the groups said. As FERC considers changing the incentive policy, it has to weigh whether this would disrupt expectations, create uncertainty and possibly chill investment by eliminating rate treatments that cut risk and aid in lower financing costs to benefit consumers, they said.
FERC’s proposed change would treat the RTO adder as an incentive to join an organized market, but the groups argued that was not Congress’ intent.
“The commission is, ultimately, ‘a creature of statute and has only those authorities delegated to it by … Congress,’” they said. “Any action that would restrict eligibility for this incentive beyond the requirement that a transmission owner join an RTO is ultra vires [beyond its legal authority].”
RTO membership requires TOs to transfer operational control of their facilities to the grid operators, which perform functions like planning, marketing and congestion management. The grid operators can require TOs to make investments in high-risk transmission projects, with the RTO adder helping to offset that risk.
“Transmission owners in RTOs must also comply with a more expansive set of federal regulations, such as Order Nos. 719, 745, 841 and 2222, which significantly and disproportionally impact RTO regions,” the groups said. “Through these actions, the commission has fundamentally altered the business model, exposed certain future capital investments of transmission owners to competition, increased the potential that investments will be delayed and deprive customers of the benefits, and created significant uncertainty and related regulatory risk.”
The RTO adder offsets risks incurred in delivering the benefits of RTO membership to customers such as access to cheaper power, efficient dispatch over a wide area and enhanced reliability, which together far outweigh the cost of the adder, they argued.
PJMpresented a $97 million increase to a project included in the 2022 Regional Transmission Expansion Plan (RTEP) Window 3. The change would remove two 230-kV lines between the Mars substation and Sojourner and Shellhorn facilities and reroute them to terminate at the south side of Mars to avoid intersecting with new lines being planned. The original scope is to build a 500-kV line between Mars and Golden and a 230-kV line from Mars to Lockridge and terminating at Golden. The changes bring the total cost to $439.9 million.
Projects included in the 2022 RTEP Window 3 also have obviated the need for two prior projects totaling $7.5 million. The rebuilding of a line between Loudoun and Morrisville will supplant a $4.5 million project to rebuild a 1.3-mile segment of that facility. A $3 million project to replace breakers at the Ox 500-kV substation also is being canceled as the same work is included in baseline projects.
Supplemental Projects
FirstEnergy presented a pair of projects amounting to $37.6 million to replace two 500/138-kV transformers and disconnect switches at its Pruntytown Substation in the APS zone due to the assets nearing end of life and experiencing maintenance issues. The projects are in the conceptual phase with in-service dates of Dec. 13, 2030, and June 13, 2031.
The replacement of another aging 500/345-kV transformer at Wylie Ridge is expected to cost $20 million with a projected in-service date of Dec. 13, 2030. The transformer has increased hydrogen and ethylene readings, moisture buildup and low dielectric strength, according to FirstEnergy.
American Electric Power presented a $50.4 million project to build a new 345-kV substation, to be named Navistar, in the AEP zone to serve a new customer bringing 437 MW of load to the New Carlisle, Ind., area. The facility would be cut into the Dumont-New Prairie 345-kV double circuit lines and would be configured as a breaker and a half with 11 345-kV breakers and two bus ties to the customer. The project is in the scoping phase with a projected in-service date of March 15, 2027.
Dayton Power and Light presented a $480 million project to serve two new customers located near Jeffersonville and Wilmington, Ohio, by expanding several 345-kV substations and linking the Clinton, Fayette and Atlanta facilities with new 345-kV lines. The Fayette and Atlanta substations would be expanded to breaker-and-a-half configurations to accommodate a 25-mile double circuit between the two sites, as well as two customer feeds from Fayette.
The Clinton facility would be expanded with equipment for a new 27-mile line to Fayette and two 345-kV customer feeds. The project is in the conceptual phase with a projected in-service date in January 2031. The Jeffersonville load is expected to come online in September 2026 and ramp up to 1.5 GW of load by 2031, while the Wilmington customer is expected to come on in 2028 and grow to 500 MW.
PPL presented a $101 million project to expand the proposed Tresckow 230-kV substation to include a four-bay breaker and a half 69-kV yard to serve a customer expected to bring 300 MW of load to Hauto, Pa., in 2028. Four 230/69-kV transformers also would be installed, as well as two 69-kV double circuit lines connecting Tresckow to the Frac-Tres 69-kV No. 1 and No. 2 lines. The project is in the conceptual phase with a projected in-service date of May 30, 2028.
Duke presented a $49 million project to build a new 345-kV substation, to be named Gold Finch, along the Silver Grove-Red Bank 345-kV line to serve a new customer seeking to interconnect 300 MW in Clermont County, Ohio. Gold Finch would be configured as a ring bus with four 345-kV breakers and a control building. The project is in the scoping phase with an in-service date of June 1, 2028.
Dominion presented a $450 million project to upgrade several lines and transformers to address load drop and thermal violations on the Ladysmith CT-Fredericksburg and Ladysmith CT-Four Rivers 230-kV lines. The violations were identified in the 2025 do no harm analysis. The project is in the conceptual phase with an in-service date of July 1, 2029.
Phase 1 of the project, expected to be complete in January 2028, includes rebuilding 6.5 miles of the Summit DP-Fredericksburg Sub 230-kV line with higher capacity conductor; reconductoring 7.3 miles of the Ladysmith-Ladysmith CT line; adding two 500-kV capacitor banks to Ladysmith; and building a new 230-kV line running between Ladysmith, New Post, Lee’s Hill and Allman using a mix of new structure and vacant arms.
Phase 2 would go online in July 2029 to expand the Kraken 500-kV switching station to cut into the Summit DP-Fredericksburg Sub 230-kV line, the St. Johns-Four Rivers 230-kV line and the planned Ladysmith-Allman 230-kV line. The St. Johns-Four Rivers and Four Rivers-Elmont lines also would be rebuilt. The 115-kV lines from Fredericksburg-Four Rivers, Pinewood-Four Rivers, Four Rivers-Elmont, and Pinewood-N. Doswell lines would be “wrecked” and a new double circuit 230-kV line would be built from Kraken to Allman, along with a single circuit line from Kraken to Elmont.
Several additional Dominion projects would serve new service requests across its footprint. A $10.1 million project would construct a 230-kV ring bus with four breakers at its Trabue substation; two new 230-kV substations, Ruther Glen and Carmel Church, would be added to the Ladysmith CT-Four Rivers line for $87 million; and two new 230-kV substations, New Post and Lee’s Hill, would be built along the Fredericksburg-Ladysmith CT line for $43 million.
The Wabash Valley Power Alliance presented an $80 million project to construct a 15-mile, 345-kV line between AEP’s Elderberry substation and NIPSCO’s Stillwell substation. The line will be operated by MISO and is being submitted to PJM’s supplemental planning process to allow study coordination.
