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January 9, 2025

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PJM Capacity Market in Flux Going into 2025

Two years after PJM CEO Manu Asthana warned stakeholders the RTO will have to move quickly to ward off a reliability crisis brewing around 2030, the Board of Managers stated a capacity shortage now could come as early as the 2026/27 delivery year.

PJM begins 2025 with several proposals before FERC seeking to rework its capacity market and generator interconnection queue, while stakeholders work on an expedited Quadrennial Review of the market and changes to resource accreditation.

Two capacity auctions are scheduled for 2025 following several delays: The Base Residual Auction for the 2026/27 delivery year is set to be conducted in July, with the auction for the following year scheduled for December. The rules for those auctions, however, remain unclear amid the ongoing stakeholder processes and pending proposals.

While those changes are being considered, consumer advocates argue there is a break between capacity prices and the ability for developers to bring new resources online to lower prices. In a complaint to FERC, they make a case that so long as that gap persists, PJM’s Reliability Pricing Model (RPM) cannot deliver capacity in a just and reasonable manner. (See Consumer Advocates File Wide-ranging Complaint on PJM Capacity Market.)

One of the pillars of the advocates’ complaint is that capacity supply is being suppressed by several categories of resources being exempt from the requirement that all resources offer into the market, which would be addressed by a PJM proposal to expand the requirement to intermittent, hybrid and storage resources. Some stakeholders have advocated for the change on the basis that capacity is being withheld from the market, while renewable developers have pushed back, saying that making a change of this magnitude on such short notice could have a chilling effect on development.

Another PJM proposal would model the output of the Brandon Shores and H.A. Wagner generators outside Baltimore as supply. Both units left the market for the 2025/26 auction to operate on reliability-must-run agreements, which the Independent Market Monitor said was a major component in the substantial increase in clearing prices (ER25-682). (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

The proposal also would establish criteria for determining when an RMR unit can be counted as supply, limiting the practice to the next two delivery years and applying only to resources that can meet the needs of the transmission constraints they are being retained for while also retaining operational flexibility to provide capabilities akin to capacity. PJM told FERC it intends to pursue a more long-term solution to how RMR agreements interact with the capacity market.

The third prong of the filing would add language stating that resources that are categorically exempt from the requirement that market sellers offer into the capacity market do not hold “safe harbor against allegations of the exercise of market power that benefits an affiliated portfolio of market manipulation power.”

Queue Proposals

Another pair of filings propose to create expedited processes for new resources to proceed through the interconnection queue.

The Reliability Resource Initiative (RRI) (ER25-712) would allow 50 resources to be added to the Transitionary Cycle 2 queue, which PJM is about to begin studying. Projects would be scored and prioritized based on their capacity and effective load-carrying capability (ELCC) ratings, impact on zones facing capacity shortfalls, constructability and transmission headroom availability. PJM said it is meant to be a “one-time” solution that could allow about 10 GW of unforced capacity to quickly come online to address projected capacity shortfalls toward the end of the decade.

The RRI has been met with a mixed response from stakeholders, with some generation owners saying it would allow them to bring shovel-ready projects and uprates to existing resources to the market, while those with projects that have been in the queue for years have argued it would amount to cutting in line and discriminatory treatment. (See PJM Stakeholders Wary of Expedited Interconnection Proposal.)

PJM also proposes changes to its surplus interconnection service (SIS) process, which allows accelerated interconnection studies on projects co-located with existing resources that would improve their average output without exceeding the site’s capacity interconnection rights (CIRs). The changes would loosen the eligibility rules to allow projects that would require network upgrades, consume transmission headroom or result in “material adverse impacts” on short circuit and thermal limits. It would also expand SIS to apply to planned resources not yet completed.

And PJM plans to file in January yet another proposal, to create a parallel process for resources that would replace a deactivating generator at the same point of interconnection. The new process would take advantage of CIRs from deactivating generators to construct a new resource.

Endorsed by stakeholders in October, the proposal would create a nine-month timeline from when a developer submits an application to the drafting of an interconnection agreement. It would allow projects with minor network upgrades to proceed, including storage resources — a sticking point throughout the stakeholder deliberations.

Quadrennial Review Could See Changes to Demand Curve

To address the longer-term concerns PJM and its members have with the capacity market design, the Quadrennial Review of the market has been moved up by one year, with the aim of submitting a filing at FERC in the third quarter.

Through a handful of conceptual meetings in the fall and winter, the Brattle Group laid out its thinking on the demand curve and reference resource. In the most recent Quadrennial Review, PJM shifted to a combined cycle for the reference resource over a combustion turbine, but it has sought to reverse that in one of its capacity market proposals.

That change was proposed out of a concern that higher energy and ancillary service (EAS) revenues for CCs would lead to the net cost of new entry (CONE) falling to zero for some locational deliverability areas. Several additional parameters use net CONE as an input, including the penalty rate for generators that fail to perform during an emergency, compensation of black start units and the overall shape of the demand curve. The 2026/27 auction would be the first to use a CC reference resource.

Brattle also is exploring the possibility of PJM shifting from a variable resource requirement (VRR) curve to a marginal reliability impact curve, which could improve price stability and be adaptable to a sub-annual design if that is sought in the future. The design could yield a flatter demand curve, one of the major concerns stakeholders have voiced about the VRR curve, particularly as EAS revenues are projected to rise.

Data Center Growth Driving Transmission Upgrades

On the transmission side, PJM is grappling with how to supply rising load growth in the east, particularly around “Data Center Alley” in Northern Virginia, with new generation expected to come online in the west.

Staff have announced their intention to recommend a $5.8 billion package of Regional Transmission Expansion Plan upgrades to the board, with a vote on approval expected in the first quarter. (See “PJM Unveils Recommended Projects for 2024 RTEP Window 1,” PJM PC/TEAC Briefs: Dec. 3, 2024.)

In Transmission Expansion Advisory Committee presentations on the recommended project components, PJM staff said one of the factors it weighed in its selections was expandability because of the likelihood that additional grid reinforcements will be needed as load growth continues.

Presentations to the RTO’s Load Analysis Subcommittee on the preliminary 2025 Load Forecast included several transmission owners projecting tens of gigawatts of large load additions (LLAs). Those additions represent expected load growth not captured in PJM’s standard economic load growth models, but consumer advocates have argued the process by which they are included requires more transparency.

Bill Fields, deputy of the Maryland Office of People’s Counsel (OPC), said the transparency and standardization of data center load projections will be a major focus for advocates going forward. He said it is unclear how PJM is vetting LLAs, and he is concerned that developers scoping out one project across multiple utilities could lead to speculative or duplicative additions making it into the forecasts.

Consumer Advocates Seek More Capacity Market Changes

Consumer advocates laid out their own priorities at a December meeting of the PJM Public Interest and Environmental Organizations User Group (PIEOUG), including incentivizing storage and demand response participation in the capacity market, a sub-annual market design and changes to RTO governance. (See Rising Transmission Costs in PJM Concern Consumer Advocates, Enviros.)

Fields said there are roadblocks limiting the participation of DR and storage resources, both of which have been the subject of stakeholder discussions in recent months. The Market Implementation Committee has been examining the winter availability window for DR, which defines the hours in which the resource is considered available for dispatch for capacity emergencies in ELCC modeling. Curtailment service providers have argued the window limits consumers with a flat load profile from responding in winter.

The Markets and Reliability Committee voted to delay action on a PJM issue charge to establish rules for storage as transmission assets in October, with several stakeholders suggesting that the membership is saturated with work. Speaking at the Dec. 10 PIEOUG meeting, Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates are broadly supportive of expanding storage development, and they may seek changes to market rules through the PIEOUG.

Fields said it’s hard to see how PJM’s capacity market filings will be enough to address the concerns that advocates have with the market. While the RRI would allow some projects to progress and mitigate high prices, a mechanism is needed to keep prices reasonable so long as capacity prices cannot result in an actionable price signal, he said.

Under normal circumstances, PJM’s filings would constitute years’ worth of stakeholder attention and effort, not concentrated into a few months. Adequate analysis will be needed to ensure stakeholders understand the possible market impacts and to identify any unintended consequences, Fields said.

Capacity Accreditation

While several stakeholder efforts are focused on overhauling aspects of the capacity markets, they also continue to fine-tune the redesign to come out of the 2022 Critical Issue Fast Path (CIFP) process.

Three issue charges introduced by LS Power in the fall focus on the marginal ELCC accreditation methodology at the heart of the CIFP changes and are being worked on through the newly formed ELCC Senior Task Force. It is charged with considering the process’s transparency, how it contributes to resource accreditation, and a “disconnect” between the winter-focused risk modeling behind ELCC and the use of summer peaks to calculate zonal capacity emergency transfer limits.

When introducing the issue charges, LS Power argued that market participants have limited ability to understand how changes to their assets would affect their ELCC ratings. Because the framework relies on performance during past capacity emergencies, it may also take years for any improvements that could bolster capacity performance to result in higher accreditation.

LS Power’s Dan Pierpont told RTO Insider that the issue charges are just the first steps in improving ELCC; there needs to be a larger discussion on creating an accreditation framework that reflects future capability rather than historical performance. Without that, he said, the market cannot deliver a clear investment signal.

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ERCOT Faces Uphill Battle to Meet Large Loads

Known for his no-nonsense demeanor, ERCOT COO Woody Rickerson was especially candid in December when he appeared before a legislative committee overseeing the state’s grid. 

Asked to respond to a lawmaker’s concerns that assessments of Texas’ energy supplies are offering a misleadingly optimistic portrayal of the state’s energy production, Rickerson replied, “I don’t have a positive sense on this at all.” 

State Sen. Charles Schwertner (R), the joint committee’s chair and architect of many of the new laws put in place after the disastrous 2021 winter storm, asked Rickerson to clarify. 

“I don’t have a positive sense that we have enough generation on the books to serve the load that’s expected,” Rickerson replied. 

The Texas grid operator raised eyebrows last April when it said its load-growth forecasts had ballooned by 40 GW over the previous year’s estimates. It said it anticipates about 152 GW of new load by 2030. 

The state’s business-friendly environment attracts investors and developers who want to build data centers, mine cryptocurrency and employ artificial intelligence, all massive energy consumers. Industrial electrification, electric vehicles and now hydrogen facilities will only increase the strain on the ERCOT grid. The ISO has about 103 GW of installed capacity for a system that peaks around 85 GW of load in the summer and 78 GW in the winter. 

“We’re the best market in the country to react to that kind of growth potential,” ERCOT CEO Pablo Vegas said during the ISO’s April Board of Directors meeting, pointing to the ability to interconnect resources “faster than anyplace else in the country.” 

ERCOT CEO Pablo Vegas | © RTO Insider LLC

“We continue to add generation at really an incredible rapid pace,” he told his board in December, pointing to an interconnection queue with more than 371 GW of capacity. 

Still, ERCOT has decided it had to adapt and take a different approach to meeting future demand that ensures all system-planning processes can “adapt to better serve” the state’s economy. Central to that is a new law requiring the ISO to include prospective load identified by transmission service providers, rather than factoring in unsigned load. 

Solar resources (155 GW) and battery storage (141 GW) account for 83% of the 1,775 active interconnection requests. At the same time, Texas is trying to attract more thermal generation with its Texas Energy Fund, established by state law and approved by voters in 2023.  

The fund’s In-ERCOT Generation Loan Program offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable generation. It has received 18 applications for 9.72 GW of potential new generation seeking $5.34 billion in loans; the Public Utility Commission will vet the applicants during the year before awarding the grants. 

Dealing with Growing Loads

Meanwhile, ERCOT is tracking more than 40 GW of large-load requests that may or may not show up. 

“There’s no real cost associated with saying, ‘Hey I’m a load, and I want to come to the grid,’ and there’s no forking over of ‘X’ dollars if you’re a large load, for instance,” Schwertner said during the December joint committee meeting. “We should have a great handle on what that load is, where it’s going to be added.” 

Schwertner suggested assessing an upfront fee for those wanting to interconnect their large loads with ERCOT, an issue that likely will be discussed during this year’s legislative session, which runs from Jan. 14 to June 2. 

Vegas says the current generation mix is more diverse than ever, can be built faster and is located farther from load centers. While the generation is coming online quickly and load growth increasing faster, it still takes three to six years to energize transmission in ERCOT (about half the time required in other regional grids). 

Speaking at an Energy Bar Association symposium in October, ERCOT General Counsel Chad Seely said the ISO often is asked how much its recommended transmission improvements will cost consumers and whether the new buildout will be sufficient “if all that load eventually shows up over the next five, seven years.”  

ERCOT staff continues to work with stakeholders to define rules and has completed its Permian Basin Reliability Plan, as directed by the PUC. The plan recommends five 345-kV import paths into the region and, in a first for the state, three 765-kV import paths. 

With estimated costs of $13.77 billion for the 765-kV lines and $12.95 billion for the 345-kV imports, the plan exceeds the price tags of previous annual infrastructure portfolios. Seely said the plan is necessary to meet the region’s load growth, which comes not just from oil and gas production but also data centers, crypto facilities and other large industrial users. 

“That is the equivalent of taking North Texas [and the DFW Metroplex], from a load standpoint, and putting it out in West Texas,” Seely said. “They want reliable service, so we’ve recommended a lot of transmission infrastructure, both locally and large-scale highway infrastructures.” 

Transmission providers are preparing certificates of convenience and necessity applications. The PUC has set May 1 as a date to determine which import paths will be used. 

Prompted by a 35.7% increase in projected load growth from the year before, ERCOT’s annual Regional Transmission Plan (RTP) included more than 50 GW of individual loads larger than 75 MW. Released just before the holidays, the plan includes more than 274 transmission projects and about 6,000 miles of line upgrades, rebuilds, conversions and additions to meet the forecasted load growth in the traditional 345-kV plan. In comparison, the grid operator identified a combined 262 projects in its 2023 and 2022 RTPs. 

The 2024 plan also considers a 765-kV plan as an alternative to the traditional 345-kV plans. ERCOT will file a 345-vs.-765 comparison with the PUC by late January and will host a workshop on the differences Jan. 27. 

RTC with an ERCOT Twist

After the commission shelved the once-favored performance credit mechanism market change, the ISO says its staff and stakeholders will work to complete the real-time co-optimization (RTC) project by the end of the year. Postponed after Winter Storm Uri, RTC will save about $1.6 billion annually in reduced energy costs by procuring energy and ancillary services every five minutes. (See Texas PUC Shelves PCM Design Over Lack of Benefits.) 

RTC market trials are scheduled to begin in May. The project has a December targeted go-live date.  

Once RTC becomes a part of the ERCOT market, staff will begin adding a new standalone ancillary service, dispatchable reliability reserve service. DRRS will be procured in the day-ahead and real-time markets from eligible generators who must be online within two hours of instruction and run at least four hours at their high-sustained limit. The amount of DRRS procured will reduce reliability unit commitments. 

While RTC is common in most regional grids, ERCOT is tacking in a different direction with its reliability standard. As currently proposed, the standard includes the normal one-in-10 days loss-of-load expectation found in other regional grids, but the ISO also will measure duration (no more than 12 hours in any event) and a yet-to-be-determined magnitude. (See ERCOT’s Vegas Touts New Reliability Standard.) 

ERCOT says this will result in a comprehensive reliability standard that better characterizes the real risk probabilities of a grid event and its impact on consumers. Staff are finalizing the magnitude element and working on the various parameters and scenario modeling for the new standard. 

Speaking to the Texas Reliability Entity in December, Vegas said, “We’re going to now have a yardstick that is going to effectively help us measure how we think the ERCOT market will perform in some period of time.” 

ERCOT is also working to improve its reliability must-run and must-run alternative processes, a result of CPS Energy’s attempt to retire three aging gas units this year. Staff has said the units are needed for reliability purposes and are pursuing an RMR contract for the largest resource. (See related story, ERCOT Finds Little Interest in MRAs for San Antonio Units.) 

“Some of our thermal fleet is getting quite aged,” Vegas told the board in December. He said about 40% of the ERCOT fleet is over 30 years old and 30% is over 40 years old. 

“Over time, as new resources are built and developed and brought onto the grid, you will expect the older, less economic resources to be retiring,” Vegas said. “We want to make sure that we’ve got a robust reliability must-run or must-run alternative process that we can leverage to get the most efficient and effective solutions when we are faced with that circumstance again in the future.” 

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Mass. Electricity Rates Working Group Issues Recommendations

Prior to the deployment of advanced metering infrastructure (AMI), the adoption of simple, near-term rate reforms could help Massachusetts achieve its electrification goals while minimizing effects on ratepayers, an interagency working group concluded in a report released in late December. 

The Massachusetts Interagency Rates Working Group (IRWG) recommended that each utility adopt an opt-in seasonal heat pump rate and establish a “non-bypassable fixed charge” to encompass some of the policy costs that currently are recovered through volumetric charges. 

The working group includes members of the Department of Energy Resources, the Executive Office of Energy and Environmental Affairs, the Massachusetts Clean Energy Center and the Attorney General’s Office. 

“The Working Group’s primary recommendation for the near term is for the DPU [Department of Public Utilities] to require all the EDCs [electric distribution companies] to establish a seasonal heat pump rate, similar to those recently approved and directed by the DPU for Unitil and National Grid, but with larger winter differentiation to ensure energy bill savings for customers transitioning from gas heating to electric heat pumps,” the IRWG wrote. 

Under the current rate structure, electrifying a natural gas heating system typically increases a household’s total energy costs, the group noted. It added that the cost disincentive to electrification could become more pronounced in the coming years, as both distribution and transmission rates are set to increase.  

About 54% of homes in Massachusetts use natural gas heating, 26% use oil and 13% use electric resistance, the working group noted.  

The working group recommended seasonal household-wide heat pump discounts on distribution and transmission charges. It noted that the New England power system currently peaks during the summer, and the increased winter electricity demand would be unlikely to significantly increase overall system costs. Supply rates would not be affected by the discount.  

“The winter volumetric charge of a seasonal heat pump rate can be set on a revenue neutral basis, such that, based on the expectation for increased kWh usage, the rate will still recover the same level of total fixed costs,” the IRWG wrote.  

Estimated heating cost by fuel type in Massachusetts | Massachusetts Interagency Rates Working Group

If adopted, the seasonal heat pump rate may be a short-lived design. The rollout of AMI, combined with the expected transition of the New England grid to a winter-peaking system by the mid-2030s due to heating electrification, likely will necessitate broader changes to rate design. 

The report’s other major recommendation was for a fixed charge to cover some state policy costs and system reliability costs that currently are calculated based on electricity consumption.  

While programs related to energy efficiency, decarbonization and low-income discounts historically have been funded through volumetric charges to incentivize lower energy use, high electricity rates can inhibit customers from electrifying, the report said.

“A non-bypassable fixed charge could fund crucial programs that support the state’s energy, affordability and decarbonization goals in a way that does not increase volumetric charges, a key barrier to electrification,” the working group noted.  

“These recommendations, principally the seasonal heat pump rate, can be implemented in the near term and are essential for affordability and decarbonization,” the working group added. It called on the state’s DPU to facilitate the rapid deployment of the seasonal heat pump rate for the winter of 2025/26. 

The DPU has an ongoing investigation into energy affordability and tiered discount rates (DPU 24-15). The IRWG said its recommendations are intended to be complementary to this proceeding and added that it’s considering petitioning the DPU to take up its short-term recommendations. 

The working group said it plans to issue more long-term recommendations focused on “AMI-enabled rate design, ratemaking, and regulatory mechanisms,” noting that a DPU investigation likely will be necessary for implementing these long-term changes.  

The group said the state’s three electric utilities are scheduled to complete their rollouts of AMI between 2025 and 2029, and “widespread [time-varying rates] will likely be in effect between 2029 and 2033.” 

Larry Chretien, executive director of the Green Energy Consumers Alliance, expressed strong support for the working group’s main recommendations. 

Chretien wrote that implementing the recommendations likely would require action from the DPU, adding that, “based upon some recent actions by the DPU, we anticipate that the recommendations will be met with favor.” 

“To enable a proper level of civic engagement, we encourage the DPU to consolidate the recommendations into one statewide docket,” Chretien said.  

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BPA Market Decision on Track Despite Calls for Delay

The Bonneville Power Administration remains on track to issue a decision on which day-ahead market to join by May 2025 despite calls to delay until fall to give itself more time to reconsider its leaning toward SPP’s Markets+. 

BPA spokesperson Doug Johnson told RTO Insider on Jan. 6 that the agency is “not contemplating a delay at this time,” while urging stakeholders to view recent production cost models with some skepticism.  

Johnson’s comments followed concerns presented in a Dec. 19 letter from Northwest environmental organizations that joining Markets+ instead of CAISO’s Extended Day-Ahead Market (EDAM) could lead to multimillion-dollar cost increases for the agency and its customers.  

Ten organizations, including Northwest Energy Coalition, Natural Resources Defense Council, Sierra Club and Earthjustice, signed the letter, which was published in support of four U.S. senators from Oregon and Washington who voiced similar concerns in separate correspondence with BPA. 

Antoine Lucas, SPP vice president of Markets+, said in an email that the RTO is “disappointed the letter from the Northwest NGOs perpetuates mischaracterizations of the Markets+ design, benefits and governance structure in ways that have already been addressed.” 

BPA previously stated it will issue its market decision by May 2025. The agency has leaned toward SPP’s Markets+, pointing mainly to its governance framework, which BPA believes provides greater independence from California state influence compared to the EDAM option. 

However, the environmental organizations urged BPA to delay its decision to at least fall 2025 “to accurately assess the governance structures proposed by EDAM and Markets+ and to ensure that any decision delivers the greatest economic and other benefits to our states and region,” according to their letter. 

The organizations argued that Markets+ also faces governance issues. They pointed out that FERC has yet to approve Markets+’s proposed governance structure and that the market’s independent panel “is subject to the direct control of SPP.”  

Meanwhile, the West-wide Governance Pathways Initiative, a group of stakeholders, is addressing governance concerns in EDAM by developing proposals to create an independent entity to govern the EDAM and WEIM markets, the letter stated. 

In his statement to RTO Insider, Lucas said SPP “remains confident FERC will approve the Markets+ tariff, and we look forward to continued conversations about the competitive benefits Markets+ brings to Western stakeholders and their customers.” 

Financial Considerations

BPA also participates in CAISO’s Western Energy Imbalance Market, which has “generated over $6 billion in benefits,” according to the letter. The agency’s investments in WEIM could go to waste in the Markets+ scenario, the groups contended. 

Additionally, a study by Environmental and Energy Economics found that EDAM could generate economic benefits “ranging from $65 [million to] $221 million per year compared to Markets+,” the organizations wrote. 

BPA has questioned this finding. In correspondence with Seattle City Light, the agency’s administrator, John Hairston, said these numbers are accurate only under a scenario in which there is only a single West-wide market rather than the more likely scenario that there will be multiple markets in the future.  

Johnson reiterated this point to RTO Insider, saying, “The model benefits under a single West-wide market footprint should be viewed with some skepticism.” 

“For example, a production cost model study does not capture the material impacts of resource adequacy requirements, greenhouse gas accounting, fast-start pricing, scarcity pricing, bid caps, market power mitigation, out-of-market actions and other differences in market design between EDAM and Markets+,” according to Johnson. 

He added that those models also fail to consider changes in market rules “or the lack thereof, that are influenced by a given market’s governance structure, which may impact and influence market outcomes depending on the process for updating market rules.” 

He also targeted the letter’s claim that BPA considers spending “$25 million in customer money” to fund Phase 2 of the Markets+ proposal despite expecting “to miss revenue projections for this year by $375 million, leading to $280 million in losses.” 

The letter relies on information from BPA’s second quarter business review for 2024, and Johnson said the organizations have “extrapolated that into a completely different financial operating year.” 

“We would absorb that $25 million cost if we were to execute a Phase 2 agreement with SPP this year, and we haven’t even done a first-quarter report yet, so we’re not even talking about our finances this year,” Johnson said. 

A spokesperson for U.S. Sen. Jeff Merkley (D-Ore.) — one of the four lawmakers who signed the initial letter that spurred the environmental organizations’ support — told RTO Insider that Merkley “is following this discussion closely.” 

“His priority remains ensuring there are deliberate processes to maximize the benefits for Oregon families,” the spokesperson added. 

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NYISO’s Busy 2025 Begins

NYISO capped off a roller coaster of a year full of reliability needs, the Demand Curve Reset and contentious stakeholder meetings by announcing a new record level for hourly wind power generation on Dec. 16.

The grid operator reported that 2,309 MW were generated from 30 wind power facilities at 11 p.m. This served 14.4% of energy demand statewide. The previous record of 2,213 MW was set in November.

With more wind power on the way, NYISO’s latest Public Policy Transmission Need seeks to get up to 8 GW of offshore wind into New York City by 2033. It received four bids from the New York Power Authority, New York Transco, Viridon New York and energyRE Giga-Projects USA. The ISO will spend most of 2025 evaluating and selecting projects. A draft report on the top projects will be released between the second and third quarters, with a final decision by the Board of Directors by the end of the year.

NYISO’s early 2025 will likely be dominated by the Reliability Needs Assessment process again. Now that the board has accepted the results of the RNA, which identified a reliability need in New York City starting in summer 2033, the ISO will seek system updates to try to address the need without opening a formal solicitation process. This will incorporate any ongoing or planned upgrades, generation additions and other changes that might address the need.

If this is not sufficient to address the reliability need, NYISO will seek solutions to fix the issue. This would trigger an additional process that looks at the proposed solutions and eventually culminate in the development of a Comprehensive Reliability Plan. The CRP then serves as the blueprint for system reliability for the next 10 years, up to and including ranking any solutions to the need if it still exists.

At the same time, NYISO will continue to update its quarterly Short-Term Assessment of Reliability reports, the most recent of which found the continued operation of two generators on the Gowanus Canal and two barge-based peakers to be necessary for reliability. These peakers were supposed to close because of the Department of Environmental Conservation’s “peaker rule” by May 1. NYISO is keeping them active for an initial period of up to two additional years until “permanent solutions to the need” are in place.

NYISO 2025 Projects and Developments

May 1 also marks when the DCR is due to go into effect.

Pending FERC approval, the reset will redraw the demand curves for wholesale electricity based on the estimated cost of a proxy peaker plant, which for the first time has been designated a battery by NYISO.

The previous 2021-2025 DCR was challenged by a lawsuit because of FERC’s rejection of NYISO’s amortization period. It is unclear if any parties, including FERC, will issue changes or challenges to the new demand curve, but the selection of a battery as the proxy unit was controversial with stakeholders.

NYISO also will be involved in nested planning projects throughout the year. The third year of the Coordinated Grid Planning Process with the New York Public Service Commission and utilities will see a report in the fall or winter. This report will highlight the least-cost planning assessment for transmission upgrades and solutions across the state.

Simultaneously, NYISO will be implementing FERC Order 1920, which requires NYISO to change its regional transmission planning process to examine long-term needs over a 20-year horizon. The ISO expects to file its compliance with FERC in mid-2025.

This year also marks the first in which NYISO’s new interconnection study cluster process will go into effect. The ISO hopes it will streamline and expedite the backlogged interconnection queue. The big change is that interconnection requests are being examined in clusters as opposed to individually. Projects also have a limited number of “midstream” modifications they can make to avoid bogging down the rest of the cluster.

Beyond the ISO

There are several other developments in New York to keep an eye on in 2025.

Smart Path Connect, a major NYPA and National Grid transmission project, is due to finish its rebuild of 100 miles of lines in April. The new substations for the project are due to be energized in the fall 2025 and spring 2026. When completed the project will allow an additional 1,000 MW of energy to travel across the state.

Raya Salter, an environmental justice advocate serving on the New York Department of Public Service’s Energy Policy Planning Advisory Council, told RTO Insider she would push to get environmental justice issues folded into the transmission planning process. In a report developed in collaboration with the Columbia Climate School, she identified gaps in the planning process that hinder meeting the state’s environmental justice goals under the Climate Leadership and Community Protection Act.

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ISO-NE in 2025: Capacity Reforms, Tx Solicitation and FERC Orders

ISO-NE’s multiyear effort to overhaul its forward capacity market likely will continue to dominate ISO-NE and NEPOOL work in 2025. The RTO’s workload also will feature a first-of-its-kind transmission procurement, compliance with FERC Orders 2023 and 1920, the development of an energy shortfall threshold and a myriad of other efforts focused on balancing affordability, reliability and decarbonization.  

The capacity market already is a major revenue source for generators in the region and is poised to gain value as renewables supported by long-term contracts reduce prices in the energy market. 

The RTO anticipates total revenue from the capacity market and power purchase agreements surpassing the value of the energy market by 2035. The capacity market was valued at $1.8 billion in 2023, while the energy market was valued at $4.8 billion.  

Meanwhile, resource capacity accreditation changes, which have been under development since 2021, could significantly affect capacity revenues for different resource types. 

ISO-NE has broken up the capacity auction reform (CAR) project into two phases, with the first phase focused on reducing the time between the auction and the capacity commitment period from years to months, and decoupling the resource retirement process from the capacity market. 

The RTO plans to ramp up work with stakeholders on the detailed design for the first phase in early 2025, targeting a FERC filing by the end of the year. (See NEPOOL Markets Committee Briefs: Dec. 10, 2024.) 

The second phase of the CAR project will focus on accreditation and seasonal reforms, which would split CCPs into distinct seasons with separate auctions. ISO-NE plans to begin discussions on these changes at a high level in 2025 before moving into more detail by the end of the year. It plans to file the second phase with FERC in late 2026.  

The RTO reached an advanced stage with its accreditation reforms in early 2024 before pausing this work to widen the project scope. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) ISO-NE told stakeholders in December that it plans to “explain and discuss all proposed changes to capacity accreditation … as if they are being presented for the first time.”  

New Transmission and Aging Infrastructure

Also in 2025, the RTO is set to roll out its first request for proposals (RFP) for its longer-term transmission planning (LTTP) process, and likely will have to devote significant resources to complying with FERC Orders 1920 and 1920-A.  

The LTTP process was developed by the New England states and ISO-NE and approved by FERC in July. It creates a process for selecting and paying for transmission projects to fulfill long-term needs identified in ISO-NE studies. (See FERC Approves New Pathway for New England Transmission Projects.) 

In December, the states officially directed ISO-NE to develop the first LTTP RFP, which will be focused on increasing the north-to-south transmission capacity in Maine. ISO-NE plans to issue the RFP by March. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.) 

The LTTP process mirrors many of the requirements of FERC Orders 1920 and 1920-A, which direct transmission providers to adopt long-term transmission planning procedures and establish cost-allocation methods with the states. Order 1920 compliance filings will be due in the summer of 2025.  

| Vineyard Wind

Prior to the release of Order 1920-A, ISO-NE paused stakeholder discussions on Order 1920 compliance, citing uncertainty regarding the pending rehearing order. It has yet to resume compliance discussions and has not announced whether it will pursue an extension of the compliance deadline. (See ISO-NE Announces Pause of Order 1920 Compliance Discussions.) 

The orders do not directly require changes to the LTTP process. However, using parts of the LTTP process to comply with the orders would “require extra justification and could result in commission modification to those processes on compliance,” Day Pitney LLP, counsel for NEPOOL, said in a December presentation.  

“The LTTP provisions might be better as an entirely separate supplemental process under the tariff,” Day Pitney added. “ISO, the [relevant state entities], the [participating transmission owners] and NEPOOL will need to consider.” 

2025 also will bring continued scrutiny of asset condition projects, which are intended to address deteriorating transmission infrastructure. Asset condition spending by the region’s transmission owners has ballooned in recent years, and states and consumer advocates have raised alarms about a lack of transparency and oversight into the investments.  

The region’s transmission owners have introduced over $3 billion in asset condition investments since the start of 2023, arguing that the investments are necessary to maintain the region’s aging grid. The states have pushed for reforms to the asset condition project review processes to ensure the investments are prudent, and also have expressed interest in right-sizing projects to capture long-term cost reductions when possible. 

Interconnection

ISO-NE and stakeholders still are waiting for a response from FERC on their compliance filings for Orders 2023 and 2023-A. The RTO submitted its compliance filing in May, requesting that FERC approve the proposal by Aug. 12 to preserve the compliance timeline.  

However, FERC has yet to rule on the RTO’s compliance filing for Order 2023, and ISO-NE has paused its work to implement its compliance with the order.  

This delay has created significant uncertainty for projects in the interconnection process. The queue is closed for new projects, and likely will reopen only after the completion of the first cluster study, which will take about a year to complete after its initiation. If FERC requires significant revisions to ISO-NE’s proposal, this could further delay the start of the first interconnection study. (See New England Clean Energy Developers Struggle with Order 2023 Uncertainty and With FERC Inaction, ISO-NE Delays Order 2023 Implementation.) 

“A commission order on the compliance proposal is sorely needed to help alleviate existing interconnection challenges and to provide certainty to both stakeholders and ISO-NE,” the New England States Committee on Electricity (NESCOE) wrote in a letter to FERC in late November.  

“The continued uncertainty around the timing of an order places ISO-NE on a tightrope where it is forced to balance the need to be postured to move quickly toward compliance once an order is issued with the need to continue to process resources under the currently effective tariff,” NESCOE added. 

At the state level, Massachusetts Energy Secretary Rebecca Tepper has said interconnection reform will be a major focus for Bay State energy officials in 2025. (See Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024.) 

Reliability Backstops and Fossil Resources

ISO-NE also aims to establish a regional energy shortfall threshold (REST) in 2025, which likely will be a key factor in potential future out-of-market reliability actions to retain resources or ensure an adequate supply of stored fuel. 

In November, the RTO said it plans to base the REST on two key metrics: normalized unserved energy over a 72-hour period — intended to capture the intensity of an energy shortfall — and total shortfall duration. (See ISO-NE Details Regional Energy Shortfall Threshold Metrics.) 

ISO-NE plans to finish discussions on the REST metrics in early 2025 before proposing an initial risk threshold to stakeholders in March or April. These discussions could pose difficult questions about how much the region is willing to pay for reliability, and to what extent it will keep fossil resources online to support reliability as renewable generation increases. 

The RTO’s inventoried energy program, which compensates fossil resources for maintaining fuel storage on-site in the winter, is set to expire in the spring of 2025. The RTO has yet to announce whether it plans to bring the program back for future winters. 

In 2024, New England saw the closure of the 1,400-MW Mystic Generating Station, while Granite Shore Power announced its plans to retire Merrimack Station, the region’s last remaining coal plant, by 2028. While the coal generator struggled to pass an emissions test throughout 2023, one of the station’s two units passed the emissions test in July 2024. The other unit is not allowed to run until it passes the test.  

Carbon emissions from electricity generation across New England likely increased in 2024 relative to 2023, according to ISO-NE data calculated through Nov. 25. The added emissions came from increased gas generation and do not account for gas system methane leaks, a key driver of climate change. (See Climate Activists Ask ISO-NE Board Members for More Transparency.) 

ISO-NE has faced continued pressure from activist groups at public meetings to take a more activist approach to reducing power sector emissions. ISO-NE has said frequently it favors putting a price on emissions in the wholesale markets but would need unanimous state support to pursue this mechanism.  

Consumer and environmental advocates also criticized for a lack of transparency into the proceedings of NEPOOL and the RTO’s board of directors. NEPOOL meetings remain closed to nonmembers, which has been a major point of contention for some environmental groups. 

State Clean Energy Policy

To ensure resource adequacy amid the clean energy transition, new capacity additions must keep pace with resource retirements and load growth. ISO-NE projects peak demand to grow from about 24,800 MW in 2024 to 25,700 MW in 2030. The RTO expects load growth to accelerate after 2030, projecting peak demand reaching up to 57 GW in 2050.  

New renewables are on the horizon — Vineyard Wind 1 and the New England Clean Energy Connect transmission line could come online by the end of 2025, potentially adding about 2 GW of combined generation capacity to the system. However, the subsequent wave of offshore wind projects likely will not be online until 2030.  

The obstacles to large-scale renewable deployment are daunting; state policymakers and advocates face a less friendly federal administration, increasing costs and long delays for offshore wind projects and transmission lines, and mounting affordability pressures on ratepayers. 

Two offshore wind projects, New England Wind 1 and SouthCoast Wind, remain in contract negotiations following their selection in the 2024 tri-state offshore wind solicitation. Connecticut declined to buy any offshore wind capacity from the solicitation amid worries about costs. (See Connecticut Closes the Door on 2024 OSW Procurement.)  

New England states likely will pursue major new procurements in 2025, potentially building on the 2024 multistate coordinated offshore wind procurement. Massachusetts is authorized to pursue multistate clean energy solicitations through the end of 2025 and may pursue an additional offshore wind solicitation. 

Maine is considering procurement of onshore renewable generation in the northern part of the state and also is developing its first offshore wind solicitation. Its first offshore wind RFP is scheduled to be finalized in January 2026. 

New England officials have discussed the possibility of more transmission lines to Canada, which may be bolstered by an agreement in December between Eastern Canadian provinces that could lead to a significant increase in the country’s hydropower capacity.  

With additional transmission capacity, Canadian hydropower could help balance renewable resources in New England, reducing reliability costs and renewable curtailment. While political and technical challenges remain, top energy officials in both Massachusetts and Quebec have expressed an interest in exploring the potential of new interregional transmission lines to unlock this potential. (See Overheard at Raab Electricity Restructuring Roundtable: Dec. 13, 2024.) 

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Uncertainty Clouds NJ Clean Energy in 2025

Amid nationwide concern about the impact on clean energy initiatives of President Trump’s return to the White House, New Jersey in 2025 faces the added uncertainty of a governor’s race to replace clean energy champion Gov. Phil Murphy and his release of a new energy master plan.

Murphy (D), who will step down in January 2026, has in his seven years in office aggressively pushed solar and offshore wind projects and the adoption of electric vehicles. His energy master plan could help shape the state’s energy use for years.

Yet the lack of clarity over what leadership comes next could complicate the state’s efforts to keep on track Murphy’s ambitious goals, which include developing 11 GW of ocean wind capacity by 2040, adding another 130,000 EVs on the road by the end of 2025 and launching a new Storage Incentive Plan (SIP) this year to provide stability to the state’s growing reliance on electricity.

“It is still, definitely a race to the finish line for the Murphy administration’s clean energy priorities,” said Doug O’Malley, director of Environment New Jersey. “There’s a real moment in the Trump era for gubernatorial candidates to talk about their plans for climate action and clean energy.”

The state’s last master plan, issued in 2020, formed the foundation of Murphy’s energy policy based around electricity. To date, that has included four solicitations of offshore wind projects and the adoption of the Advanced Clean Cars II act and the Advanced Clean Trucks rules, which took effect Jan. 1. Murphy also promoted the transformation of building heating and hot water systems to run on electricity.

Offshore Wind Challenges

The state’s biggest challenge in 2025 could be maintaining momentum in the state’s OSW projects. Since Ørsted abandoned two of the state’s three most advanced projects — Ocean Wind 1 & 2 — in October 2023, the state’s leading project has been the 1,510-MW Atlantic Shores, which received its Construction and Operations Plan approvals from the Bureau of Ocean Energy Management in October 2024.

To help the developer adjust to the changing OSW financial and supply chain environment, it submitted a rebid in the New Jersey Board of Public Utilities’ fourth solicitation. The BPU, which was scheduled to announce the solicitation outcome in December 2024, has yet to do so. And the BPU also expects to launch a fifth OSW solicitation in early 2025.

In addition, another project — Leading Light Wind, one of two projects totaling 3,742 MW of capacity endorsed in the state’s third solicitation in January 2024 — is struggling to advance. After the developer said it was looking for a new turbine manufacturer, the BPU extended by two months to the end of 2024 a deadline by which the developer should make “significant financial obligations.” (See New Jersey BPU Approves Invenergy Offshore Wind Delay.)

On Dec. 19, developer Invenergy Wind Offshore filed a motion with the BPU asking for an extension of the delay until May. The project supported its request by saying the “wind equipment market continues to experience significant price volatility, and the company has not yet identified a solution to that volatility.”

Vigorous Debate

Elsewhere, the Murphy administration is striving to reach the governor’s goal, set in February 2023, of electrifying 400,000 more dwelling units and 20,000 more commercial spaces or public facilities by December 2030. And the governor, after announcing in December that the number of EVs in the state has doubled since 2022 to 208,000, continues to push for more growth and more charging points. The state currently has 4,000 chargers in place, he said.

Those plans likely will be subject to debate in the gubernatorial race, said Sen. Bob Smith (D), who heads the Senate Environment and Energy Committee, which shapes many of the Legislature’s clean energy bills. Six Democrats and eight Republicans have announced their intent to seek the governor’s office.

“There is going to be a very vigorous discussion of energy policy and where New Jersey gubernatorial candidates see our energy policy going” on both sides of the aisle, he said.

Even if a pro-clean-energy governor is elected, he said, Trump’s presence in the White House “would mean New Jersey would have to do more on its own and not in partnership with the federal government.”

Master Plan Divisions

The state’s current master plan calls for the state to reach 100% clean energy by 2050, mainly by improving energy efficiency and shifting to wind and solar generation. The new plan was scheduled to be completed by the end of 2024, ready to form the cornerstone of a state “comprehensive climate action plan” to be released in 2025, Murphy’s Office of Climate Action in the Green Economy has said.

The release of the report is likely to be contentious, as were the four public hearings held by the BPU in the spring, when environmentalists said the last master plan had been too weak and the next one should be tougher. Business groups, who have long complained that the last master plan did not include an analysis of the cost of implementing the plan, said that should be a priority in the next report. (See NJ Wrestles with Clean Energy Priorities.)

As in many states, clean energy supporters say the state’s grid needs to be strengthened to handle a future electricity demand surge that BPU officials predicted in October 2024 will increase by 20% by 2034. (See NJ Offshore Infrastructure Plans Spark Electromagnetic Fears.)

“We have a grid that doesn’t work,” said Smith. “We’re not investing enough in it. … As a result, even if we get wind moving at a decent rate, and that hasn’t started yet, you’re going to have some trouble in getting the renewable energy where it needs to be.”

Ray Cantor, a lobbyist for the New Jersey Business & Industry Association, agreed the state needs to “ensure our electrical grid has adequate resources and remains reliable.” His organization, one of the state’s largest business groups, wants it done in a “manner that is affordable and reliable,” he said.

Yet there is little agreement on how to do it. A bill sponsored by Smith to appropriate $300 million for grid upgrades has not moved since leaving his committee in March. He said he thinks public sentiment may not be ready to endorse the necessary investment in 2025 until the state suffers even more extreme weather impact than the recent run of storms, wildfires and heat waves.

Stimulating Storage

Also on the state’s agenda is the BPU’s SIP initiative, which is designed to help the state reach 2,000 MW of installed storage in the state by 2030 and provide stability to an energy system based on the vicissitudes of wind and solar power.

The proposal, for which the state gathered stakeholder input in November and December, seeks to stimulate storage development through two programs: one to be launched in 2025 that would offer fixed incentives for grid supply projects; and another to offer fixed incentives for distributed energy projects, with a 2026 launch date. (See Developers Seek Deadline Extension in NJ Storage Plan.)

Solar supporters see the storage program, and new remote net metering rules, as important for continued solar growth. The state, with a goal of 12.2 GW of installed capacity by 2030, was expected to reach 5 GW of capacity in 2024. But the latest BPU figures, for the first 10 months of 2024, show the state installed 201,935 kW in the period. At that rate, the full-year capacity installed would fall short of the 447,697 kW installed in 2023.

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, estimated the state’s residential solar installations in 2024 were 25% lower than the year before, commercial projects were down 50% and community solar was down 66%.

A key issue to be addressed in 2025, he said, is that the “solar sector is still struggling with utility interconnection cost issues and the number of circuits now closed or severely restricted to new solar installs statewide.” Those issues can be addressed by electric delivery companies, he said, adding that to make those changes there also needs to be a “rational split of costs between ratepayers and solar developers.”

“Ratepayers need to make some meaningful contribution toward grid modernization,” he said.

EV Advance

In the EV sector, the New Jersey Coalition of Automotive Retailers is skeptical the governor’s 200,000 EV milestone means the state can reach its 330,000 EV goal.

President Laura Perrotta said New Jersey consumers in 2024 bought fewer than half the 100,000 EVs sold that is required by the ACCII rules. The rules require that 23% of vehicles sold in 2024 in the state are EVs, far larger than the actual figure of 11.2%, she said. Sales were hampered by the state’s decision in 2024 to remove a sales tax exemption on EV purchases and to add a registration fee of $250 a year for four years on the purchase price of an EV to pay for road repairs.

Pam Frank, CEO of ChargEVC, a nonprofit coalition that promotes the sustainable growth of the EV market, said the state has passed through the “early adopter” phase to the “mass market” era. Despite the added fee, the sales tax loss and the state’s reduction of incentives for all buyers except those on a low income, “the good news here is that the industry is moving along pretty well,” she said.

The state in 2025 should see the rollout of EV chargers along the New Jersey Turnpike and Garden State Plaza, which at present host mainly Tesla chargers, she said. Applegreen NJ Welcome Centres in 2023 committed to installing chargers on the state’s two highway arteries, with 80 installed by the end of 2025. (See NJ EV Charger Plan Advances as Enviros Demand ACC II Adoption.)

In addition, she said, her organization is helping put together the state’s first ever EV car show, a four-day event in April that will be held at the state’s largest mall, American Dream in East Rutherford.

“We’re hoping to make it the largest gathering of EVs on the East Coast,” she said.

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SMR Manufacturer, Texas and Utah Sue NRC Over Licensing Requirements

Two Republican state attorneys general and micro nuclear reactor firm Last Energy filed a lawsuit in federal court seeking an easier regulatory hand from the Nuclear Regulatory Commission on small reactors. 

Attorneys general in Texas and Utah signed onto the lawsuit that was filed Dec. 30 in the U.S. District Court’s Eastern District of Texas, Tyler Division (6:24-cv-00507). 

“With a preference to build in the United States, Last Energy nonetheless has concluded it is only feasible to develop its projects abroad in order to access alternative regulatory frameworks that incorporate a de minimis standard for nuclear power permitting, limiting requirements with a consideration of proportionality to the risk embodied in the technology,” the lawsuit said. 

Last Energy builds very small reactors of 20 MW that operate inside fully sealed containers with 12-inch-thick steel walls and thus have “no credible mode of radioactive release even in the worst reasonable scenario,” said the complaint. 

The firm has deals to build more than 50 reactors in Europe and has invested $2 million to set up a factory in Texas. But unless the NRC dials back regulatory requirements for small reactors, the lawsuit argued, its business would never get off the ground in the United States. 

The NRC, despite its name, does not really regulate new nuclear reactor construction so much as ensure that it almost never happens, the lawsuit said. The NRC’s interpretation of its regulations goes against congressional intent, which the lawsuit argued was to exempt small reactors that do not use significant amounts of nuclear material from federal licensing requirements. 

“The NRC imposes complicated, costly and time-intensive requirements that even the smallest and safest SMRs and microreactors — down to those not strong enough to power an LED lightbulb — must satisfy to acquire and maintain a construction and operating license,” the lawsuit said. “These requirements threaten the health and prosperity of Texans by hindering the rollout of safe and reliable power — precisely the sort of thing that Last Energy could provide.” 

The Atomic Energy Act of 1954 authorizes the NRC to require licenses only for reactors “capable of making use of special nuclear material in such quantity as to be of significance to the common defense and security, or in such a manner as to affect the health and safety of the public.” 

As written, the lawsuit said the Atomic Energy Act appropriately requires licensing for large nuclear power units, but those that use only a little nuclear material should be exempt, the lawsuit said. 

“To be clear, this regime hardly gives free rein to operators of even small, safe reactors,” the lawsuit said. “Such operators still must comply with the NRC’s stringent oversight of the special nuclear material that fuels reactors, not to mention state regulation, export controls, restrictions on nuclear weapons production, and prohibitions on weapons- grade nuclear material. Further, state governments would retain, and likely exercise, their traditional power to regulate power generation within their borders.” 

An earlier version of the act passed in 1946 gave atomic regulators licensing authority over “any equipment or device capable of making use of fissionable material,” but the lawsuit argued that in 1954, Congress deliberately narrowed that authority with thresholds related to national security, and health and safety. 

When NRC’s predecessor agency implemented the new law in 1956, it kept the broader licensing requirements in place and did not explain why any reactor used enough material to “be of significance to the common defense and security, or in such manner as to affect the health and safety of the public.” 

NRC has exempted tiny research reactors like the five-watt reactor at Texas A&M University, which is barely strong enough to power a small LED lightbulb. 

The lawsuit wants the court to require the NRC to implement a new rulemaking that considers the statutory limits around smaller reactors, and to declare that Last Energy’s proposed small modular reactors and microreactors “are not utilization facilities” under the Atomic Energy Act. 

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Data Centers and Demand Growth Top 2025 Agenda

Apart from the November election, the issue that has been utterly inescapable is data centers and their insatiable appetite for power. 

From conferences to utility earnings calls to state and federal regulatory meetings to a growing library of reports and research papers, the electric power industry has debated, discussed and wrestled with how to provide the gigawatts of demand from the data centers that are sprouting like mushrooms across the country.  

These increasingly mammoth facilities used for new artificial intelligence services are disrupting traditional utility and regulatory planning models and could accelerate the pace of change across the industry. 

Former FERC Chair Neil Chatterjee noted that winning the AI race with China has become a national security imperative. Consequently, demand growth from data centers is “going to totally upend energy policy and the conventional wisdom that Republicans are for fossil fuels and Democrats are for green energy,” Chatterjee said Dec. 5 at the U.S. Department of Energy’s Deploy 2024 conference. 

“We’re going to need every available electron and … every available megawatt,” he said. “We’re going to figure out energy efficiency, demand response, virtual power plants. How can we get grid-enhancing technologies [online]? How can we get greater optimization for our current grid? All of this will be essential to winning the AI race while simultaneously bringing down the cost of electricity for consumers.”  

The data center dilemma centers first on a familiar mismatch of timescales. Utilities and their regulators tend to plan based on the small, incremental demand growth that has been the norm over the past two decades at least. Planning, approving and building new generation can take three to five years or more. New transmission can take a decade.  

But data center development moves at ever-increasing digital speed, with tech giants like Google, Amazon and Microsoft planning and building new “hyperscale” facilities in two years or less. These companies also have committed to powering their operations with clean energy and have started looking for carbon-free electricity outside established business and regulatory models. 

Google has been on the cutting edge, with recent announcements of a new “clean transition tariff” in partnership with NV Energy, bringing major amounts of previously untapped geothermal power to Nevada’s grid. The company also rolled out a first-ever power purchase agreement for nuclear power from small modular reactors being developed by Kairos Power. 

Microsoft made headlines with its agreement with Constellation Energy to reopen a reactor at the shuttered Three Mile Island nuclear plant in Pennsylvania and its plan to buy 500,000 metric tons of carbon dioxide removal credits over six years from 1PointFive, a carbon removal developer. 

Just how much power will be needed is a moving target. A much-cited figure, traceable to a May 2024 analysis from Goldman Sachs, is that a ChatGPT query can consume nearly 10 times as much electricity as a standard Google search. Also released in May, a report from the Electric Power Research Institute estimated data centers would consume 9% of U.S. power by 2030.

More recent figures from the Lawrence Berkeley National Laboratory show that data centers, which accounted for 76 TWh, or 1.9%, of U.S. energy demand in 2018, hit 176 TWh, or 4.4% in 2023. LBNL predicts future growth ranging from 325 to 580 TWh by 2028, or 6.7 to 12% of total U.S. energy demand.  

The numbers for individual utilities are equally dramatic. As part of a new “Silicon Prairie” region attracting hyperscale development, the Omaha Public Power District put 1 GW of additional capacity online in 2024 and expects to almost double its generation capacity, from 3.6 GW to 6.8 GW, in the next five years, according to CEO Javier Fernandez.  

Georgia Power estimates a threefold increase in power demand from data centers and other economic development by mid-2030, from its current 12.2 GW to 36.5 GW. In April, the utility won approval from state regulators to update its 2022 Integrated Resource Plan, adding three new methane gas- and oil-burning power plants, totaling 1.4 GW of capacity, while also importing 750 MW of coal-fired power from Mississippi and pledging to add 10 GW of renewables by 2035.  

Pivoting the Message

Georgia Power’s IRP update represents what has become a typical response to the data center dilemma: delaying the previously planned closures of coal-fired and nuclear plants and adding new natural gas-fired plants to short-term expansion plans, along with renewables. 

PJM stirred controversy with its proposed Resource Reliability Initiative to meet demand growth by allowing new resources with 24/7 power to jump its historically clogged interconnection queue, a strategy that likely would favor fossil fuel plants over renewable projects that have been waiting in line for years.  

The industry argument for such fast and familiar solutions is simply that SMRs, enhanced geothermal and other emerging clean technologies supported by the tech giants are not yet at scale and may not be for five or 10 years. In the interim, new, dispatchable power will be needed, and existing generation ― including coal, natural gas and nuclear plants ― should be kept online, or in the case of the Three Mile Island and the Palisades nuclear power plant in Michigan, brought back online after a previous closure. 

But the clean energy industry is framing demand growth as a major opportunity to provide new solutions that build on its strengths, such as flexibility and innovation, and to use demand management strategies to reposition data centers as grid assets. 

Since the election, a range of industry leaders have shifted their messaging to align with President-elect Donald Trump’s priority of U.S. energy dominance, and big tech CEOs, including Jeff Bezos of Amazon and Sundar Pichai of Google, have made million-dollar contributions for Trump’s inauguration.  

The takeaway here is that while concerns with climate change may not lessen over the next four years, they likely will not appear in companies’ and trade associations’ public statements and policies.  

Speaking at Deploy 2024, Heather Reams, president of the right-leaning Citizens for Responsible Energy Solutions, said, “You’re not changing your business but pivoting the words you use.” She advised the industry to come with solutions to demand growth and talk with the White House and lawmakers on both sides of the aisle in Congress. 

The Solar Energy Industries Association set the tone Dec. 12 with its 10 policy priorities for the new administration, beginning with an “all-of-the-above” approach to U.S. energy dominance that includes solar and storage. Nos. 2 and 3 on the list are eliminating U.S. dependence on China for a range of clean energy technologies, including solar, and “surging” U.S. manufacturing. 

With the tech giants seeking clean energy, SEIA’s list also promotes solar as a key to unlocking the new power needed to meet data center and AI demand. 

The EPRI report recommends that data centers optimize their computational load by moving certain operations to off-peak hours, to reduce strain on the grid and their own electricity bills.  

Such strategies “could evolve to incorporate real-time energy market dynamics enabling data centers to not only adjust their operations based on grid demands but also actively participate in energy markets to optimize their benefits and support grid stability,” the report says. 

Permitting and Transmission

After AI and data centers, permitting and transmission planning were the other top issues for the clean energy industry in 2024 and will be a critical part of any solutions to demand growth going forward. 

But whether Trump and the Republican-controlled Congress can advance the bipartisan problem-solving needed is an open question. 

Certainly, Trump and North Dakota Gov. Doug Burgum (R), nominated as secretary of the Interior, are expected to come into office prioritizing the rollback of a range of environmental regulations. 

For example, the Biden administration has placed a strong emphasis on community engagement as an essential part of environmental reviews and permitting, to prevent ongoing legal challenges to new projects. Will such requirements be maintained, weakened or dropped in rollback and reform efforts? 

The bipartisan Energy Permitting Reform Act (S. 4753), authored by outgoing Sen. Joe Manchin (I-W.Va.) and Sen. John Barrasso, incoming Senate Republican whip, fell victim to post-election politics during the lame duck session of Congress. Both parties agree that energy infrastructure permitting needs to be streamlined and accelerated, but sticking points include the extent to which any new law should change environmental reviews under the National Environmental Policy Act and whether reform should include transmission. 

For Republicans, permitting reform could be targeted primarily at increasing drilling on federal lands and building out more natural gas pipelines. A new permitting bill could prioritize allowing companies to pay for expedited NEPA reviews, while cutting the time frame for legal challenges to final permitting decisions from its current six years to six months or less. Such changes likely would meet fierce opposition and legal challenges from environmental groups.  

Many Republicans also link action to increase interstate transmission as supporting the deployment of renewable energy, specifically the 2,600 GW of solar, wind and storage sitting in RTO and ISO interconnection queues across the country. 

With Barrasso as Republican whip, EPRA could be used as a starting point for a permitting reform bill that Republicans could try to pass via budget reconciliation, which would require only a simple majority vote. Democrats are countering that this approach would not pass parliamentary muster since budget reconciliation measures, by law, must be related to the federal budget.  

While Congress debates, however, the tech industry continues to move much faster than lawmakers, utilities or regulators and has shown itself adept at circumventing politics. The new buzzword in data center development is “co-location,” meaning that data centers are planned with their own supplies of clean energy, if not behind the meter, then inside the fence. 

A critical question is whether the hyperscalers ― like Google, Amazon and Microsoft ― will backtrack on their clean energy commitments as they continue aggressive expansion of their data centers, and whether others, including cities and states, will follow suit. 

Will Microsoft’s purchase of carbon removal credits be used to offset or rationalize continued fossil fuel use at some of their facilities? Maryland boasts one of the most aggressive emission reduction goals in the U.S. ― 60% below 2006 levels by 2031. But the state passed a law (S.B. 474) in 2024 allowing data centers to use fossil fuels to power backup generators without going through a standard regulatory approval process, a policy supported by Gov. Wes Moore (D). 

As competition grows between states to attract hyperscalers and their data centers, will such workarounds become a new norm or just one of many possible solutions that will emerge as the demand growth landscape continues to evolve in 2025? 

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Measured Praise for Clean Hydrogen Tax Credit Rules

The IRS has issued final clean hydrogen tax credit rules that balance the contentious and complicated matter well enough that industry and environmental advocates alike can find something positive in the details. 

But the Jan. 3 announcement — more than two years in the making — landed less than three weeks before the inauguration of a president whose policies and priorities may reshuffle the landscape for the U.S. clean hydrogen industry. 

The Fuel Cell and Hydrogen Energy Association hailed policy changes incorporated in the final rules but described its issuance as a milestone rather than the destination in an “extremely complex” matter. 

“There are also multiple areas where implementation and timing will be up to the incoming Trump-Vance administration,” CEO Frank Wolak said in a prepared statement. 

The section 45V Clean Hydrogen Production Tax Credit was authorized in the Inflation Reduction Act, which was signed into law in August 2022. The proposed guidance for 45V was not issued until late December 2023. Final guidance took an additional year to land, as 30,000 public comments were submitted, and multiple federal agencies collaborated intensively. 

Building up a clean hydrogen industry in the United States was among President Biden’s signature initiatives, but progress was slow during the two-year wait for the final rules and the key clarifications they provide on what qualifies as “clean.” 

Producers will need to wait a few more weeks for the Department of Energy to issue its updated 45VH2-GREET model so they can calculate the section 45V tax credit. (GREET is the Greenhouse gases, Regulated Emissions and Energy Use in Technologies life cycle analysis suite developed by the Department of Energy’s Argonne National Laboratory.) 

Hydrogen holds promise as a fuel that does not generate carbon emissions, but it is expensive to produce. The Biden administration’s push is to lower the price of producing clean hydrogen while also lowering carbon emissions associated with its production. 

Environmental advocates pressed for tight rules on the emissions-free energy used to generate clean hydrogen and industry representatives pressed for looser controls that would help make green hydrogen more economical. 

In their Jan. 3 news release, the U.S. Department of the Treasury and Internal Revenue Service promise clarity, safeguards and flexibility in the rules, which drill down to grid regions, hourly accounting, upstream methane leakage, carbon sequestration, fugitive methane use and temporal matching of electricity generation and hydrogen production. 

The guidance stretches 379 pages. Wolak noted that it is extremely complex, “and will require intense evaluation by project developers to understand all the nuances and how they will apply to their specific facilities.” 

It is scheduled to be published Jan. 10 in the Federal Register. 

John Podesta, senior adviser to the president for international climate policy, said in the news release: “The extensive revisions we’ve made in [these] final rules provide the certainty that hydrogen producers need to keep their projects moving forward and make the United States a global leader in truly green hydrogen.” 

Wolak said the final rules are not the final word: “This issuance of final rules closes a long chapter, and now the industry can look forward to conversations with the new Congress and new administration regarding how federal tax and energy policy can most effectively advance the development of hydrogen in the U.S.” 

Other organizations had mixed reactions, but most had something good to say about the rules, even if they also offered some criticism. 

Clean Air Task Force senior U.S. director Conrad Schneider said: “We appreciate Treasury moving toward better hydrogen policy in its final rule for clean hydrogen production. … We hoped to see stricter guardrails around the use of existing clean electricity to make hydrogen, but we are glad the final guidance includes criteria for determining the incrementality of existing clean electricity, especially existing nuclear energy, that accounts for the unique circumstances of each plant. We are, however, disappointed in Treasury’s decision to push hourly matching from 2028 to 2030, and we worry that this could cause at least some increase in emissions in the short term.” 

Constellation Energy Corp., the nation’s largest nuclear reactor operator, applauded a change from the tentative rules that will allow existing nuclear plants to claim tax credits for powering clean hydrogen production. But the company stopped short of any commitment. “Constellation is carefully reviewing the impact of the final rules as well as newly proposed electric transmission charges on the feasibility of its proposed clean hydrogen project at the LaSalle Clean Energy Center and Constellation’s role in the MachH2 Hub,” the company stated in a news release. 

CEO Joe Dominguez added: “While any incrementality limit is incompatible with the conclusion that clean hydrogen customers should be able to use reliable nuclear energy from America’s fleet of plants, the final rule is an important step in the right direction.” 

Investment firm Jefferies said Jan. 3 that it does not expect operators of existing U.S. nuclear plants to pursue the clean hydrogen market because data center contracts are more lucrative and less risky. 

Business Council for Sustainable Energy President Lisa Jacobson said: “The release of the final rules will allow project developers and investors to better assess credit eligibility and open investment opportunities in the U.S. hydrogen industry. The rule provides clarity and flexibility in several areas but will also require continued engagement with the Trump administration and Congress on a number of critical open implementation issues.” 

The Environmental Defense Fund said 45V presents an opportunity to reduce pollution while building new markets. “Clean hydrogen can help clean up parts of the economy that are hard to decarbonize any other way, but only if we do it right,” said Beth Trask, EDF vice president for global energy transition. “Proper implementation of the production tax credit could help catalyze private investment, lower costs and drive global demand for American-made hydrogen. But risks remain that public incentives for clean hydrogen could go toward fossil fuel-based projects that offer no real climate benefit and undermine the integrity of the U.S. hydrogen market.” 

The National Resources Defense Council took a similar stance. “The final guidance is an important step towards a truly clean hydrogen industry. The rule provides much needed certainty for the industry and positions U.S. producers to be competitive in the global market,” NRDC hydrogen advocate Erik Kamrath said. “The extra flexibilities granted to the green hydrogen industry are not perfect from a climate perspective. But the rule maintains key protections that minimize dangerous air and climate pollution from electrolytic hydrogen production while also protecting U.S. taxpayers and electricity consumers.” 

Earthjustice was less complimentary. “The Biden administration’s tax guidance supports clean hydrogen projects that by and large do not worsen climate and health-harming pollution, but more protections are needed,” legislative director for climate and energy Chris Espinosa said. “The administration included several significant loopholes for dirty hydrogen producers to enjoy the benefits of this important climate program.” 

CNX Resources, an independent company extracting natural gas from shale in the Appalachian basin, said the 45V rules do not work for its purposes: “The Department of Treasury’s recognition of captured waste coal mine methane (CMM) as a feedstock for hydrogen production is validation of its inherent environmental and economic benefits and an important step in continuing to monetize the value of this unique asset. However, we believe that the final 45V implementation rules are overly restrictive across a range of feedstocks and do not currently appear to create sufficient economic incentives for the company to expand its CMM capture operations for hydrogen end use.”