U.S. utilities continue to ratchet up load growth forecasts in their integrated resource plans.
As of September 2025, the IRPs are projecting demand will be 24% higher in 2035 than in 2023, RMI reported Oct. 15. This compares with 12% in December 2023 and 6% in January 2021.
The third-quarter “State of Utility Planning” report is the latest in a series by RMI and combines data from 130 IRPs. As RMI notes in its preface, IRPs are not a clear picture of the future, but they do provide a snapshot of trends, goals and strategies to meet those goals.
The third-quarter report is the first that reflects the impact of the One Big Beautiful Bill Act, with its phaseout of tax credits for wind and solar generation, which recently have been the largest source of new U.S. generation by nameplate capacity.
Other factors gaining prominence in the third quarter included delayed fossil retirements, uncertainty in planning, inability to bring new resources online quickly and difficulties in buying electricity from neighboring utilities.
Trends continuing from previous quarterly reports include changes in resource adequacy rules, particularly in MISO, as well as the expectation that new large loads will present demands that cannot easily be met.
These factors are set against a background of considerable uncertainty over factors such as resource costs, market rules, EPA regulations, other federal policies, frequency of extreme weather events, state policies and the load-growth forecasts themselves. The forecasts are demonstrably imprecise, and some observers maintain that top-end projections are unrealistically large.
Every IRP reviewed for RMI’s third-quarter report increased the load forecast over previous projections but also showed a wide range of uncertainty about the size of that increase. Both the quantity and hourly profiles of these new loads differ from historical trends.
The difficulty of resource planning amid all this is a common point of discussion for utilities, RMI said, along with the need to devise new ways to meet future needs.
RMI noted that since it began tracking IRPs, load projections have increased in all nine quarters and cumulative emissions projections have increased for seven consecutive quarters.
It also pointed out that emissions reductions are lagging in utility projections: The companies examined have targets of 63% emissions reductions by 2035 from a 2005 baseline, but their IRPs would lead to only a 53% reduction.
The IRPs include 259 GW of wind and solar additions through 2035, 103 GW of natural gas additions and 74 GW of coal retirements. This is 2.4% more wind and solar than was planned as of the end of 2023 but 106% more natural gas.
RMI acknowledged the challenges facing electric utilities as they try to balance regulations, costs for customers, profits for investors and climate impact.
But the clean energy advocacy nonprofit also said delayed fossil retirements and new gas generation are the default choice in most IRPs, which instead should incorporate alternatives such as energy efficiency, virtual power plants, grid enhancing technologies and clean repowering.
These alternatives — along with policy and regulatory support — would help utilities hold down costs as they transition to a zero-carbon future, RMI concludes.
The report combines historical data from RMI’s Utility Transition Hub with IRP data manually collected by EQ Research. The 130 IRPs reviewed would cover approximately 48% of U.S. electricity deliveries.
The Lawrence Berkeley National Laboratory released a paper recently examining why some states have seen retail power prices rise faster than inflation. The listed reasons include distribution investments, extreme weather and wildfire, natural gas prices and state renewable targets.
“Factors influencing recent trends in retail electricity prices in the United States” includes an article in The Electricity Journal. It found that states in the Northeast and on the West Coast saw some of the biggest price increases from 2019 to 2024 but noted the national averages were in line with inflation.
In nominal terms, prices rose 23% between 2019 and 2024. Controlling for inflation, they were flat outside of a bump in 2022 related to the Ukraine-Russia war’s effect on natural gas prices. The national average masks a big difference in state average prices that range from 8 cents/kWh in North Dakota to more than 27 cents/kWh in California.
“Examining recent trends in inflation-adjusted prices, 31 states saw real price declines from 2019 to 2024, while 17 states experienced increases,” the article said. “States on the West Coast and in the Northeast were most affected by rising prices — especially California, where average retail prices increased by 6.2 cents/kWh in real 2024 dollars.”
States with the greatest price decreases typically exhibited increasing customer loads over that period, which misses the recent run-up in PJM capacity prices in the 2025/2026 auctions that are affecting customer bills now, according to a presentation accompanying the study.
PJM’s Independent Market Monitor found that new data center load contributed to the largest chunk of the capacity price increase (alongside some market design parameters), and most PJM states saw retail prices jump from 10 to 15% when the new delivery year started.
Rising demand from data centers, manufacturing and other sources has been cited as creating a risk of higher prices due to their purported impact on wholesale markets, higher retail prices or cost allocation policies that might favor large commercial and industrial customers in the name of economic development. But the study found that load growth from 2019 to 2024 tended to reduce retail prices.
“In the 2019-2024 time frame, the regression suggests that a 10% increase in load was associated with a 0.6 (±0.1) cent/kWh reduction in prices, on average,” the article said.
That aligns with the understanding that a primary driver for utility spending has been refurbishing existing transmission and distribution infrastructure in recent years. Spreading those costs over a larger base cuts average prices, but the study noted that negative load-price relationship was seen in average prices and lost when focused on residential prices.
“Load growth over this historical period was led by commercial customers, and cost allocation practices have tended to benefit those large, non-residential customers,” the article said.
The study focuses on average prices across customer classes, but it noted that residential prices generally are higher than commercial and industrial prices and have risen more than those classes in recent years.
Investor-owned utilities have seen prices rise faster than public power, but the article noted that in California it is largely due to differences in wildfire risk and related costs.
“States with the greatest price increases typically exhibited shrinking customer loads — partially linked to growth in net metered behind-the-meter solar — and had renewables portfolio standards (RPS) in concert with relatively costly incremental renewable energy supplies,” the article said.
Net energy metering offers participants bill savings, but utilities must invest more in their distribution systems and recover fewer fixed costs from customers on NEM programs. The study found a 5% increase in net-metered, behind-the-meter solar led to an average price increase of 1.1 cents/kWh.
Utility-scale wind and solar development that happened outside of RPS might have led to lower retail prices in recent years, though the impact was not statistically significant, the article said. It added that RPS targets are likely to increase prices if they lead to renewables the market would not have delivered. Three-quarters of utility-scale wind and solar growth from 2019 to 2024 happened outside of RPS mandates.
Another major driver of higher prices is extreme weather, which impacts two of the states that have seen prices rise the most in recent years – Maine and California. Central Maine Power’s storm recovery cost rider rose from 0.1 cents/kWh in late 2020 to 1.8 cents/kWh in 2024.
“Between 2019 and 2023, California’s three large IOUs were authorized to include $27 billion in wildfire-related costs in retail prices,” the article said. “By June 2024, wildfire-related costs constituted an average of 17 % of total IOU revenue requirements, up from 1.7 % in 2019 and, if directly translated into one-year cost impacts, equivalent to a 4 cent/kWh increase.”
On average, the states with the highest wildfire risks have seen power prices rise by 1.1 cents/kWh, the article said.
A new report outlines a high-level road map for cross-border interregional transmission planning in the Northeast, making the case for more coordinated planning processes across sub-regions and regulatory environments.
The analysis, authored by the energy consulting firm Power Advisory, was commissioned by the Northeast Grid Planning Forum. The forum is an initiative of Nergica, a Quebec-based clean energy research organization, and the Acadia Center. (See New Initiative Focuses on Interregional Tx Coordination in the Northeast.)
“Provinces and states could benefit through enhanced coordination and transmission project development that optimizes utilization of existing resources and enables development of new clean energy sources,” Power Advisory wrote.
While studies have shown significant potential for increased interregional transmission throughout the Northeast, “fragmented planning processes and challenges presented by differences in regulatory structures” have limited states and provinces’ ability to fully realize these benefits, the authors wrote.
They emphasized the need to build trust, increase information access and establish mechanisms to facilitate transmission partnerships across regions and borders.
“A collaborative planning framework will require new approaches to sharing information and will require harmonizing planning processes to meet the requirements and planning horizons of each jurisdiction,” Power Advisory wrote. “Transparency and engagement will provide confidence in identified needs among jurisdictions and stakeholders.”
The report highlights several recent larger-scale transmission planning efforts as evidence of growing interest in interregional planning.
In June, the Northeast States Collaborative on Interregional Transmission, which includes nine states, issued a request for information (RFI) to identify “potential interregional transmission opportunities … that improve grid reliability, support economic growth and reduce costs for consumers.”
The states asked for input on potential cost allocation methods and wrote that responses to the RFI will “inform potential future solicitations or transmission planning activities.”
International cooperation around transmission planning also has increased. In 2024, the New England Governors and Eastern Canadian Premiers agreed to reconvene the Northeast International Committee on Energy, directing the committee to establish working groups “to pursue regional collaboration and planning on the topics of transmission, offshore wind supply chain and hard-to-decarbonize sectors.”
In Atlantic Canada, top politicians are eying a massive buildout of offshore wind generation, which would require large-scale interregional transmission developments to move the power to load centers in Canada and New England.
According to a strategic plan published by Nova Scotia, researchers have identified offshore wind sites that could host 62 GW of generation. Nova Scotia has proposed a 5,000-MW first phase of development, requiring an estimated $40 billion in capital investment to build the generation and $20 billion to build the associated transmission.
These recent efforts “indicate recognition by the key jurisdictions that current transmission planning approaches are constrained and insufficient and need to change to realize the benefits of broader regional energy system integration,” Power Advisory wrote.
To select projects, existing regional competitive transmission solicitation processes could be aligned to allow for interregional projects, or new processes could be stood up, the authors wrote.
“The recently established ISO-NE Longer-Term Transmission Planning (LTTP) process provides an instructive model for need identification across a multi-jurisdiction region,” they said.
ISO-NE is evaluating project submissions for the first iteration of its LTTP process, which is focused on increasing transmission capacity in Maine and enabling the interconnection of onshore wind generation. (See ISO-NE Reveals 1st Details of Long-term Transmission Proposals.)
States and provinces also would need to establish cost sharing processes and could take inspiration from Europe’s cross-border cost allocation methodology, the authors wrote.
Cost allocation “should ensure full consideration of all benefits evaluated in each participating jurisdiction,” including “reduced production costs, avoided capacity costs, avoidance of alternative transmission investments, improved transmission system efficiency, reliability and other benefits,” the authors added.
To address the challenges of determining needs, selecting projects and allocating costs across regulatory authorities, states and provinces should establish “a joint coordination agreement” that “formalizes collaboration and provides a clear mandate for agency staff regarding the scope of future work,” Power Advisory concluded.
This could mirror the memorandum of understanding underpinning the Northeast States Collaborative and could lay the groundwork for answering more technical questions related to modeling, information sharing and aligning existing processes, they wrote.
Can’t keep all of MISO’s new demand response rules straight? You’re not alone.
The grid operator convened a stakeholder workshop Oct. 14 to go over new requirements for demand response resources heading into the 2026/27 planning year.
After multiple instances of fraud and misrepresentation from DR in MISO’s capacity market, the RTO has spent months developing stricter rules to deter abuse.
The RTO has made:
A March 2025 filing seeking to discourage nonexistent or overstated curtailments by requiring proof of contracts and hourly meter data while instituting reference levels for DR resources so they cannot inflate baselines. FERC accepted the stricter rules in July (ER25-1729).
An April 2025 filing to put an end to MISO allowing load-modifying resources to also identify as emergency demand response and collect extraneous capacity payments. FERC also accepted the changes in July (ER25-2050).
An April 2025 filing to divide load-modifying resources into fast and slow categories for capacity accreditation, with the faster resources receiving higher accreditation values. The pending filing wouldn’t take effect until the 2028/29 planning year (ER25-1886). (See MISO Approaching LMR/DR Accreditation Based on Availability.) FERC in September decided it needed more information on the proposal’s inner workings and issued a deficiency letter.
A July filing to mandate its demand response to make real-world demand reductions for tests instead of submitting mock tests to prove capability. (See MISO Tries to Ward Off DR Fraud with New Testing Regime.) FERC hasn’t yet decided whether to accept MISO’s proposal and issued an August deficiency letter to glean more information. The new testing rules would apply retroactively for any tests after July 15, 2025, if MISO’s proposal wins approval (ER25-2845).
MISO plans to file at FERC for permission to more consistently dole out monetary penalties when a DR resource delivers less than promised, effective June 1, 2026. It also plans to bar energy efficiency from participating in its capacity auctions. (See MISO to Axe Energy Efficiency from Capacity Market.)
MISO senior market design economist Joshua Schabla reviewed new rules stemming from the filings that pertain to DR contracts, broader penalties, testing and providing MISO with documentation. MISO included the end of mock testing and stepped-up monetary penalties in its roundup, though those rules don’t have FERC approval yet.
Docs and Data
Before summer 2026, MISO will insist on more descriptive documentation for DR that details the operating procedures used to curtail load, how the market participant communicates with the facility making the cuts, the expected time to draw down the load and confirmation that the load can be held at a minimum amount for four consecutive hours.
“What we need to see is that the persons physically responsible for curtailing the load understand what they need to do and how they will do it; it does not need to provide confidential information but should be specific enough that a reasonable third party feels confident the facility knows what they’re doing,” Schabla said of the required documents.
MISO also will require written verification from facility owners that real power tests reflect what they expect to curtail if called upon by MISO.
Schabla pointed out that DR resources voluntarily participate in MISO’s capacity market and receive compensation to do so.
“With that, there comes a certain level of expectation of the documentation they submit,” Schabla said. He also said MISO wants to have confidence that DR resources are real, that ratepayers are paying for actual capacity and that members aren’t making decisions to retire generation or forgo adding generation because of fake DR megawatt reductions.
“We feel like we’re asking for some very fundamental and basic information,” Schabla said. He added that MISO wouldn’t outright reject registrations if information is lacking; rather, it would reach out for more data.
MISO also wants every non-residential resource that’s registered to submit a physical address of the load’s location.
“What we’re trying to accomplish here is to figure out where these LMRs are located,” Schabla said, adding that the addresses are a starting point.
Beginning in the 2027/28 planning year, MISO said it would further require market participants to submit the elemental pricing nodes for DR resources that are at least 5 MW.
Schabla said MISO hopes to gain more visibility into LMR and eventually be able order more targeted curtailments in instances like local transmission emergencies. He said the extra year should provide “plenty of runway” for market participants to start assembling more exact location data.
Moving into the 2026/27 auction, MISO will require market participants with DR to submit hourly metered output from every resource in the seasons they’re signing up to contribute. The RTO said it would allow single aggregated values from residential DR programs.
Enel X’s Allison Miller said time is running out to make registrations for the 2026/27 auction, but MISO has yet to finalize all the new rules and provide all registration templates. She also said there’s still a “back and forth” at FERC on MISO’s real power testing proposal, which was issued a deficiency letter.
Other stakeholders asked if MISO would hold another workshop to get stakeholders better acquainted with the new rules. Schabla said MISO would not. Schabla said MISO isn’t attempting to shut DR out of its markets but needs to discourage bad actors.
“We just want to make sure what we’re paying for is quality,” Schabla said.
At an Oct. 1 Resource Adequacy Subcommittee, MISO’s Neil Shah said MISO understands it’s putting market participants through tremendous change with its new demand response rules.
LMR Replacement Becomes an Option
There may be a silver lining in the 2026/27 auction: MISO will permit market participants to replace their load-modifying resources if the original resources become unavailable. MISO will allow demand response to replace (and avoid penalties for nonperformance) when a contract previously approved by state regulators is terminated or if there’s a change in ownership of the facility contracted to dial back load.
For behind-the-meter generation, MISO will allow replacements in the event of outages that are communicated to MISO at least two weeks in advance or if regulatory restrictions crop up, such as environmental run-time limits. MISO also said load-modifying resources can replace on a case-by-case basis with approval from MISO’s Independent Market Monitor.
The grid operator said it plans to hold DR resources to more rigid nonperformance penalties and make a FERC filing soon. MISO plans to assess penalties when DR resources are coming up short on what they said they could provide or when a resource is marked as unavailable but is consuming demand during an emergency. Penalties would be based on auction revenue and include a charge based on locational marginal prices at the time.
MISO will divide penalties into either partial failures (when a DR resource has provided at least 25% of its required response) or complete failures (when the resource has supplied less than 25%). MISO said repeat complete failures would lead to disqualification as a capacity resource.
However, MISO said it will offer penalty exemptions for when behind-the-meter generation must perform maintenance. For that, the market participant would have to pre-schedule a no more than 31-day outage in either a spring or fall period (March 1 to May 15, and Sept. 15 to Nov. 30, respectively).
Schabla said MISO realizes it’s unrealistic for 30 to 40% of its behind-the-meter fleet to seemingly never need annual outages, as is the case now.
Finally, MISO stressed the importance of market participants updating their availability in its nonpublic Demand Side Resource Interface. Schabla said offers made in the 2027/28 planning will begin to affect DR accreditation in the 2028/29 planning year. Beyond that, MISO didn’t touch on the new accreditation, reasoning that it was too early to address it.
The fate of a 6.2-GW cluster of solar energy projects in western Nevada is uncertain following the Bureau of Land Management’s decision to break the group into individual projects for review.
On its National NEPA Register, BLM changed the status of the Esmeralda 7 to “canceled” Oct. 9. The group consists of seven proposed solar projects ranging from 500 MW to 1.5 GW, each with battery storage, on federal land in Esmeralda County.
But the Department of the Interior clarified in an email that “BLM did not cancel the project.” Instead, “the proponents and BLM agreed to change their approach” to project review, the department said.
“The projects were initially submitted as a group,” Interior said. “The developers will now pursue individual applications for their respective projects. This approach ensures focused, thorough assessments of potential impacts on public lands while supporting responsible energy development.”
Interior said the new approach “aligns with the administration’s emphasis on improving permitting efficiency and reducing regulatory burdens.”
It wasn’t clear how the change in the BLM review process might impact project timelines, or whether all the proposed projects will proceed. If completed, several of the individual Esmeralda solar projects would be among the largest in the U.S.
In July 2024, BLM released a draft programmatic environmental impact statement and resource management plan amendment for Esmeralda 7. A 90-day public comment period followed. The completed work will still be useful as individual projects move forward, Interior said.
And at least one project developer plans to forge ahead.
NextEra Energy Resources is developing the Esmeralda Energy Center, described in a November 2023 project overview as 1 GW of solar with battery storage.
“We are in the early stages of development and remain committed to pursuing our project’s comprehensive environmental analysis,” a NextEra Energy spokesperson said in an email. “[We] will continue to engage constructively with the Bureau of Land Management.”
Another project is Lone Mountain Solar, 1 GW of solar and 500 MW of battery storage being developed by Leeward Renewable Energy. A timeline on Leeward’s website shows a 2027 construction start date with projected completion in 2029. A Leeward spokesperson said the company did not have any information to share regarding the impact of changes to the BLM review process.
The other projects are:
Gold Dust Solar, 1.5 GW of solar and 1 GW of storage developed by Arevia Power;
Nivloc Solar, 500 MW of solar with battery storage by Invenergy;
Smoky Valley Solar, 1 GW of solar with battery storage by ConnectGen; and
Red Ridge 1 and 2, each 600 MW of solar with battery storage by 335ES 8me.
Developers had planned to interconnect their projects through Greenlink West, NV Energy’s 350-mile, 525-kV transmission line under construction across the west side of the state.
Each solar project would include a tie line connecting to Greenlink West’s Esmeralda substation.
One goal of Greenlink West and Greenlink North, a transmission line planned across northern Nevada, is to open more of the state to renewable resource development. When completed, the two Greenlink lines along with the existing One Nevada Line will form a transmission triangle around the state.
Energy development within transmission corridors such as Greenlink West is expected to drive additional local and regional renewable energy development, BLM said in its draft environmental report.
The antipathy of the Trump administration to the offshore wind industry is well known, and so it has come as little surprise that various federal agencies have been directed to impede the progress of offshore wind developments. This comes at a bad time, just as the multibillion-dollar industry was gearing up, constructing ports and building ships, while training the workforce necessary for the remarkably challenging task of building gigawatts of wind capacity miles offshore.
An Initially Promising Resource: In the early and heady years, the U.S. industry had looked eagerly to Europe’s North Sea, where each new offshore project boasted progressively lower costs, and gigawatt-scale projects quickly emerged. That anticipation soon translated to U.S. markets, where billions of dollars were funneled into enabling infrastructure and supply chains, and the Biden administration announced an ambitious target of 30,000 MW of offshore capacity by 2030. Offshore federal leases for hundreds of thousands of acres along the East Coast were signed, followed by the first steel in the ground, for projects as large as Dominion’s $10.9 billion, 2,600-MW Coastal Virginia Offshore Wind Project.
A Radical Change in Direction: With the 2024 presidential elections, however, the winds of fortune shifted rapidly. Within months, the Trump administration announced it was taking a hard line in opposing such projects, and it became clear the future of the industry might be in peril. Most observers were surprised, however, by the intensity of the opposition.
Since taking office, the new administration’s Bureau of Ocean Energy Management (BOEM) has stopped leasing new projects, rescinding all previously designated offshore wind areas, while withdrawing nearly $680 million for ports and manufacturing, and prematurely ending the program of federal tax credits. Perhaps even more critically, the Trump administration took the additional and largely unexpected step of targeting specific projects that already were underway.
The first affected was New York’s 810-MW Empire Wind project, which was roughly 30% complete when hit by a stop-work order in April which Secretary of the Interior Doug Burgum justified in a letter to the BOEM saying the project had been “rushed through” the approval process by the previous administration “without sufficient analysis or consultation among the relevant agencies.” The project got back on track a month later, apparently following an arrangement for a quid pro quo affecting a long-delayed New York gas pipeline.
That was followed by New England’s 700-MW Revolution Wind project, which was 80% complete when it got smacked by a stop-work order. The justification in this instance was national security concerns, with Secretary Burgum at one point citing the possibility that “people with bad ulterior motives against the United States would launch a swarm drone attack through a wind farm.” That order was quickly overturned by a U.S. District Court judge, who characterized the order as being “the height of arbitrary and capricious action.”
Then last month, the BOEM also filed a lawsuit to revoke a critical permit for the 2,200-MW Maryland Offshore Wind Project, claiming it had previously underestimated the effect on search and rescue helicopters and to offshore fisheries.
For its part, the Coastal Virginia Offshore Wind endeavor continues to move forward, reaching 60% completion, with plans to start delivering power by March 2026. It thus far has managed to avoid federal backlash, with a Dominion spokesperson recently and explicitly citing the historical bipartisan support for the endeavor.
So, for at least the next several years, we will have two categories of projects: those that manage to squeak through to commissioning, and those that will never make it, despite years of planning, permitting activities and investments in ancillary infrastructure such as ports and ships. Longer-term, the industry may take decades to recover, if it ever does, with investors rightly reluctant to dip their toes into politically fraught waters.
The Costs to Our Power Grids and Investors: Already, the economic casualties are mounting. The latest, announced the second week of October, is Maersk’s cancellation of an order for a $475 million offshore wind turbine installation ship that is 99% complete and was intended to support New York’s Empire Wind effort. There will be many more such investments stranded on the hostile shores of the U.S. offshore wind debacle, totaling in the many billions of dollars, and the implications of these failures likely will spread well beyond a few wind farms. Let’s examine the ones that matter the most.
First, there are significant implications for utilities and grid planners in affected areas. Many of these offshore projects have been in the planning stages for years, and the grid operators (as well as other energy investors) have incorporated them into their energy resource and transmission planning processes.
Since these are big projects, their success or failure matters greatly, especially given the difficulty and time required for alternative projects to navigate interconnection queues. One doesn’t simply replace these canceled projects with a fleet of gas turbines overnight (one will probably have to wait many years to access a new turbine).
Pursuant to the Revolution Wind stop order, grid operator ISO-NE commented that it “is expecting this project to come online and it is included in our analyses of near-term and future grid reliability. Delaying the project will increase risks to reliability. … Beyond near-term impacts to reliability in the summer and winter peak periods, delays in the availability of new resources will adversely affect New England’s economy and industrial growth.”
The grid operator went on to say: “Unpredictable risks and threats to resources — regardless of technology — that have made significant capital investments, secured necessary permits and are close to completion will stifle future investments, increase costs to consumers, and undermine the power grid’s reliability and the region’s economy now and in the future.”
And that gets to the heart of the matter for all energy investors. Unpredictability is the greatest threat to a functioning economy, especially if that uncertainty is politically driven and perceived to be mercurial. Today’s energy darling can quickly become tomorrow’s pariah.
Offshore wind may be the target of the current administration, but at some future date, those winds may shift again. Which is why ExxonMobil CEO Darren Woods commented to The New York Times in September that “ever-changing policy, particularly as administrations change, is not good for business.”
In September, Martin Durbin, senior vice president of policy for the U.S. Chamber of Commerce, voiced similar sentiments and cautioned against yanking existing project permits, since such a practice “injects significant uncertainty into the infrastructure development process” and could increase the cost of electricity for consumers.
That sentiment was echoed more recently by the president of Shell USA, who pointed out in October that the current approach of canceling permitted projects is damaging to business, noting the risk: “However far the pendulum swings one way,” she said, “it’s likely that it’s going to swing just as far the other way.”
The Need for a More Consistent Regulatory Environment: The stroke of the regulatory pen is powerful in its ability to stimulate investments at a time when the country’s economy desperately needs more energy. But if that same pen cannot be relied upon to exhibit some level of predictability and consistency, then our energy future becomes very uncertain indeed. The infrastructure that supports our ability to generate and move those critically needed electrons relies heavily on a regulatory environment that offers some consistent level of predictability.
Investors must have faith that the hundreds of billions of dollars they place at risk in building out our future energy world will not be arbitrarily affected by a capricious regulatory approach supported by flimsy justifications. The U.S. traditionally has been a far more stable haven for investment than many parts of the world, and we have flourished as a result.
However, if we increasingly turn this effort into a risky and unpredictable political game, the global flow of capital will look for a more hospitable home, and we in the United States will all be the poorer for it.
Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.
New Jersey is evaluating a request by two solar companies to change state rules that bar out-of-state solar electricity generators and providers from participating in the program for Class 1 renewable energy certificates (REC).
The two companies — VC Renewables of Newark, a solar developer, and an affiliate, Vitol, an energy provider — say the change would allow 23.5 GW of already-installed out-of-state renewable resources to participate in the REC program and help the state fulfill its renewable portfolio standards (RPS) obligations. They say the rule change could save ratepayers hundreds of millions of dollars.
“Permitting competition from lower-cost out-of-state solar resources could generate New Jersey consumer savings of at least $200 million to $500 million per year while maintaining New Jersey’s ambitious clean energy goals as well as the economic and employment benefits of in-state solar development,” the companies argue in their petition.
Allowing out-of-state solar into the program would “increase competition to generate Class I RECs and thereby decrease the New Jersey ratepayer costs of compliance with the state’s ambitious RPS targets,” the petition argues. It also would enable third-party suppliers and basic generation service providers to “satisfy their renewable portfolio standards obligations,” the petition said.
The New Jersey Board of Public Utilities (BPU) voted Oct. 8 not to rule on the issue for 90 days while it considers the issue. “I think there is going to be a lot of stakeholder input on this matter,” so more time to deliberate would be helpful, said BPU President Christine Guhl-Sadovy.
Consumer Price Cutting
RPS programs lay out requirements for the amount of clean energy from low- or zero-carbon emission sources; all suppliers or providers that sell energy to retail customers must in the current energy year ensure that 35% of it is clean energy, rising to 50% clean energy by 2030.
As in some other states, New Jersey offers a REC — a payment for the generation of 1 MW of clean energy — to developers or generators as an incentive to encourage investment in clean energy generation
While wind, tidal, geothermal, methane, biomass and other types of energy generated outside of New Jersey are accepted in the Class 1 REC program, solar energy must be generated in-state to participate.
The New Jersey Class 1 REC program is a separate market from the similar — but more lucrative — incentive program that supports most residential solar and other solar facilities in New Jersey, the solar renewable energy credit (SREC) program. Having gone through several iterations, the program — known now as the solar renewable energy certificate II (SRECS-II) program — is part of the successor solar incentive program.
The petition filed by VC Renewables and Vitol, which provides energy in the state basic generation services (BGS) auction, argues that preventing out-of-state solar from taking part in the Class 1 REC program has contributed to a rise in Class 1 REC price from $13 in 2019 to $31 in 2024, which is passed on to New Jersey ratepayers.
Because the state limits supply, New Jersey Class 1 RECs are more expensive on the market than those from Pennsylvania and Maryland. Opening New Jersey to competition from out-of-state generators would push down New Jersey’s REC prices, the petition argues.
“Our petition offers a simple and potentially swift solution to the consumer affordability challenges facing New Jersey residents,” said Jason Barker, vice president for regulatory affairs at VC Renewables. He said it could mean every ratepayer gets the equivalent of an annual credit of $50 to $125.
The petitioners had hoped to have the new rules in place before the state’s next BGS auction in February, enabling providers such as Vitol to submit lower bids, because they will be delivering electricity supported by Class 1 RECs, he said. However, the BPU’s 90-day delay likely means the rule change — if accepted — would not be ready in time.
The change also could stimulate solar development, he said.
“By increasing the opportunities for REC sales, it certainly is an incentive and a motivator for project development throughout the PJM footprint,” he said. “And that helps investors to develop and finance their projects.”
“The RECs are a component of the income stream for a renewable project of any stripe,” he said. “So when a renewable energy developer is developing a project, they’re thinking about all of the potential income streams, whether it’s energy capacity or the clean energy attribute.”
The rule change, he said, is “simply expanding the market for the clean energy attribute for solar across the PJM footprint.”
Market Disruption
The debate comes as New Jersey, like other states, is searching for ways to create new generating capacity in preparation for an expected dramatic increase in demand, mainly driven by the need of data centers and artificial intelligence projects, and to curb the rise in utility rates. The average New Jersey residential electricity bill increased by 20% in June, a hike some industry analysts and state officials say was driven largely by the expected future supply shortage.
Abraham Silverman, a former BPU general counsel who now is a research scholar at Johns Hopkins University’s Ralph O’Connor Sustainable Energy Institute (ROSEI), said New Jersey likely limited out-of-state developers to protect New Jersey’s then-fledgling solar sector. But that protection is not needed now.
Abraham Silverman, former BPU general counsel | Christian Fiore
“At this point it’s just an administrative thing that probably simply increases costs for consumers and means that we buy more wind and less solar,” because out-of-state wind is allowed in the REC program, he said. “We have a very, very robust in-state solar market. … Given where we are today, it really does feel like New Jersey consumers are paying more than they need to.”
Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said he believes the rule changes would reduce ratepayer costs, calling it a “good thing in the current energy cost environment driven as you well know by a lack of new capacity.”
But Leeward Renewable Energy, a Dallas-based wind and solar energy developer, said in an Oct. 1 letter opposing the move that it would create a “regulatory disruption that fundamentally changes New Jersey’s REC market. “
The move would “undermine the original policy aims, disrupt market rules and jeopardize future investment in renewable energy to serve New Jersey,” the company said, noting that providers have signed long term supply or “off-taker” agreements based on existing rules.
“New Jersey’s REC market is the bellwether state for investors evaluating PJM’s market health. Market disruption in New Jersey cascades to investor uncertainty across the entire region,” the letter argued. “Unfortunately, the mere filing of the petition has already created market uncertainty and, in turn, eroded investor confidence in the market.”
LS Power, a New York-based developer, said the change would strand in-state facilities that were developed based on a revenue stream defined by existing rules, which then might face a reduced revenue stream, according to an Oct. 2 letter to the BPU. That would weaken “regulatory certainty” and reduce “investor confidence for future development,” the company said.
In addition, allowing out-of-state projects to take part in the REC program would mean funds flowing to “projects in neighboring states that bypass New Jersey’s permitting, agricultural preservation, and labor standards, creating a regulatory race to the bottom while forfeiting the local job creation, clean air benefits, and grid resilience that in-state projects deliver,” the letter said. Moreover, it added, the change would only minimally reduce New Jersey rates.
Maryland residents can benefit from the rollout of heat pumps the most by targeting state funds for low-income customers, according to a report released Oct. 14 by the Sierra Club’s Maryland Chapter and the Center for Progressive Reform (CPR).
“Building Electrification in Maryland: Implementation of Zero-Emission Heating Equipment Standards for Low-Income Households” found that the right strategies could lead to $145 million in health benefits, $350 million in energy savings and $311 million in climate benefits.
The Climate Solutions Now Act of 2022 set up the zero-emission heating equipment standards (ZEHES) to start replacing fossil-fuel burning heating equipment at the end its life with heat pumps and heat pump water heaters starting in 2029.
The regulations implementing the ZEHES have not been written, and the report seeks to put numbers on the costs and benefits of switching to heat pumps as consumers’ existing equipment needs replacement, report co-author and CPR Senior Policy Analyst Bryan Dunning said in an interview. Another factor was ensuring that low-income customers were not left behind in the transition to technology that has higher upfront costs but is cheaper over its lifetime.
“Utility bills are already high in Maryland right now, full stop,” Dunning said.
The ZEHES program will require that 14,000 space heating units and up to 22,000 water heaters are replaced with heat pumps each year for low-income consumers, who will need significant help to cover those costs, according to the report. Based on the lifespan of current equipment, water heater replacements should be accomplished by 2039 and building heating equipment by 2059.
“In the context of replacements for [low-income] households, modeling projects a yearly total cost of close to $300 million, with an additional cost, depending on implementation policy, of an additional $80 million for building weatherization,” the report says.
Even without the ZEHES program, the water and air heating equipment would need to be replaced at the end of its lifetime at an estimated annual cost of $185 million for low-income households.
While the benefits outweigh the costs, the state will need to help low-income customers, or their landlords, pay for the upfront costs, and recent policy changes at the federal level complicate that.
“Federal funds are not included in our pathway forward,” Dunning said. “One can hope that the feds may elect to support electrification in the future again, the way they had previously done, or perhaps more so, but we did not hang our recommendations on that. So, the numbers that are in our report in terms of the costs and where cost allocation has to come from [are] totally focused on the state side of things. It’s really looking at also specifically leaning on non-general fund money, so you don’t need an additional allocation from the legislature.”
Those funds include the Strategic Energy Investment Fund that comes from the Regional Greenhouse Gas Initiative, the EmPOWER program, the Clean Heat Standard being developed by the Maryland Department of the Environment and low- to zero-interest financing from green banks. In general, the paper recommends that bigger shares of the funding from some of those programs go to low-income consumers.
Given that the program does not start until 2029, the report suggests starting on replacing heating sources that have the biggest payback, which are oil, propane and electric resistance heating, the last of which is not part of ZEHES. But rolling out heat pumps comes with a quicker repayment period now than those that use natural gas, at just four years, while replacing electric water heaters with heat pump technology can be paid back in three years.
“Over 61% of water heaters in [low-income] Maryland homes currently employ electric resistance and would quickly benefit from replacement,” the report says. “Tanked heat pump hot water heaters can heat during off-peak hours, holding the hot water until peak morning hours during the winter and peak evening hours during the summer. Because they can schedule operation, these heaters can lower peak electric demand, thus contributing to lower electric rates and reducing grid congestion.”
All heat pumps have some electric resistance backups in them, which would kick in during the rare winter arctic cold snaps that impact Maryland, though generally the state’s climate is well suited for the technology, Dunning said.
“Maryland exists in a bit of a Goldilocks zone climate wise,” he added. “It’s our position that you can do this without backups.”
Backup heating sources are sometimes in states further north, but Dunning said arguments from utilities to keep natural gas heating as a backup do not make sense given the normally mild winters in Maryland.
PJMpresented several non-competitive projects it plans to recommend be included in the 2025 Regional Transmission Expansion Plan Window 1, with a first read on the competitive selections planned for the November TEAC meeting.
A $58.5 million project would rebuild 11.9-mile segments of the College Corner-Collinsville and College Corner-Trenton 138-kV lines in the DEOK zone and adjust relays at the three substations to avoid an overload on the College Corner-Collinsville line. The project has a required in-service date of June 2030.
A $45.8 million project would install a 765/345-kV transformer at the Wilton Center substation in the ComEd zone to resolve two overloaded transformers at the site, with a required in-service date of Dec. 1, 2030.
A $23.9 million project in the APS zone would construct a 138-kV substation, named McCanns Road, to be cut into the Redbud-West Winchester and Bartonville-Stephenson 138-kV lines. The segment between McCanns Road and Redbud also would be reconductored. It would mitigate a potential load drop exceeding 300 MW in the winter case under N-1-1 contingencies. It has a required in-service date of June 1, 2030.
A $9.15 million project in the APS and PN zones would rebuild 1.9 miles of the Garrett Tap-Garrett 115-kV line, install optical ground wire and adjust relaying at surrounding substations to alleviate overloads identified on the line.
A $9.93 million project in the PSEG zone would reconductor the 230-kV corridor between the Roseland, Livingston Avenue and Laurel Avenue substations to resolve overloads on lines. The project has a required in-service date of June 1, 2030.
Many of the competitive submissions proposed expanding the 765-kV backbone. Several large load adjustments in the PPL region, including around 2.7 GW of load expected near the Susquehanna switchyard by 2030, are driving need for additional transmission between the Mid-Atlantic Area Council and PPL. Generation growth in southern Dominion also will require upgrades across the region. (See “PJM Presents RTEP Update,” PJM TEAC Briefs: Sept. 9, 2025.)
Supplemental Projects
FirstEnergy presented a $156.7 million project in the Penelec zone to rebuild around 34.1 miles of its Fores-Glade 230-kV line, which it said is nearing the end of its life at 65 years old. Inspections found deteriorating wood poles and broken insulators along the line and one outage was caused in the past five years by a pole failure. The project also includes reconductoring a bus at the Glade substation. The project is in the conceptual phase with a projected in-service date of May 31, 2029.
The utility also presented a $50.2 million project in the JCPL zone to mitigate the risk of 52 MW being taken offline under N-1-1 contingencies by rebuilding its Leisure Village substation and replacing equipment at the Manitou and Lakewood facilities. Leisure Village would be reconfigured as a breaker and a half (BAAH) with nine new 230-kV breakers, an additional 230/34.5-kV transformer, attached to two high side breakers, and two new 34.5-kV transformers. Line relaying at South Lakewood, Silverton, Drum Point and Cedar Bridge also would be adjusted. The project is in the conceptual phase with a possible in-service date of June 1, 2029.
AEP presented two needs to serve load growth in New Carlisle, Ind., and Madison County, Ohio. The Indiana customer seeks to expand the load connecting to the proposed Navistar 345-kV substation by 692 MW, with a requested in-service date by June 2029. The Ohio customer wants a new 345-kV delivery point with an initial load of 100 MW on Aug. 14, 2029, which is expected to grow to 750 MW.
PPL presented a $231.7 million project to serve a customer seeking to bring 290 MW to the Frackville, Pa., region in 2027, with the intention of growing to around 600 MW by 2029. The project would construct a new 230-kV BAAH substation, named Gordon, cutting into the Eldred-Frackville 230-kV line. The 36.5-mile, 230-kV corridor through Sunbury, Eldred and Frackville would be upgraded from single- to double-circuit, with more terminal equipment installed at each substation. Gordon would be connected to the customer with three 0.1-mile 230-kV lead lines. The project is in the conceptual phase with a projected in-service date of May 30, 2027.
A $74.9 million PPL project would serve a new customer seeking 230-kV service for 200 MW near Lackawanna, Pa., projected to grow to 1,400 MW by 2031. The project would construct a new BAAH 230-kV substation, named Sturges, cutting into the 230-kV Summit-Lackawanna No. 1 and No. 2 lines, as well as the Lackawanna-Callender Gap No. 1 line. Sturges would connect to two customer substations with six, 230-kV lead lines. The project is in the conceptual phase with a possible in-service date of July 30, 2028.
Exelon submitted a need to serve a new customer in the PECO region seeking to bring 250 MW to the Fairless Hills, Pa., region in 2027, which is expected to ramp to 600 MW the following year.
The utility revised a supplemental project to serve a new large load in the ComEd zone, changing the planned lines and increasing the cost from $175 million to $215 million. The substation now will connect to the 138-kV network at Waterman-Crego Road and Line No. 11106, as well as the 345-kV Line No. 15502. The project originally was presented at the Feb. 6, 2024, TEAC meeting and is in the engineering phase with a projected in-service date of Dec. 31, 2027.
Dominion presented 26 needs for data center growth in its zone, several of which are to serve data centers in the growing cluster around Dulles International Airport. Six projects also were presented to serve data centers in Prince William, Stafford, Henrico and Hanover counties, totaling $125 million.
A $30 million project would construct a new substation, named Flamingo, cut into the Elmont-Short Pump 230-kV line.
A $33.5 million project would construct a new substation, named Tropical, cutting into the Techpark Place-Darbytown and Portugee-Chickahominy 260-kV lines.
A $16.5 million project would serve a 213.7-MW data center with a new substation, named Alto, which would cut into the Spartan-Centreport and Aquia Harbor-Allman 230-kV lines.
A $15.5 million project would construct a substation, named Baritone, which would cut into the Alto-Centreport and Alto-Allman 230-kV lines.
WASHINGTON — The challenges of meeting soaring forecasts of data center load growth dominated the Organization of PJM States Inc. (OPSI) Annual Meeting on Oct. 6-7.
PJM CEO Manu Asthana said much of the discussion has centered around reliability and affordability, but what is at stake is national competitiveness over the next century as the U.S. races to keep pace with China in developing artificial intelligence technology. Electricity supply is proving to be a significant bottleneck, he said, as China brought 428 GW of new supply online last year compared to the 49 GW completed in the U.S.
Senior Director of Market Operations Tim Horger laid out PJM’s latest proposal in the Critical Issue Fast Path (CIFP) process focused on large load growth: expediting interconnection studies for large generators, tinkering with voluntary load flexibility through price-responsive demand (PRD) and demand response, and creating more of a role for state utility commissions in reviewing the RTO’s load forecasts. He spoke on the first panel during the meeting, titled “Data Center Load Growth: Is further adaptation at the wholesale level needed?”
The expedited interconnection track (EIT) is designed to create a parallel study process for projects that carry a high certainty of reaching commercial service in a time frame that allows them to address the reliability gap, while minimizing the impact to the wider queue by limiting participation to 10 resources annually.
PJM also is considering requirements for large loads to provide financial commitments before they can be included in the load forecast, a proposition Horger said has been welcomed by data center developers. He said that builds on recent requirements that large loads obtain firm service agreements from their utilities three years in advance before their load can be included in the capacity market. Beyond those three years, he said the ability to have certainty that a particular service request will result in actual load growth becomes murkier.
Data Center Coalition Vice President of Energy Aaron Tinjum said the industry is supportive of expanding commercial readiness verification, such as requirements for electricity supply agreements; permitting reform for construction of new supply; standardization of submitting utility forecasts; and construction milestones for large loads. He said forecasting is foundational to the conversation, as it allows projects to proceed more quickly and with more confidence.
Independent Market Monitor Joe Bowring said he is amazed PJM has not attempted to exercise more authority over requests to adjust the load forecast it publishes, arguing that its stance abdicates the role of maintaining reliability to instead managing unreliability. He said PJM should implement a load interconnection queue that prevents large loads from coming online until they can be served reliably, with an expedited pathway for those bringing their own generation — a concept the Monitor is to present at the Oct. 14 CIFP meeting. He questioned whether it makes sense for PJM to allow large loads to sign up to receive service the RTO cannot provide.
While Bowring said improving the forecast is an important step in understanding the scale of the problem, he cautioned against spending too much time focusing on solutions that do not move the needle on ensuring new load is matched by capacity. He said Monitoring Analytics has been working to improve its own load forecasting, which has long relied on a bottom-up look at the next three years; that has been supplemented with a longer-term, top-down layer looking at the amount of large load that is reasonably expected to come to fruition across the U.S.
Looking at the availability of the chips used by the most power-hungry data centers and the amount of capital expenditure available to the industry, Bowring said about 60 GW of data center growth is expected across the country by 2030. That can be further divided across regions with sensitivities that assume that the share of large load growth will continue along existing projects or following trends in construction or announced projects, which creates a range of 22 to 26 GW of growth within PJM.
Horger said it’s not PJM’s place to call “balls and strikes” on which large load facilities are likely to be built and incorporated into the load forecast. Expanding the RTO’s role in developing the forecast would be complicated by the disparate requirements that states and utilities have on when large loads can be included in the forecasts submitted to PJM, with some requiring contracts and financial commitments.
Arnie Quinn, Vistra senior vice president of regulatory policy, said the Monitor’s proposal would effectively prevent new load growth until the 2030s and faulted PJM’s EIT proposal for requiring new resources to be sponsored by state utility commissions to qualify, which he said could put regulators in a precarious position. He said more focus should be put on who is bearing the risk associated with load growth, suggesting that more of it should be placed on load-serving entities signing up large loads by requiring them to procure capacity or pay a penalty.
He said ensuring the forecast is accurate would guide what forms of load flexibility PJM should pursue, arguing it would be a very different prospect for a consumer to enroll in a program when curtailments are to be expected every few years or much more regularly.
The Needs of AI vs. Cloud Computing
Aroon Vijaykar, Emerald AI senior vice president of strategy and commercial, said data centers appear as inelastic demand while investment in processing power remains high, but that is likely to moderate down the road and create more of an incentive for flexibility as power prices remain high. The large complexes expected to come online also have more of an incentive to explore the range of flexibility options available to them when compared to small consumers. Emerald develops software to allow AI load to be shifted across data centers to manage power consumption based on signals from LSEs and electric distribution companies.
The training phase of AI load tends to be less interruptible because of the risk of introducing errors to complex calculations, but reducing the response time on inference queries can deliver outsized reductions in load, Vijaykar said.
Bowring said the focus on load flexibility is an opportunity to rethink PJM’s market structures, arguing the PRD model isn’t well suited to the task, and the flexibility Vijaykar outlined could be the starting point for new market structures. He has often advocated for shifting DR to the demand side of the capacity market.
Tinjum said hyperscalers represent a small subset of data center usage compared to the shift to cloud computing, which often gets conflated with AI load growth. He said it can be difficult for data center operators who contract server capability out to smaller users, such as with cloud computing, to participate in load flexibility when their contracts require minimum uptimes. Backup generation can provide some curtailment capability, but diesel units can create a flood of noise and air quality complaints when operated for extended or regular periods in populated areas, such as Data Center Alley in Northern Virginia. The optionality and incentives for flexibility should reflect the diversity of data center users, he said.
For most data center developers and operators, the capacity and energy market revenues from DR participation are nice to have, but not a core focus, Tinjum said. If the program could be tied to interconnection timelines, that could provide much more value, he said.
During the OPSI Market Monitoring Advisory Committee meeting Oct. 7, Bowring said data centers should be required to bring their own generation and not be allowed to outbid regular consumers for capacity resources. He said it’s become a regular refrain to say the markets should be allowed to work to bring the generation needed to serve data centers, but some of the outcomes that could produce, such as blackouts or capacity being taken out of the market through bilateral contracts, are not functional solutions.
“The market can’t solve the problem of having 30,000 MW of capacity drop out of the sky,” he said.
Bowring said his statements should not be taken as advocacy for lower prices, but instead as an effort to find ways of applying cost-causation principles to the risks associated with data center load. He said those impacts already are being seen, with an analysis from the Monitor finding that the $175/MW-day price floor implemented in the 2026/27 Base Residual Auction (BRA) — which cleared at the $329/MW-day maximum — would have been relevant if data center load had been removed. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)
David Mills, chair of the PJM Board of Managers, said the RTO is trapped in a “multidimensional Gordian knot” of trying to solve for price and hold reliability constant, while adding 20 to 30 GW of supply to serve data centers and controlling the associated emissions. That also is caught in a political challenge where some of the same voices advocating for lower prices are encouraging the economic development from data center development.
He suggested the impact to residential and commercial ratepayers could be controlled by states implementing bifurcated ratemaking systems.
New Jersey Board of Public Utilities Commissioner Zenon Christodoulou questioned if high energy prices and the rush for generation and interconnection equipment could be crowding out investment in the infrastructure required for electric vehicles, reshoring industry and electrification.
Mills and Bowring both said load growth outside data centers and some heavy industry remains fairly limited and unlikely to outpace the ability for the electric industry to respond without the added pressure from large loads.
“This is an outlier event in the sense that we’ve got all this new load coming in a short period of time, and your question is a valid one because it might eat up that surplus,” Mills said.
Future of the Capacity Market
The impact of large load growth also weighed on a pair of panels focused on speeding pace of new supply and the future of the capacity market.
Denise Foster Cronin, East Kentucky Power Cooperative vice president of federal and RTO regulatory affairs, compared the scale of data centers to adding a new zone to PJM, but without the requirement that a new entity seeking to join PJM demonstrate that it can procure the capacity it needs. She said LSEs should be active servers of their load and capacity auctions should return to their residual nature.
PJM Vice President of Market Design and Economics Adam Keech said the reliability backstop procedures may be worth revisiting. He said the trigger for the backstop — three consecutive BRAs that clear short of the reliability requirement — was designed at a time when the scale of load growth and reliability degradation was not envisioned. The backstop allows PJM to conduct a procurement process for transmission and generation owners to submit solutions to the reliability issue, including new generation to receive a multiyear commitment.
PJM Executive Vice President of Operations, Planning and Security Aftab Khan said the RTO is on pace to complete its transition to a cluster-based interconnection study process in April 2026, clearing tens of gigawatts worth of projects to proceed to development. There has been a slowdown in the pace of new generation coming online, with developers reporting issues around financing, permitting, siting and policy changes.
The majority of the resources in the queue and with interconnection service agreements that have not yet entered service are solar, which does not carry a high effective load-carrying capability rating. He said the RTO has major concerns if that is the only resource type coming online over the next few years.
“It’s important for PJM that we have the right generation portfolio mix,” he said.
