American Electric Power told analysts during its quarterly earnings call that load growth, driven by commercial customers in its service territory, presents opportunities to invest in “critically needed” infrastructure.
CEO Bill Fehrman said during the May 6 call that commercial load increased 12.3% in the first quarter compared with the same period a year ago. The company has forecast “historic” total retail load growth of 8 to 9% over the next three years, driven by large-load demand in Indiana, Ohio, Oklahoma and Texas.
“This growth is not a show-me story. It is happening,” he said. “As we look ahead, AEP is extremely well-positioned to participate in future growth across our footprint … to support increasing electric demand.”
AEP’s capital plan includes customer commitments for over 20 GW of incremental load by 2030 because of data center demand, reshoring, manufacturing and continued economic development. Fehrman said the company’s investment in its 40,000-mile transmission system, which includes the nation’s largest network of 765- and 345-kV lines, has been a driver behind the growth.
“These ultra high-voltage lines position us exceedingly well in attracting hyperscalers [large data centers] to our system. We need consistent, large-load power,” he said. “New infrastructure will allow us to handle this increased demand.”
AEP said it has secured funding this year through two separate transactions that complete its expected equity needs for its five-year, $54 billion capital growth plan. The company said it could invest an additional $10 billion over the next five years.
Fehrman said the company has determined the capital plan has about 0.3% direct tariff exposure.
The Columbus, Ohio-based company reported first-quarter earnings of $800 million ($1.50/share), compared with just over $1 billion ($1.91/share) from the same period in 2024. It also reaffirmed its operating earnings guidance of $5.75-$5.95/share and maintained its long-term growth rate target of 6 to 8%.
AEP’s share price closed May 7 at $107.48, up four cents since the earnings release.
The NYISO Market Monitoring Unit on May 5 told stakeholders it is independently analyzing the capacity market in parallel with the ISO’s ongoing Capacity Market Structure Review project.
“We want to help with a bit of quantitative modeling to help reason through some of the alternative structure proposals that have come out as part of this process,” said Joe Coscia of Potomac Economics. He said that his presentation to the Installed Capacity Working Group was intended to show his thinking and get feedback on possibilities. “We’ll follow up with a future presentation of results, so no numbers today.”
Coscia said the MMU is attempting to address the specific concerns of stakeholders with the current market. The analysis will address several questions:
Is there still value in a market designed to attract new entry in an environment where new generation development is driven by state contracts?
Do uniform net cost of new entry (CONE) demand curves result in “excessive rents” to existing resources?
Do bifurcated or “retention-driven” capacity markets improve efficiency or reduce costs?
Coscia said the study includes looking at the implications of using marginal capacity accreditation factors (CAFs) rather than average CAFs. This involves studying the calculation of effective load-carrying capacity for resources on the grid. Currently NYISO uses marginal CAFs, which can diminish the value of energy storage as more storage enters the market, according to a Brattle Group analysis.
Stakeholders asked whether the MMU’s analysis would try to account for state reimbursement programs for renewable energy. Coscia said the study will include an assumption that a portion of renewable energy entry into the market would not be driven by capacity prices.
Coscia gave a brief rundown of the MMU’s assumptions:
state-contracted renewables could meet 70% of load by 2033 and 100% of load by 2040;
6 GW of battery storage and 9 GW of offshore wind would be satisfied by state contracts;
load growth based on the 2025 Gold Book’s forecasts; and
imperfect market participant foresight in investment and retirement decisions.
These assumptions would underlie different market designs, which would be tested under different “technology scenarios” (i.e., all fossil units retired by 2040, dispatchable renewable energy peakers available, etc.). The goal is to examine how alternative market designs might perform under different future economic and technological conditions, Coscia said.
“What we’re interested in doing is trying to simulate out the implications of what could happen if changes are made to the way that prices and settlements are being determined,” Coscia said. “We have no ability to predict the future about all these market conditions that could be taking place.”
He said this would be a helpful tool for looking at the tradeoffs and benefits of different market structures under different conditions.
Stakeholders also asked whether there would be sensitivities included in the analysis. Coscia said the MMU intended to look at different variations within the assumptions.
NYISO Presents Results of Transmission Congestion Contract Survey
NYISO conducted a poll of current transmission congestion contract market participants to see what the demand for TCCs of various durations in future auctions might be, as well as their preferred structure for this fall’s centralized auction.
Ten market participants responded to the survey. On average, they wanted roughly 22% of system capacity to be available at a one-year duration. The desired capacity for a six-month duration was roughly 44%. Multiple market participants said that they wanted a percentage of the available system capacity to be reserved from the centralized TCC auctions for release in the “balance of period” auctions.
In response to the survey, NYISO proposed an eight-round auction structure. The ISO would offer 20% of system capacity as one-year TCCs across three rounds and 45% of system capacity as six-month TCCs across four rounds. Both of these would be effective Nov 1.
Effective May 1, 2026, NYISO proposes 5% of system capacity be available as one-year TCCs in one auction round. The remaining 35% of the system capacity for the winter 2025/26 capability period was already sold in 2024.
Market participants and transmission owners are encouraged to provide feedback to the ISO.
After a hiatus on gas-electric coordination discussions, MISO’s Advisory Committee touched on lingering frustrations in 2025 and potential solutions.
This time, MISO members pointed out that new electric storage could mitigate risk at times when high demand causes the natural gas supply to falter. The Advisory Committee’s roundtable May 7 was one of its periodic “current issues” discussions, with more topics planned in June.
John Wolfram, representing MISO transmission owners, said he expected it would continue to be a challenge to supply gas plants in high demand using a pipeline system that was designed to support heating only. Wolfram said TOs would like to see 24/7 gas operations, especially since scarcity occurs in extreme weather that strikes indiscriminately.
“It always seems like these emergencies occur on a four-day holiday weekend,” Wolfram said.
The Union of Concerned Scientists’ Sam Gomberg said battery storage waiting to interconnect in MISO’s queue could help it navigate gas shortfalls during punishing weather. The queue contains about 60 GW of energy storage.
Gomberg also said more regional and interregional transmission lines could lessen the pressure to perform for MISO’s key natural gas generation and make forced outages during system stress less noticeable.
“These aren’t one-off events anymore,” Gomberg said of extreme weather episodes. “I think MISO should be incorporating these into their long-term planning.”
Xcel Energy’s Susan Rossi, also representing MISO TOs, said a multiday commitment model from MISO could help natural gas resources better prepare.
MISO in 2024 said it wouldn’t entertain a member request to create a multiday fuel purchase requirement for market participants during extreme cold weather. However, the RTO said it likely would create a financial guarantee by the 2025/26 winter for resources that are committed days in advance and have those commitments canceled by MISO. (See MISO Proposes Alternative to Multiday Gas Purchase Requirements.)
Clean Grid Alliance’s David Sapper said while firm fuel procurements and dual-fuel conversions on plants could alleviate some risk, a “less expensive” option could be better unit commitments from the RTO.
Sapper also said battery storage, which could be charged with natural gas generation ahead of time, could help MISO ride out long, stormy weekends when gas becomes scarce.
Sapper said the lack of weekend service “in times of incredibly high need does not square with competitive markets and outcomes.” He said it remains “puzzling” to him that gas trading shuts down without regard to need.
Committee members agreed MISO has been handling fierce winter conditions better than ever. (See MISO: Better Preparations Clinched Winter Storm Operations.) However, some said it’s difficult to separate how much of the improved operations are due to MISO’s better forecasting and data or improved gas-electric coordination.
More Topics in June
The Advisory Committee will discuss emergency preparedness and power restoration procedures when it meets in June with the MISO Board of Directors in the audience.
Clean Grid Alliance’s Beth Soholt asked that MISO sectors be allowed more input when selecting topics to discuss in front of the board rather than its C-suite determining themes.
Advisory Committee Chair and Indiana regulator Sarah Freeman agreed there’s still “a degree of opacity” in how MISO leadership chooses the subject matter for Advisory Committee sessions during quarterly Board Week meetups.
For its separate, “current issue” discussion format in June that is not held in front of MISO board members and handpicked by the committee itself, the Advisory Committee decided to discuss MISO’s most recent capacity auction and how the new sloped demand curve influenced results. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)
The committee maintains an ongoing list of future topics. Potential upcoming discussions could feature a possible minimum transfer capability between RTOs and how to best prevent future episodes of market manipulation à la Ketchup Caddy. (See In a Pickle: FERC Issues $27M in Fines over Ketchup Caddy DR Deceit.)
VIRGINIA BEACH, Va. — The sudden halt of the offshore wind sector has left states holding high-investment wind ports that won’t be needed for a while, raising questions about how states can use the pricey assets without hampering future OSW needs.
That approach, while understandable to try to recoup on the investment, could leave OSW developers high and dry if the industry rebounds, said speakers at the International Partnering Forum (IPF), which ran from April 28 to May 1.
“It scares us,” Brendan Crowe, port procurement manager for developer Invenergy, said in a panel called “Preserving Offshore Wind Port Development Momentum Amid Market Uncertainty.”
“We completely understand that that port is sitting fallow right now,” said Crowe, whose employer is developing OSW projects in New Jersey, New York and California. “We do understand that it needs to be a revenue-generating asset, and the state needs to start paying back the taxpayers for their investments.”
But, at the same time, “We don’t want that port to go to another alternative and we are not … able to claw back that use for our projects. Hopefully those alternative uses are short term prior to our project construction periods.”
Crowe urged states to stay the course.
“If the states are serious about their offshore wind goals, to put it frankly, they’ve got to put their money where their mouth is,” he said. “These port facilities are the industry enablers, and we’re not going to be able to construct anything without these ports. I always say ports are one of the first dominoes that needs to fall.”
Thinking Long Term
The panel was part of an ongoing discussion at the conference about the uncertain future. The sector requires massive investments and a complex, interlocking system of permitting, financing, supply chain and assembly elements. Planning is tough when the future is unclear.
Even before President Trump’s decisions to temporarily freeze all OSW projects in the permitting process, and to halt New York’s Empire Wind project mid-construction, the sector suffered a series of abandoned projects due to supply chain and financing problems, and rising costs.
That raised questions about the level of risk taken to support logistics and supply chain projects, and what’s the price — and reason — for taking it on.
Bon-Kyu Koo, CEO of cable manufacturer LS Cable & System, gave a decisively positive answer to a question by moderator Liz Burdock, CEO of Oceantic Network, the conference organizer, as to how he weighed the risks against the market opportunities in the United States.
The previous day, the manufacturer broke ground on a $700 million, 750,000-square-foot subsea cable factory in Chesapeake, Va., in a ceremony attended by Gov. Glenn Youngkin (R). The plans include a vertical vulcanization tower and a dedicated pier.
“The most important thing for all of us here in the offshore wind industry is if you look at this as a timeline of only one, two, three, four, five years, it’s difficult to make a decision,” Bon-Kyu Koo told Burdock. “But what we did is, we’re looking at this as an industry that will last over 20, to 30, to 40 years.
“Of course we’re going to have our ups and downs. But if you look at the long-term curve, this will be a curve that will be now going up.”
Port Capacity Shortfall
For stakeholders involved in building or using a port, the question is how to weather the near-term turbulence, said Jonathan Kennedy, chief development officer for port developer Clean Energy Terminals, who moderated the panel and was heavily involved in developing New Jersey’s port.
The OSW sector has achieved much in the past five years, developing the N.Y. and N.J. ports, as well as building ports in New Bedford, Mass., Tisbury, Mass., Providence, R.I., and New London, Conn., he said. The challenge stems from the large scale of the projects and the need to build them well in advance of when they’re needed to handle turbine materials and preparation, he said.
“We all know the U.S. lacks the port capacity it needs to achieve long term offshore wind targets,” he said. “Given the current market uncertainty, how do we preserve that momentum so that we can be port-ready when that offshore wind pendulum swings back — and it will swing back.”
John Schneidawin, director of strategic initiatives for the Port of Albany, said the agency recently put out a request for “expressions of interest” for alternative uses of the port, given the dramatic slowdown in offshore wind business. (See Fate of Wind Tower Manufacturing Site in Albany Uncertain.)
The port, located 126 miles from New York up the Hudson River, has 85 acres and will be shovel ready in two years, he said. The initial goal was to use it for a Tier 1 tower manufacturing site, taking advantage of the cheaper costs of doing business in Upstate New York while moving materials, equipment and finished towers down the Hudson River to the South Brooklyn Marine Terminal, he said.
“We’re trying to identify, do we subdivide those 85 acres,” said Schneidawin, who attended the ports panel but was not a panelist. “Do we maybe leave half of it kind of dedicated toward the needs of the industry now in offshore wind, whether that’s just storage and assembly and marshaling? Or maybe go with a different use for the other set of the acres.”
Future Income Uncertain
Suzanne Plezia, senior director/chief harbor engineer for the Port of Long Beach, said the port is confident the project on 400 acres to assemble floating wind turbines will not go to waste, based on the experience of the main port. The Port of Long Beach, which handles imports and exports in shipping containers, is the busiest in the U.S.
“From a near term, (for) all of our infrastructure, we have to think 20, 30 years down the road. So we do cargo forecasts. That’s how we look at, ‘Do we need to expand our infrastructure?’” she said. “It’s a similar approach here with pure wind. We believe in the long-term horizon and the need for offshore wind. And you know, whatever happens in the next four years will sort of be a blip on that horizon.”
The port also is protected by the heavy demand for land in the port area for non-wind uses, she said.
“From a risk profile, we know that should offshore wind not move forward, there will absolutely be a demand for that land,” she said. Still, she added, the nature of offshore wind makes it tough to get private investors interested in the wind port compared to backing cargo ports, for which the future cargo flow and income is more predictable.
“When it comes to pure wind, we need that same environment where there’s predictability on that source of revenue,” she said, and cited the typical “offtake” or contract for output delivered in the future. “The offshore wind model in particular is very challenging in that regard because offshore wind offtake happens in the future in increments over time. And that is really a core foundation for investors: Is that revenue secure?”
“So you have to think about, ‘How do we move forward during this period of time so that when (the developer) is ready my infrastructure is ready?’” she said. “And that risk is really high right now.”
Maturation Period
Crowe, of Invenergy, said the industry needs to draw on its OSW solicitation experience to create “offtake mechanisms,” that “share and mitigate that risk between developers and the ratepayers.”
“We are still in the early stages of this industry,” he said. “We have to allow the industry to mature before we start tacking on these kind of supply chain development targets on these early projects, and allow the industry to mature and bring those manufacturing (elements) domestic over time.”
Crowe agreed with the suggestion from audience member Molly Croll, director of Pacific Coast Offshore wind for the American Clean Power Association, that the current enforced pause may help the OSW sector by giving more time to develop the supply chain and decide which equipment is needed so ports can design around that plan.
Invenergy, which expects to use the Port of Long Beach to develop its floating foundation types, is “continuing to select what that component of foundation is going to look like, and that is really going to help (the port) build a more efficient, effective port for our use,” Crowe said.
“The challenge,” he said, “is I’m not the only customer,” and other developers will be placing their own demands too.
Ørsted is pushing ahead with two U.S. offshore wind projects amid potential policy threats but halting development of a much larger U.K. proposal due to rising costs.
The Danish renewable energy developer shared the news May 7 with the release of its latest financials. The company has struggled amid global headwinds facing renewables but managed to post higher first-quarter earnings in 2025 than in the same period of 2024.
Ørsted does expect halting the Hornsea 4 project to have a potential negative impact of as much as $530 million (U.S.) in the second quarter, however. And it projects a roughly $180 million impact on its Revolution Wind and Sunrise Wind projects due to new U.S. tariffs on steel and aluminum. Additional U.S. tariff impacts are possible but not expected to be as large.
Ørsted, which claims the title of largest offshore wind developer by capacity, surpassed 10 GW of installed offshore generation and reached 99% renewable generation in the first quarter of 2025.
During a conference call with financial analysts, CEO Rasmus Errboe reaffirmed the company’s commitment to offshore wind, saying “despite the significant challenges across certain geographies, the long-term fundamentals for offshore wind are strong.”
But the headwinds that emerged in the early 2020s still exist and led Ørsted to tighten its investment decision making process earlier this year.
Ørsted has suffered heavy losses on its investments in the struggling U.S. market, and the first question in the Q&A portion of the call honed right in on the latest threat: President Donald Trump.
How will Revolution and Sunrise be able to avoid stop-work orders like the one federal regulators in April slapped on Empire Wind 1, a New York project under construction by fellow Scandinavian developer Equinor?
Errboe said he would not speculate on the U.S. regulatory process.
The same analyst asked if Ørsted has discussed this risk with the Department of the Interior or its Bureau of Ocean Energy Management.
Ørsted always maintains an ongoing dialogue with regulators about its projects, Errboe said, but he described the current conversations only as “constructive.”
He told another analyst the company remains 100% committed to finishing both projects.
Revolution is far along in its offshore construction, with 100% of the export cable, 80% of monopiles and 50% of turbines installed. The delaying factor that has emerged is construction of the onshore substation. Revolution is not expected to reach commercial operation until the second half of 2026.
Offshore work began earlier this work on Sunrise, which is targeted for commercial operation in the second half of 2027.
Revolution will feed 704 MW into Connecticut and Rhode Island. Sunrise has a 924-MW offtake contract with New York.
Unlike some recent earnings calls, however, the U.S. market was not the main topic of discussion on May 7.
The decision to shelve Hornsea 4 — which at 2.4 GW would be one of the largest offshore wind arrays — overshadowed the other developments.
Errboe said increases in interest rates and supply chain costs as well as other adverse developments have raised risks and decreased anticipated rate of return well below the more-stringent thresholds for investment the company announced earlier this year.
Ørsted already has commissioned Hornsea 1 and 2 and now is building Hornsea 3. The problem that arose with Hornsea 4 is that cost factors changed after it was awarded its Contract for Difference — a mechanism by which the U.K. government subsidizes low-carbon generation.
A similar fate befell most early projects advanced by Ørsted and other developers off the Northeast U.S. coast, which locked in compensation long before costs.
Multiple contracts subsequently were canceled, and multiple proposed offshore wind projects were put on hiatus. Ørsted so far is the only developer to fully cancel a project — Ocean Wind 1 and 2, off the New Jersey coast.
Ironically, one of the ways Ørsted was going to reduce the financial blow of canceling Ocean Wind 1 was to use the export cables procured for that project instead on Hornsea 4.
Errboe emphasized that while the execution plan for Hornsea 4 is discarded, the concept of the wind farm itself is not.
The pause comes early enough that the financial impact is not as bad as it could be, he said, adding: “Also worth noting that we still have the lease rights, we still have the development consent order, we still have the grid connection agreement, and we will now work toward bringing the project forward again in a new configuration. We basically take it back to development, if you will.”
Ørsted reported a first-quarter 2025 EBITDA 18.7% higher than in the same period of 2024. Offshore wind earnings were 10% higher year over year, with weaker 2025 wind speeds offset by increased capacity and availability of generation.
Constellation Energy said it is closing in on new power purchase agreements and is in a good position to help serve projected data center load — whether in front of the meter or behind.
During the company’s first-quarter earnings call with financial analysts on May 6, CEO Joe Dominguez also gave optimistic updates on its acquisition of natural gas generation company Calpine and its planned restart of the former Three Mile Island nuclear plant.
Data centers were a recurring focus of the presentation, however, and Dominguez said Constellation feels the sky-high projections of the power demands posed by the artificial intelligence revolution are exaggerated — in some cases by stakeholders trying to build a business case for new wires or generation.
“I think the load is being overstated. We need to pump the brakes here,” he said.
He cited as an example projections by ERCOT, MISO and PJM of a combined 140 GW of new large-load demand by 2030 and contrasted that with forecasts by third-party analysts that average out to only 74 GW of new data center demand in that period in the entire country.
“Large-load demand” is more than just data centers, but a significant portion of those new large loads are expected to be data centers.
The problem is a familiar one: developers shopping around in multiple locations with a single early-stage plan that may not even get built but which gets added to the tally of potential growth in each jurisdiction.
“We know from conversations from our customers and the end users that the same data center need is being considered in multiple jurisdictions across the United States at the same time,” Dominguez said.
He added that renewable energy developers do the same thing, cramming interconnection queues with projects that have only a fractional likelihood of ever being built.
“It’s hard not to conclude that the headlines are inflated,” Dominguez said. “In fact, we’ve done the math, and if Nvidia were able to double its output and every single chip went to ERCOT, it still wouldn’t be enough chips to support some of the load forecasts. In ERCOT, there’s been a history of over-forecasting.”
A recent RMI analysis based on FERC data concluded that over the past decade, utilities’ long-term demand forecasts were 23% higher than what actually came to pass, he added.
But Constellation does expect load growth and for that growth to present the company with a strong market position. It hopes to absorb Calpine’s fleet and finish the year with more than 50 GW of operating generation in place; the cost and time frame to build a comparable new fleet would be daunting.
Constellation’s Wolf Hollow and Colorado Bend combined cycle gas turbine plants, for example, would cost about 300% more today than they did when built less than a decade ago.
Crane Clean Energy Center — Unit 1 of the former Three Mile Island — is aiming for a 2028 restart. It was among the 51 projects PJM selected for expedited interconnection studies; more than half of the 600 employees needed to run the plant have been hired; the first reactor operator class is underway; and the second operator class is on deck for this autumn.
In late April, Constellation answered FERC’s deficiency letter on its proposed acquisition of Calpine, and the company expects the deal to be approved and to close later this year. For its $29 billion outlay, Constellation will gain generation capacity that would cost $65 billion to build new.
“The short story here is that we’re seeing a very, very favorable environment,” Dominguez said. “We believe our offerings for clean and reliable generation are far more attractive from a time and pricing standpoint than any competing option, whether that’s used to support on grid data center development or behind the meter development.”
Possible headwinds facing Constellation include tariffs, a recession and hotly debated regulations on generation being co-located with load.
Past recessions historically resulted in a 1 to 4% decrease in demand, with weather patterns complicating any attempt to generalize the relationship between the economy and demand. This time around, the demand growth that is occurring would offset a temporary economic slowdown, Dominguez said. Also, the production tax credit for Constellation’s nuclear fleet gives the company downside protection from falling power prices during a recession.
The final shape of tariffs remains to be seen, Dominguez said, but Constellation’s preliminary estimate is for a 1 to 2% impact on 2025/26 capital expenditures, excluding fuel, but a negligible impact on operations and maintenance.
The outcome of the co-location debate is not clear, Dominguez said, and the industry desperately needs clarity. One byproduct of the controversy, he added, is that utilities have sped up the interconnection process. He applauded them for that and urged FERC to allow for some latitude in its rulemaking.
“It’s important that FERC not constrain innovation for co-generation and co-location,” he said.
Constellation reported unadjusted GAAP income of $118 million ($0.38/share) in the first quarter of 2025, down from $883 million ($2.78/share) in the same period in 2024.
It reported adjusted non-GAAP earnings of $673 million ($2.14/share) in the first quarter of 2025, up from $579 million ($1.82/share) in the same period in 2024.
The company’s stock price soared May 6 after the release of the financials, closing 10.3% higher as the three major U.S. stock market indexes all closed lower.
California’s electricity grid is expected to meet peak demand this summer, with state energy officials pointing to the massive growth in solar and battery storage resources as key.
A surplus of at least 5,500 MW is projected to be available to California during peak demand under normal conditions and 1,368 MW under extreme conditions, according to a May 1 reliability report by the California Energy Commission, the California Public Utilities Commission (CPUC) and the California Air Resources Board.
As of April, more than 12,000 MW of battery storage capacity is online and serving the grid, with almost all the capacity becoming available in the past four years, CPUC staff member Christina Pelliccio said at a May 2 joint agency reliability meeting. By 2028, another 15,000 MW of storage resources are expected to be available, accounting for the majority of the 20,000 MW of new resources expected in that time.
“CAISO will be able to rely on the large amounts of storage, solar and hybrid projects that are under development and projected to be online by August 2026,” CPUC Senior Analyst Behdad Kiani said at the meeting.
However, storage resources are the energy technology most affected by Trump administration tariff changes, BloombergNEF Senior Policy Associate Derrick Flakoll said. Assuming a 54% import tariff on China, battery storage additions in the U.S. in 2026 are expected to decrease from a forecasted 15 GW to about 10 GW. BloombergNEF projects the cost for a four-hour battery energy storage system will increase from about $200/kWh to about $260/kWh in 2026 due to the 54% import tariff.
Even so, battery storage project developers have not cited increased tariffs as an issue yet, said Rohimah Moly, deputy director of energy and climate at the California Governor’s Office of Business and Economic Development.
“But we have asked developers how the proposed tariffs will impact their projects,” Moly said. “A lot of the developers … are doing some behind the envelope calculations and will come back with us with some more information.”
Batteries and other power equipment also are expected to see supply chain issues, Branden Sudduth, vice president of reliability planning and performance analysisat WECC, said at the meeting. The costs and lead times of transformers and switchgears continue to increase, and more than half of balancing authorities in the WECC region have said they’re concerned about procurement delays for these pieces of critical equipment.
In the immediate future, between 2,100 MW and 5,800 MW of new resources will be coming online by September, the vast majority of which are battery storage and solar projects, the report says. Most battery storage energy will dispense between 7 p.m. and 8 p.m.
Although California is set to meet demand this summer under normal conditions, in a worst-case scenario, the state could need to tap into more than 2,600 MW of contingency resources, according to the report. For example, wildfires outside the state could reduce import capacity by as much as 4,000 MW, the report says.
“We have moderate to severe drought conditions this year,” Jeff Fuentes, assistant chief at the California Department of Forestry and Fire Protection, said at the meeting. “In the Pacific Northwest, we have abnormally dry conditions … we also have an early spring, which causes a longer growing season.”
In Southern California, several “pulses of moisture in February and March coupled with the recent rain this week is allowing green-up to continue,” Fuentes added. This also has resulted in an increased yield of the grass crop and fine fuels, while drier conditions become more likely in the summer, he said.
Additionally, there is potential for above-normal temperatures in August and September, primarily for the West, said Amber Motley, CAISO director of forecasting. The first half of summer could include above-normal temperatures that most likely wouldoccur in the northern and central portions of the West. There is a slightly lower chance of above-normal temperatures in coastal locations, she said.
Stakeholders asked FERC to force MISO to cut or dilute some of the harsher requirements of its proposed demand response participation and accreditation package of revisions.
MISO in March proposed an overhaul of its capacity accreditation methods for load-modifying resources (LMRs) and DR that would be based on whether they can help during system risk (ER25-1886). (See MISO Approaching LMR/DR Accreditation Based on Availability.)
Comments on the proposal arrived May 5, with a majority asking FERC to give demand resources more slack in accreditation reductions, response time thresholds or exemptions for outages. Multiple stakeholders also told FERC the plan would create an inconsistency between DR accreditation and how MISO’s load-serving entities prepare for peak demand.
The grid operator proposed to accredit LMRs, emergency DR and behind-the-meter generation depending on their offers during both low-margin and risky hours, when a capacity advisory, maximum generation alert or warning, or energy emergency is in place. MISO has reasoned that those hours best indicate when it is likely to need demand curtailments.
The RTO plans to split its LMR category into rapid responders with greater responsibility and slower DR with more relaxed expectations and smaller capacity values by the 2028/29 planning year. (See MISO Closing in on New LMR Accreditation.) More agile LMRs would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency Step 2 events. Slower LMRs would have a maximum six-hour response time and would be called up earlier during maximum generation warnings.
The plan would be uncompromising: MISO would ascribe accreditation values of zero for the entirety of an emergency or near-emergency event when resources fail to contribute anything for even one hour.
MISO plans to rely on the past year to get an idea of resource availability for accreditation. That’s in contrast to other capacity resources that rely on average availability over the past three years. Staff have said the accreditation is designed to be unforgiving because the RTO expects LMRs and emergency-designated DR to be available during emergencies that usually crop up after years of downtime for the resources.
The RTO would require DR and LMRs to designate a response time when registering their assets. It plans to deduct accredited values when resources report inaccurate availability.
The new accreditation would affect MISO’s approximately 12 GW of demand-side capacity resources, or about 10% of its 122-GW 2024 summertime peak load.
Under the current framework, demand resources receive a 100% accreditation of their reported capacity rating. The RTO said recent data from its demand-side resource interface show that about 2 GW of DR is accredited but never is designated as available or self-scheduled in its system.
Concerns over Declining DR, and a Clash with MISO’s RA M.O.
The Organization of MISO States said while it believed the RTO’s filing was acceptable overall, it harbored concerns about the new accreditation method making DR participation less attractive, the complexity of the proposal and a budding discrepancy between how the RTO sets margin requirements for utilities compared to how it accredits their DR.
Most OMS regulators agreed MISO “streamlined and simplified” DR participation and accreditation, “although the process is still complex.” The organization said it appreciated the RTO had to react to system risk shifting away from the usual planning around a summer peak and said it was correct to try to ensure LMRs are available when called up while cutting down on gaming opportunities and being able to access DR outside of emergency procedures.
However, OMS said it “remains concerned about the impact of the new accreditation approach on the amount of DR resources available for emergencies.” It said the new structure “may make running DR programs for load-serving entities more burdensome, more costly and more difficult to explain to participating customers, making operating such programs ultimately less attractive.” It warned MISO against “over-solving” a problem. It also said the RTO’s “all-or-nothing” approach pressures resource owners to respond to every call or risk accreditation values.
Finally, OMS noted that MISO left a mismatch between its DR accreditation and the amount of planning reserve margin responsibilities it puts on its LSEs. It said that while margin requirements still are set by utilities’ energy consumption on the peak hour, LMR accreditations would move to an availability model during risky hours that likely won’t line up with coincident peaks.
OMS urged MISO to set new reserve margin obligations as soon as possible to minimize confusion.
The Illinois Municipal Electric Agency seconded the need for MISO to iron out LMR accreditation in relation to how it sets LSEs’ reserve requirements. It said the current accreditation raises doubt over how LSEs will use their LMRs to meet upcoming peak demand responsibilities. The agency also said the RTO should cut its expectation of demand reductions to within 30 minutes or less to 90 minutes or more. It asked FERC to issue MISO a deficiency letter until it resolves both issues.
Minnesota Power said many of its 300 MW of demand resources have vowed to stop participating in MISO if the new accreditation and stricter testing is enforced.
“Through these reforms, MISO is requiring demand response customers to choose between being called upon far more frequently than they currently are or being called upon in a time frame that they cannot safely or commercially respond within,” the Duluth-based company said. It predicted the plan would “erode the value proposition” of industry to sign on for demand reductions, thereby driving up rates.
Minnesota Power also agreed MISO should have worked out a companion proposal on its reserve margin assignments before introducing a proposal that is incompatible with how its other procedures define resource adequacy.
Advanced Energy United echoed concerns that the more unforgiving accreditation could block some resources from participating and could lower accreditation too much when resources take necessary outages. The trade association added that MISO was being too strict by using just the past year instead of an average of the past three years to calculate availability; by categorizing partial failures to reduce usage as total failures; and by requiring hourly meter data on demand resources and five-minute meter data during calls for faster demand resources that can respond in less than an hour.
A group of municipal utilities — Michigan Public Power Agency (MPPA), Lansing Board of Water & Light, Central Minnesota Municipal Power Agency, Northwestern Wisconsin Electric Co. and Upper Midwest Municipal Energy Group — took issue with MISO’s proposal lumping dispatchable behind-the-meter generation in with DR and subjecting it to a harsher accreditation than other thermal generators, which use three-year averages to measure availability. They said the RTO would unfairly slash accreditation for a behind-the-meter generator if risky hours or an emergency event unfolds during a planned outage.
At MISO Board Week in March, MPPA’s Tom Weeks said the RTO’s accreditation would discriminate against dispatchable, behind-the-meter thermal generation that is built because of the difficulties with getting interconnected to the grid. Weeks said multiple municipalities rely on such generation.
“I guess if I were to use a phrase to convey my concerns, it would be, ‘throwing the baby out with the bathwater,’” Weeks said.
However, the Coalition of Midwest Power Producers (COMPP) said more nuanced participation and a stricter accreditation for DR are necessary considering MISO will rely on DR more as the fleet evolves and reliability risk enters high season. It said the RTO took a step toward making sure its DR fleet is “prepared and capable of performing as expected and needed during periods of system stress” and is paid commensurate with the value it provides the system.
COMPP also said MISO’s stepped-up testing will help cut down on market participants collecting payment for phantom load reductions, citing recent instances that include dummy company Ketchup Caddy and aggregator Voltus. (See Voltus Agrees to $18M Fine to Settle DR Tariff Violations in MISO.)
“The current capacity construct for demand resources at MISO has been built by piecing together disparate retail programs from the various MISO member states. However, this fragmented and ad hoc approach is no longer sufficient for MISO to meet the rapidly evolving demands of the grid,” the coalition said.
Voltus itself protested the filing over what it called an overlooked provision: MISO would cease allowing DR aggregations to cut use down to a predetermined baseline and instead require specific megawatt reductions.
“Many demand response resources, from the largest industrial loads to small commercial manufacturers, respond to deployments by turning off all loads except for non-curtailable baseload,” Voltus argued.
The aggregation company said instead of a drastic accreditation, MISO could be better served by launching an availability requirement for DR where assets must show they dropped use near or to accredited values or risk replacing their capacity or buying out their shortfalls at the latest capacity auction clearing prices.
A second group of utilities clustered around the Great Lakes also maintained it wasn’t fair that MISO would never allow behind-the-meter generation a planned outage without it risking its accreditation value. It also asked FERC to allow demand resources three years of average availability for accreditation purposes like other generators.
Entergy also said demand-side resources should be afforded an average of three years of past performance for a larger sample size for accreditation. The corporation seconded requests for exempted planned outages for behind-the-meter generation and to allow aggregations to dip to a firm service level instead of reducing by a megawatt amount.
VIRGINIA BEACH, Va. — Offshore wind advocates are closely monitoring and vigorously lobbying Congress to assess and shape potential changes to the Inflation Reduction Act and its budget, speakers said at the International Partnering Forum 2025.
Key among the issues outlined at the IPF — which ran from April 28 to May 1 — is the fate of investment tax credits, as Congress seeks to pass a budget that will extend President Donald Trump’s 2017 tax cuts, speakers said.
Trump’s dislike of offshore wind has resulted in a freeze in permitting of projects and a halt placed on the Empire Wind project in New York mid-construction. Those actions suggest an uncertain fate for the IRA. But many benefits from the act have gone to Republican states, and wind advocates hope to sway legislators in key districts to keep the credits in the president’s proposed $4.5 trillion budget.
“It’s fair to say that defense of the tax credits is the first, second and third priority for ACP federal affairs team,” said Anne Reynolds, vice president of offshore wind for the American Clean Power Association (ACP), in an April 29 panel.
On the same panel was Shawn Daray, a tax attorney for Jones Walker, who specializes in renewable energy tax credits. He said one of Trump’s first executive orders — known as Unleashing American Energy — “is attempting to pause the disbursement of funds for the Inflation Reduction Act, that includes grants, loans, contracts and any other financial disbursements,” by declaring a national emergency.
“It’s important for all of us to just keep a close eye on the inner workings of Congress and see what comes out of these coming months,” he said.
Driving Economic Development
The IRA discussion emerged from a conference focused on efforts to reenergize the OSW sector amid a host of economic and political challenges. (See IPF25 Attendees Plan Future OSW Resurgence.)
The energy investment tax credit can be used to pay 6% of the cost of a project starting construction before Jan. 1, 2026, rising to 30% if the project pays prevailing wage levels and meets apprenticeship requirements. A project can earn another credit of 10% if it meets requirements for domestic content, such as the iron and steel used and certain other components. Domestic manufacturers of wind components — such as blades, nacelles, towers, and offshore wind platforms — can get a 10% tax credit.
In recent weeks, 21 Republican Congressmen signed a letter supporting the tax credits. Four senators have publicly expressed support too, speakers at the conference said. OSW advocates are working hard to solidify that support and make sure it is reflected in the budget talks.
“Our message in Congress is that these tax credits are driving economic development, job creation and increases in household incomes all across the country,” said Reynolds, whose organization represents wind, solar, storage and other clean energy companies. “They’re doing that disproportionately in Republican states and Republican districts, and they’re doing it in a way that will address the surging demand for electricity across the country. So that’s the message that we’re trying to say six different ways.”
ACP’s campaign includes “television ads and online ads and events in strategically selected congressional districts across the country,” she said. “It includes grassroots activation, patch calls, email alerts, text alerts, and it includes direct meetings with Congress,” Reynolds said. On April 30, ACP organized 400 people to conduct congressional visits, including “front line workers, so real people whose jobs are depending on these tax credits continuing” could present their position, she said.
The challenge is to try to make sure the Republicans expressing support for the credits maintain that view through budget negotiations, said Catherine Belmán Goggins, the policy director of Turn Forward, a nonprofit organization that supports OSW. She said the first deadlines for passage, Memorial Day and then July 4, may change again.
“Time is of the essence,” she told the audience of about 100 people. She urged them to stress not only the local benefits of offshore wind but “the broader priorities” held by federal legislators, such as “domestic energy security, energy resilience, domestic manufacturing.”
“These are common interests across both sides of the aisle,” she said.
Persuading Opponents
That strategy of looking for common ground with opponents is key, said speakers at a panel called “Bridging the Divide: Engaging Republican Lawmakers on Offshore Wind and Renewable Energy.”
In general, OSW has strong support, said Hillary Bright, executive director of Turn Forward. Surveys conducted by the organization show that 73% of voters overall approve incorporating renewable energy into the state’s mix, including 53% of Republicans and 90% of Democrats, she said.
Those figures rise when the people surveyed are told “offshore wind can support good paying jobs, but don’t all require four-year degrees” and when the survey takes place in states like Texas or Virginia, where the benefits of wind energy development are in evidence, she said.
To persuade skeptics, advocates need to talk about OSW “in a more inclusive way that really brings everyone to the table,” she said.
A key strategy is to remove climate change from the discussion, said Jennifer Mundt, assistant secretary of clean energy economic development for the North Carolina Department of Commerce, which helps develop offshore wind energy resources in the state. They don’t mention the “other environmental co-benefits, like improved air quality because we’re replacing fossil fuel generation and all the emissions — we don’t touch any of that,” Mundt said.
But they will emphasize “the opportunities that come with growing, really a nascent industrial supply chain,” she said. “What we found to be the most successful strategy in communication has just really been to depict innovative and sustainable energy solutions like offshore wind as a part of a portfolio, as the drivers of economic growth, as the drivers of good jobs creation, and as the driver of energy security that North Carolina needs.”
Confronting New Regulatory Terrain
For other speakers, the key challenge facing the industry is how to adjust to the fact that “regulatory certainty has been turned on its head,” as Josh Kaplowitz, senior counsel for Troutman Pepper Locke, put it.
The changes triggered by Trump’s executive orders, and their potential impact on OSW projects, the supply chain, states and the industry, have been dramatic, according to speakers on a panel called “Unpacking the New Presidential Directives on Offshore Wind.”
Key among the initiatives highlighted was the Unleashing American Energy order, which declared the nation under an energy emergency and enabled the White House to take action to create more energy. That was followed by a separate — and contrasting — order that effectively froze all OSW federal permitting and leasing pending a review of existing leases, for which no timeline has been set, speakers said.
The administration’s decision to halt New York’s Empire Wind project mid-construction, with all permits in place, was close to unprecedented, said Kaplowitz, who moderated the “Unpacking” panel. The decision, enshrined in a presidential memorandum, did not cite any “particular legal authority” to justify the move, and it potentially could deter investors from backing any major energy project, he said.
“You have a situation where a project that has been fully financed, all the contracts are not just signed, but being executed,” he said. “It does beg the question about what message it sends to any industry, when receiving a final federal permit doesn’t mean anything, because it can be pulled away at any time, literally, including in mid-construction.”
Brian Krevor, senior director for offshore environmental and permitting at ACP, said Empire Wind was one of nine projects in various stages of construction that all had permits.
The Trump administration has set up a “dichotomy” of dramatic contrasts between its treatment of renewable energy projects versus other types of energy, Krevor said. To say that there is a national energy emergency and then exclude renewable energy as a source to meet it “doesn’t quite make sense,” he said. Nor does the fact that the U.S. Department of the Interior on April 23 said it would review non-renewable energy projects in 28 days if they require an environmental impact statement, and 14 days if they simply need an environmental assessment, he said.
“So on one hand, they’re making a critique of reviews that have taken two plus years each for these offshore wind projects, and even longer, to get there and do planning,” he said. “But for all other energy resources, they’re saying 28 days or 14 days is sufficient.”
On the same panel, Janice Schneider, an attorney at Latham & Watkins who specializes in environmental, energy and infrastructure, said she expects the administration’s moves to create “create some market chill.”
“In a perfect world, a lender would prefer to not lend until there are final and non-appealable permits on projects,” she said. The new environment is likely to mean “folks are sort of asking themselves, can we be confident that this shovel-ready project is actually going to be buildable and we get a return on investment?”
PJM has selected 51 projects to receive expedited interconnection studies through its Reliability Resource Initiative (RRI), adding 11,793 MW of nameplate capacity to the next study cycle.
The RTO’s May 2 announcement said 39 of the projects are uprates of existing units, amounting to 2,488 MW, while the bulk of the capacity comes from 12 “new construction” projects, which would bring 9,305 MW to market. That translates to 9,361 MW of unforced capacity (UCAP) split between 2,108 MW of uprates and 7,253 MW of new construction.
The majority of the additional nameplate comes from six new combined cycle gas generators and 20 uprates, which together would provide 7,756 MW if completed. An additional 2,275 MW of battery storage was selected, coming from five new projects. Four uprates to nuclear units would add 496 MW, while one new unit would carry 887 MW.
Thirteen combustion turbine uprates would provide 365 MW, and 14 MW would come from an uprate to a coal generator. One onshore wind project was selected to increase its capacity interconnection rights (CIRs) by about 20 MW.
FERC approved the initiative Feb. 11 to address a potential capacity deficiency PJM has identified in the 2029/30 delivery year. By ranking and selecting RRI applications according to their expected capacity contribution, in-service date and location, PJM argued that the one-time program would allow projects that could bring additional capacity online quickly to be added to Transition Cycle 2 (TC2).
By limiting the number of projects selected to 50, it said there would be no impact to other queue positions in the cycle; ultimately, 94 applications were received, amounting to 26.6 GW of nameplate. The May 2 announcement said 51 were selected due to a tie in the ranking. (See PJM Receives 94 Applications for Expedited Interconnection Process.)
PJM’s announcement said 90% of the selected projects should begin service before 2030 and all should come online by 2031.
‘Thinly Veiled Effort’
Renewable developers and environmental organizations have objected to the RRI, characterizing it as allowing fossil fuel generation to jump a queue made up mostly of wind and solar projects.
“If PJM were serious about addressing reliability concerns, they would be complying with FERC’s order to reform their interconnection process and speeding up their interconnection queue to get projects online that have been waiting for years. Instead, PJM has decided to let gas plants cut in line,” Sierra Club Staff Attorney Megan Wachspress told RTO Insider.
Wachspress called RRI a “thinly veiled effort to move gas plants ahead of renewable resources” and said it is “beyond disappointing that more than 75% of the projects selected are methane gas projects when study after study [has] shown that renewable energy is more reliable, affordable and better for the environment.”
She also said winter storms Elliott and Uri showed that “gas plants underperform when families need electricity the most. Rather than follow FERC’s direction to improve interconnection and transmission, PJM’s short-sighted favoritism will put customers at risk and threaten our environment.”
PJM highlighted several changes it’s making to its interconnection study process, including the cluster-based study process, of which RRI is a part. Since being approved by FERC in 2022, PJM said, the process has completed studies on about 18 GW of projects, and studies on an additional 62 GW should be completed by the end of 2026.
The announcement also notes the commission recently approved changes to PJM’s surplus interconnection service (SIS), which allows expedited studies for new projects sharing a point of interconnection (POI) with an existing or planned resource not fully using its injection capability (ER25-778).
Another proposal before the commission would revise the process for transferring CIRs from a retiring generator to a replacement resource by allowing all resource classes to participate, most notably storage (ER25-1128). (See PJM Stakeholders Approve SIS Manual Language.)
Increased automation of studies could reduce the queue backlog by 60%, PJM said, pointing to a collaboration with Google announced April 10 to use AI tools to streamline the process. (See PJM, Alphabet Partnering on AI Tools to Speed Interconnection.)
In a statement, Constellation Energy said the Crane Clean Energy Center, formerly Three Mile Island, was among the projects selected. The company said the RRI allows high-reliability projects to respond to rising load forecasts fueled by burgeoning AI and manufacturing demand.
“In addition to Crane, PJM selected three Constellation ‘uprate’ projects that will increase output at three other nuclear plants in our fleet, bringing the total increase from the four projects to 1,150 MW of clean, firm electricity. We look forward to bringing these projects online to help support grid reliability and economic development throughout the region,” the statement reads.
American Clean Power focused on the ability of storage developers to quickly install their selected projects, which improve grid reliability and reduce costs, ACP spokesperson Phil Sgro said in an email.
“The representation of energy storage in PJM’s selection highlights these benefits, including favorable capacity accreditation and shorter development timelines,” Sgro wrote. “To balance the strengths and weaknesses of all generation resources, a diversified grid that includes clean energy is the best way to achieve the most reliable and affordable grid. PJM has [forecast] annual demand growth of nearly 5% over the next 10 years. Renewable resources are quick to deploy and provide additional capacity for the grid, helping boost overall reliability and meet rising demand.”
