Page 123 – RTO Insider

May 5, 2025June 30, 2025

Around the Corner: Nobody Does Capacity Quite Like Ontario

Twenty-two years after it went live, Ontario’s independent electric system operator, IESO, has launched its Market Renewal Program (MRP), instituting a nodal day-ahead market that covers more than 900 locations.

The revision appears to have gone smoothly, with the grid operator now joining the seven U.S. ISOs and RTOs that have day-ahead structures. Given that fact, it’s an opportune time to look at the bigger picture of Ontario’s structure and competitive electricity markets in general.

DA markets typically are where the largest volumes of electricity are transacted on a location-specific nodal basis, with varying levels of nodal granularity. Under its earlier approach, IESO had operated only a real-time market with a single price, irrespective of location or transmission constraints.

Generators could schedule their output the day prior, but commitments were not financially binding. Any inefficiencies or price discrepancies, including congestion, were settled through compensatory out-of-market payments, and discrepancies between expected generation and actual real time operations were not subject to penalty. 

Under the new MRP, day-ahead market offers — which create financial obligations to deliver energy the following day — will be scheduled to match forecast demands. Prices will be bound by a floor of -$100/MWh and a ceiling of $2,000/MWh.

In some ways, it’s surprising the move took so long. Locational day-ahead markets create more market efficiency while also offering grid operators and market participants better foresight into what will happen the following day. They are more deliberately proactive and less reactive to real-time events.

The move was a big step for IESO and one of the biggest tweaks to its market design in years. And while it increases the overlap in the Venn diagram with other market operators, IESO’s action and market redesign highlights a very curious fact about North America’s restructured markets: Each “deregulated” market embraces the overriding concept of competition but then spikes the drink with its own highly local flavors.

Peter Kelly-Detwiler

Editorial pet peeve: It’s not clear why people insist on calling this “deregulation.” With highly complex competitive markets superimposed on regulatory supervision for distribution at the state or provincial level, there are far more — and more complex — rules than ever existed before the advent of competition. And operators keep tweaking them to respond to the latest perceived market shortcoming.

These market flavors also defy any attempt by generators, battery operators or demand response aggregators to achieve economies of scale — no, we have created a true Tower of Babel here.

To illustrate the nature of this multifaceted hydra, let’s take the issue of capacity in a number of markets. Texas has no capacity market, letting energy scarcity prices offer the signals, although operating reserves are in the mix as well. Meanwhile, ISO-NE and PJM hold formal capacity market (FCM) auctions three years in advance — unless the regulatory conversation gets so muddled that they get delayed for years, as has been the case for PJM.

New York long ago decided the FCM approach was too potentially inefficient and risky, and opted for monthly options with the possibility of transacting seasonal strips. Meanwhile, on the West Coast, California’s ISO tasks the utilities with procuring capacity resources.

In many markets, capacity represents a noticeable element on the wholesale power bill. Exhibit A is PJM, with its recent eye-watering 2025/26 auction results at just under $270/MW-day, and the just-formalized floor and ceiling prices of $175 to $325/MW-day for the coming two auctions. Exhibit B is MISO’s just released auction results for this summer, coming in devilishly high at just over $666/MW-day and annually between $212 and $217/MW-day. They make PJM look tame by comparison.

But nobody does capacity quite like Ontario, and that hasn’t changed with its Market Renewal.

Capacity and the Global Adjustment Charge (GAC)

As in other markets with capacity prices, the GAC — established in 2006 — is intended to cover the cost of building and maintaining supply infrastructure to ensure system resource adequacy. The initial MRP proposal intended to do away with the GAC and replace it with a formal capacity auction. However, pushback from various stakeholders resulted in this plan being abandoned.

Unlike the role of capacity pricing in other markets, though, the GAC specifically addresses the difference between the total compensation made to certain contracted generators and any offsetting market revenues. As such, there typically has been a strong inverse relationship between wholesale electric energy prices and the GAC. When wholesale energy prices are lower, the GAC is higher, and vice versa. And energy prices historically have been very low, with the result that the GAC typically is the largest single element on the average consumer’s total wholesale power bill, often representing up to 65% or more of the monthly costs.

Ontario’s GAC will continue under the new program, but its impact and interaction will change slightly. The greatest impact may simply be that it will reflect greater location-specific volatility resulting from a nodal pricing program that specifically integrates the impact of congestion.

Lower hourly energy prices will result in higher compensatory GACs, and higher prices will result in the opposite. Only time will tell whether capacity costs will decline as a total percentage of the entire wholesale bill. But if the history of many other grid operators is any guide, the rules-tweaking is far from over. Call it whatever you want, but don’t call it “deregulated.”

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.

May 5, 2025May 6, 2025

MISO Petitions 8th Circuit in Dispute with SPP over Data Center-strained Flowgate

MISO is seeking judicial review of two related FERC decisions preventing the RTO from recouping costs or revising a joint procedure with SPP over a shared North Dakota transmission line that has become congested by a new cryptocurrency mining facility.

The RTO on May 1 filed a petition for review with the 8th U.S. Circuit Court of Appeals over the commission’s previous orders declining a request that SPP refund MISO members or change procedures around the overworked 230-kV Charlie Creek flowgate (ER24-1586, et al).

The flowgate ran up tens of millions of dollars in congestion costs after the Atlas Power Data Center in Williston, N.D., activated on the SPP side of the line in 2023. MISO and its member Montana-Dakota Utilities maintain that associated market-to-market (M2M) settlements unfairly involved MISO in SPP’s localized issue brought on by 200 MW of poorly planned data center growth.

FERC in March denied requests by both MISO and Montana-Dakota Utilities for rehearing to obtain refunds from SPP or cancel eligibility for the flowgate’s ongoing M2M coordination. The commission said the Charlie Creek Flowgate passed the RTOs’ flowgate eligibility studies for such coordination. (See FERC Again Declines Changes, Refunds on Crypto-burdened MISO-SPP Flowgate.)

According to the agreement between the RTOs, MISO must secure SPP’s permission to remove M2M coordination from the flowgate.

MISO also unsuccessfully sought for FERC to alter the MISO-SPP interregional coordination process — which manages flowgates — to make it easier for one RTO to revoke M2M status on a line if it doesn’t think the designation can assist with relieving a constraint. FERC decided that while a section of the two RTOs’ interregional coordination process says M2M coordination should be reserved for issues that are regional — rather than local — that requirement is not an explicit prerequisite for a flowgate to hold an M2M designation. 

MISO has claimed that unwarranted M2M coordination has cost its members $38 million in charges to manage congestion on the flowgate, even as its members can offer only less than 1 MW of relief. However, FERC said SPP’s evidence shows that revoking Charlie Creek’s M2M flowgate status might risk the RTO needing to resort to transmission loading relief or load shedding. 

MISO did not return RTO Insider’s request for comment on how much the RTO estimates its members are owed in refunds or whether it believes growing data center load would produce more flowgate issues at its seam with SPP.

May 5, 2025

CRES Urges Federal Support for Cleaner Hydrogen

A conservative-leaning energy advocacy group is out with a new report on the value of methane-based hydrogen production paired with carbon capture and storage.

So-called “blue” hydrogen is poised to help expand U.S. energy dominance as the global market for lower-emissions hydrogen takes shape, the authors write, and federal incentives are essential for the nation to remain competitive in the early stages.

The Citizens for Responsible Energy Solutions (CRES) Forum report released May 5 included modeling analysis that projected tens of thousands of new jobs and tens of billions of dollars in economic impact from a robust blue hydrogen sector.

The report comes amid ongoing debate over clean-energy tax credits created under former President Joe Biden, which subsequently were targeted by President Donald Trump but are finding support from some Republican lawmakers who see economic benefits in their districts from those credits.

Among these are the 45V clean hydrogen production tax credit. It and other incentives are “essential” for helping the United States stay competitive in the emerging market, the authors write, as the advanced technology involved carries high upfront costs.

While U.S. industrial decarbonization initiatives no longer enjoy the same level of support as they did under President Biden, the report notes that other major economies continue to ramp up such efforts.

“The U.S. benefits from abundant natural gas resources and technological leadership in CCS, making it uniquely positioned to become a global leader in blue hydrogen production,” the authors write.

Their analysis of data from the International Energy Agency shows that all blue hydrogen projects publicly proposed in the United States would have a combined annual production capacity of 9.8 million metric tons by 2035.

Using multiple scenarios, the report calculates:

- Construction of those plants nationwide could support 29,000 to 79,000 construction jobs through 2035.
- Texas and Louisiana would see the largest boost in construction employment.
- Construction could have an annual economic impact of $6.7 billion to $18.7 billion.
- Annual operations would support 18,000 direct jobs and 44,000 indirect or induced jobs.
- The bulk of those permanent jobs again would be in Texas and Louisiana.
- Operations would support $22.4 billion in economic output.

Production of 9.8 MMT of blue hydrogen also would ripple through the natural gas industry, creating steady demand and supporting nearly 6,800 direct jobs, the report estimates.

The authors note that roughly two thirds of announced blue hydrogen production would be devoted to ammonia, most of it for fertilizer. The remainder might be used mainly for petroleum refining and transportation, with a small amount going to steel production.

“The 45V tax credit is not just an investment in energy; it is an investment in America’s economic strength, industrial leadership and long-term global competitiveness,” the authors write.

Dramatically increasing the production and dramatically decreasing the production cost of clean hydrogen was one of Biden’s high-profile Earthshot initiatives, but the vision was hampered by the slow rollout of details crucial to investment decisions. The 45V tax credit rules were not finalized until two weeks before Trump’s inauguration.

Beyond the economics, there is disagreement over how “clean” various types of hydrogen generation really are, and there was spirited argument between industry lobbyists and environmental advocates over the details of 45V as they were being finalized.

Those details play a critical part in how expensive production is and how impactful it is on the environment.

Hydrogen itself does not create carbon dioxide when burned or run through a fuel cell, but significant amounts of the greenhouse gas can be generated through hydrogen production.

Also, given that hydrogen produces less energy per unit of volume than methane, more hydrogen may be needed for a given application.

Finally, the carbon capture and storage that is integral to blue hydrogen also consumes energy.

There is room for reduction, however — the vast majority of U.S. hydrogen production is “gray,” which essentially is the same as blue hydrogen but without carbon capture.

Environmental advocates press instead for “green” hydrogen — emissions-free hydrogen produced with emissions-free electricity newly built for that purpose. Green at present is much more expensive than gray.

CRES is a nonprofit seeking to educate Republican lawmakers and the public about conservative solutions to address U.S. energy, economic and environmental security while increasing the nation’s competitive edge. It identifies its goal as lowering global emissions to maintain a clean environment and mitigate the impacts of climate change.

May 5, 2025May 6, 2025

CalCCA Study Touts Benefits of RA Trading at Hourly Level

The cost of electricity in California could be reduced if energy providers were allowed to trade their resource adequacy products by the hour, a new study by the California Community Choice Association (CalCCA) says.

Currently, load-serving entities submit annual and monthly RA reports to the California Public Utilities Commission. In the reports, each LSE must demonstrate it has procured 90% of its system RA obligation for the five summer months of the coming compliance year and that it meets 90% of its flexible RA obligation for all 12 months. Under existing regulations, California LSEs are limited to trading RA products that cover an entire month.

In 2024, CPUC started the first “Slice of Day” (SOD) RA program in the U.S. The program requires each LSE to demonstrate sufficient capacity in all 24 hours on CAISO’s “worst day” in a month, i.e., the day of the month that has the highest forecast peak load.

However, in the SOD program’s first year, many LSEs had more resources than needed, while other LSEs did not have enough, CalCCA’s paper says. This outcome “suggests there are additional opportunities for trade that are currently unrealized due to regulatory barriers,” it says. It therefore argues for an hourly obligation trading model in order to reduce costs to consumers. 

“This is about fairness and common sense,” CalCCA CEO Beth Vaughan said in a press release. “Let’s stop making energy providers buy more capacity than they need, and let’s stop making Californians foot the bill.”

CalCAA estimated that average RA prices could decrease by $1/kW-month for every 1-GW demand reduction in the new hourly model. The reduced demand for RA products on the market lowers the price of RA and the cost of meeting RA obligations for all California LSEs.

Reducing the cost of RA in California has grown in importance in recent years following the rapid increase in RA prices, the paper says. For example, the weighted-average RA price was $2.77/kW-month in 2019 but increased by a factor of nine to $26.26/kW-month in 2024, according to the paper.

Policymakers should support the development of effective trading mechanisms that go hand in hand with the transition to SOD, CalCCA’s paper says. Otherwise, the SOD program will drive up costs for consumers with no direct benefit to reliability.

But CalCCA noted that its study is based on simulations and that a “real-world” implementation would require a much more in-depth investigation.

“Implementing an effective trading mechanism with the SOD program will not be easy,” the paper says. “Trading in the SOD policy environment is six to nine times more complex than that of the legacy monthly RA product and will require a greater volume of trades, more transactions and more trading partners.”

A key principle of CPUC’s current RA program is balancing addressing hourly energy sufficiency with advancing California’s clean energy, greenhouse gas emissions-reduction and air pollution-reduction goals, spokesperson Terrie Prosper told RTO Insider. With increasing penetration of renewable resources, CPUC sought to construct the SOD framework to better manage reliance on use-limited resources in meeting reliability needs, Prosper said.

Trading RA obligations at the hourly level would not influence natural gas generation in California, Prosper said. The RA framework — both the previous structure and the SOD — is a planning construct and does not directly determine how much gas generation will be dispatched in the energy markets.

May 5, 2025May 6, 2025

FERC Accepts ISO-NE Compliance Filing on Interconnection O&M Costs

FERC on May 2 accepted a compliance filing by ISO-NE and New England transmission owners eliminating interconnection customers’ responsibility to pay for the operations and maintenance costs of network upgrades (ER25-1324).

The commission ordered an additional filing to address potential issues regarding refunds for O&M costs incurred after its initial ruling in December 2024. (See FERC Sides with New England Developers on Interconnection Complaint.)

“The compliance filing largely complies with the [commission’s] directive to remove from the tariff any language providing for the assignment of O&M costs for network upgrades to interconnection customers,” FERC wrote.

The commission also accepted tariff changes broadening the definition of an “interested party” in the New England TOs’ formula rate protocols, which should enable a wider range of groups to participate in proceedings.

NEPOOL, RENEW Northeast, Advanced Energy United and the Alliance for Climate Transition supported the filing, while the New England Power Generators Association and CPV Towantic expressed concern it inadvertently would limit refunds to payments made after the December order, leaving out advance payments for costs incurred after.

FERC directed ISO-NE and the TOs to make an additional filing within 30 days “to clarify that network upgrade O&M costs accrued on or after Dec. 19, 2024, will be returned to the interconnection customer, regardless of whether the interconnection customer made advance payments prior to” that date.

May 5, 2025May 6, 2025

Coastal Virginia Offshore Wind Sees Costs Increase from Trump Tariffs

Dominion Energy’s Coastal Virginia Offshore Wind (CVOW) project has weathered most of the issues facing offshore wind, but the company said during its first-quarter earnings call May 1 that the project faces risks from President Donald Trump’s tariffs.

The project is 55% complete and months away from the first delivery of energy to customers in 2026, and is on track for 100% completion that year, Dominion CEO Robert Blue said.

“It represents the fastest and most economical way to deliver almost 3 GW of electricity to Virginia’s grid to support America’s AI and cyber preeminence and the largest data center market in the world; to support U.S. shipbuilding at customers like Huntington Ingalls — the largest military ship building company in the United States and one of our largest customers — and support some of the country’s largest and most important military and defense installations,” Blue said.

The project’s components are being or already have been assembled, and Dominion has taken delivery on many already, with its Jones Act-compliant vessel, the Charybdis, nearly complete and heading to the construction site off the southern coast of Virginia in the next two months to support turbine installation this summer.

“It’s difficult to fully assess the impact tariffs may have to the project’s final cost, as actual costs incurred are dependent upon the tariff requirements and rates, if any, at the time of delivery of the specific component,” Blue said.

So far, components already have cost an extra $4 million, of which Dominion is responsible for $1 million. But that could grow to as much as $510 million, with the firm responsible for $128 million. It already has filed updated costs with Virginia’s State Corporation Commission that show a $123 million impact from tariffs and Dominion responsible for $31 million, with a final project cost estimate of $10.8 billion.

“The updated project cost of $10.8 billion is expected to increase residential customer bills by an average of 4 cents a month over the life of the project,” Blue said.

Generally, the impact of tariffs on Dominion’s business seems manageable, with Blue saying it already had updated its supply-chain practices after the COVID-19 pandemic.

“We think about increasing inventory and ordering thresholds to address longer lead times, ensure that we have multiple sources of supply where it’s appropriate,” Blue said. “We have been placing some orders ahead of tariff effective dates to mitigate cost increases where it’s possible.”

The other big issue facing Dominion is continued growth in Data Center Alley in northern Virginia, the largest data center market in the world. Blue reported no slowdown of interest in adding new facilities to that market.

Dominion recently asked for a rate increase from the SCC, which also included a proposed new customer class for large loads like data centers that requires them to agree to pay for at least 14 years of power consumption, even if they use less. (See Citing Inflation and Load Growth, Dominion asks Virginia for Higher Rates.)

The new rate class applies to customers who use at least 25 MW, and it would apply to 139 separate consumers, of which 131 are data centers, Blue said. The changes are meant to ensure they pay their fair share and that other customers face fewer risks around stranded assets.

“We’ve talked with the data center customers,” Blue said. “We talked with them in preparing this proposed new tariff. I’m sure there will be further conversations during the case, but I think I can say confidently they understand what we’re looking to accomplish here, and the conversations have been very constructive.”

May 4, 2025

FERC Approves $180M Annually for RMR Deals with Brandon Shores and Wagner Plants

FERC issued an order approving settlements on reliability must run (RMR) deals that will keep the Brandon Shores Generating Station and the H.A. Wagner Generating Station in Maryland running until May 31, 2029 (ER24-1787 and ER24-1790).

Talen Energy owns both plants, which are located near Baltimore and had sought to retire this year. But PJM found that would have led to reliability issues. Brandon Shores is a 1,289-MW coal plant, and Wagner is an 843-MW oil-fired unit. Now they will run until transmission improvements are ready to replace them reliably.

Brandon Shores is getting $145 million a year and Wagner $35 million, which includes fixed-cost charges, a monthly investment tracker payment to recover spending that’s needed to keep the plants running and a reimbursement mechanism to cover operations and maintenance costs.

Talen entered into settlements with Exelon, PJM, the Maryland PSC, the Southern Maryland Electric Cooperative and the Old Dominion Electric Cooperative on the RMR deals, which cut its initial annual cost from $175 million for Brandon Shores and $40 million for Wagner. Talen will credit market revenues the plants earn back to customers, and it agreed to limits on investments in the plants, which require PJM approval.

PJM said the settlements represent a significant achievement of consensus on issues between Talen and a broad coalition of load parties that will pay for the RMR deals.

The deal was opposed by PJM’s Independent Market Monitor and the Maryland Office of People’s Counsel, who took issue with how the plants determined their sunk costs. Talen was spun off from PPL in 2015, and at that point Brandon Shores was appraised at $648 million. But in 2012, the firm bought both plants for just $372.5 million. The people’s counsel argued that using the higher number amounted to a windfall for Talen.

FERC trial staff countered that the sunk costs are within the just and reasonable range and will be offset by capacity revenues being credited back to customers. And costs would be greater if outages occurred in the area because the plants were retired too soon.

“Under this approach, the commission need not find that the rate is exactly the rate the commission would establish on the merits after litigation,” the order said. “The commission need only find that the overall package, resulting from the give and take of the bargaining which led to the settlement, falls within a broad ambit of various rates which may be just and reasonable.”

Precedent gives the commission a few legal rationales for approving settlements. The one it picked focuses on the end result of the deal and involves a balancing of the benefits with costs and the potential effect of continued litigation.

The deals provide a high degree of certainty to market participants that the units will be available, including a longer RMR (five months more than initially proposed) and fewer circumstances under which Wagner and Brandon Shores can terminate operations. It also gives PJM flexibility to end the RMR deals early if market conditions change.

“This certainty provides value to the settlements, especially in light of the serious reliability concerns at stake without the settlements that could lead to much greater costs overall,” FERC said.

May 4, 2025

NYISO Details Proposed Metrics for IDing Poor Performers in Reserve Market

NYISO has proposed the metrics for identifying operating reserve suppliers that consistently underperform as part of its plan to remove them from the market.

The ISO first presented the proposal in January, but it had not yet specified the thresholds for determining whether a supplier was underperforming. (See NYISO Explains How It Would Put Poorly Performing Resources in Time-out.)

One metric is aimed at frequently called poor performers and examines how they performed during Reserve Pick-up (RPU) events — defined as when the area control error exceeds 100 MW — and audits.

The other targets those that are qualified to provide reserves but are rarely called to do so and examines their performance when dispatched in the energy market. “We’re looking at their energy dispatch in the cases where they weren’t picked up for an RPU but are still a provider,” NYISO Associate Engineer Andy Bean told the Installed Capacity Working Group on April 24.

Bean explained that the first metric would be a snapshot of the last three months of RPU performance data. The ISO would divide the difference of the expected basepoint and energy provided by the total sum of the expected basepoints for the three months. Generators that fall below 70% of their expected performance would be subject to a rebuttable presumption of removal from the market.

The metric would be applied any time a resource eligible to provide 10-minute operating reserves is dispatched during an RPU event and during manual audits of eligible resources.

The energy performance metric is structured similarly, but instead of comparing an expected basepoint to energy provided, it uses the same formula to compare energy requested to energy provided over the past three months. Bean said this metric would be assessed any time a resource in the operating reserves market is scheduled, but not when it is providing regulation. If energy performance falls below 50%, it would be subject to a rebuttable presumption of removal.

Resources that fail to meet these thresholds would be eligible for removal from the market for at least 30 days.

Richard Bratton, representing the Independent Power Producers of New York, asked how the ISO had come up with the thresholds.

Bean said NYISO staff had looked at historical data, and those percentages were where they saw “natural breaks” and the worst-performing units separating out. These units, Bean said, were also aligned with what the Market Monitoring Unit identified as the worst performers.

The ISO found that in 2024, roughly 550 MW of operating reserve suppliers would have failed one or both of the metrics and would have been subject to the threat of removal from the market. If all of them had been removed for three months, this would mean that operating reserves would be down 100 MW each month in 2024.

Bean presented a slide showing historical audit data, demonstrating that between the 2022 and 2024 capability years, there were about 80 audits stemming from RPU issues.

Resources may rebut the metrics by showing that the data are incorrect, they were in an outage or their basepoints are inconsistent with what they can provide. Extreme circumstances outside of operator control would also rebut the ISO’s presumption that the resource was performing poorly.

If the resource is unable to rebut, they would be removed from the operating reserves market for 30 days in the first instance and 90 days in subsequent instances. The ISO would retest resources to allow them back on the market.

Mark Younger of Hudson Energy Economics, representing generators, asked whether there would be a mechanism for permanently removing a resource from the operating reserves market. Bean said that was currently not part of the proposal.

Bean said NYISO would consider stakeholder feedback before finalizing the metrics, mentioning several times that he had “starred” comments and questions in his notes over the course of the meeting.

May 4, 2025May 5, 2025

IPF25 Attendees Plan Future OSW Resurgence

VIRGINIA BEACH, Va. — Bruised by President Trump’s aggressive efforts to shut down offshore wind projects, developers and industry advocates are strategizing on how to reset the industry and position it to re-emerge in two to four years.

Speakers and attendees at the International Partnering Forum (IPF) 2025 Conference, while shocked at the pace and ferocity of Trump’s opposition, said they’re optimistic the rapidly rising demand for energy means the federal government eventually will have to harness wind power to meet the nation’s needs.

Key on their minds was Trump’s announcement upon taking office that the nation is facing an energy emergency, then soon after taking steps to shut down offshore wind projects. He issued a memorandum essentially freezing projects in the permitting process and has stopped New York’s Empire Wind mid-construction. He also stalled New Jersey’s Atlantic Shores project, asking for new information even though the project received its final approval in October. (See Feds Move to Halt Construction of Empire Wind 1 and EPA Puts Hold on Atlantic Shores OSW Permit.)

Developers such as Equinor, Ørsted and Vestas have given grim assessments of the U.S. market. (See Equinor, Ørsted, Vestas Say US OSW Market in Trouble.) Speakers at the IPF conference sought to portray the situation variously as a “pause,” a “reset” or a moment when the industry could use the forced downtime to plan for the future.

“Our job, all of our jobs, is to keep pushing so that regulators, citizens and politicians will realize that offshore wind, it’s not optional — we have to have it,” Oceantic Network CEO Liz Burdock said April 29, opening the conference’s second day.

“We’re not just here to trade business cards,” she said. “We’re here to unlock the full force of our collective creativity, to rethink, redesign and reignite the U.S. offshore wind industry.”

“But in our fight, we must adapt and adapt fast, while we grapple with indecision, economic uncertainty and political turbulence,” she said. “Our opponents are loud and they’re organized and they’re holding elected leaders accountable to their demands. It’s time we respond with strength on strength. No more passive storytelling, no more silence while the narrative is shaped by others. We must amplify the truth.”

Sam Eaton, president and CEO, RWE US Offshore Wind | © RTO Insider

Sam Eaton, CEO of RWE’s U.S. Offshore Wind operation, said in an interview with Burdock that a “reset” period will enable it to sharpen its purpose and address its core issues.

“It’s important that we don’t lose sight of the success that we’ve had here in the U.S.,” Eaton said. “But now we face a question as to where the next evolution of offshore wind is going to be, and we need to think about this fundamental question: Are we developing a technology that will serve an important niche, or are we developing a technology will scale to an American mainstream?”

States’ Initiative

Before Trump moved against the OSW sector, President Biden issued leases for 60 GW of power, said Sam Salustro, senior vice president of market and policy strategy at Oceantic Network, adding that “state demand exceeds about 115 (GW) at this point.” The U.S. has one commercial-scale project operating, South Fork in New York, and projects totaling about 19 GW of power have full federal approval and are heading toward completion.

Among them is Dominion Energy’s 2.6-GW project Coastal Virginia Offshore Wind (CVOW), which has two pilot turbines in operation about 27 miles off the Virginia shore. With 176 turbines, the project is designed to power 600,000 homes. Construction is expected to be completed in 2026.

In Massachusetts, Vineyard Wind is producing about 50 MW of energy. Construction is scheduled to be completed in 2025 on the full 800-MW output, Elizabeth Mahony, commissioner for the Massachusetts Department of Energy Resources, said at the conference.

“We’re actively engaged right now with our legislature, with our governor and with the industry to make sure that despite what might happen in D.C., that Massachusetts will continue to be a place for the industry to come this year and next year, or for the next 10 years,” Mahony said.

Several speakers said that given the federal government’s position, states need to take a larger role to push the sector forward. “They are the market movers, and they have continued to act over the last few months,” Salustro said.

Another key factor is collaboration, said Megan Outten, policy manager for the Maryland Energy Administration.

“That goes down to supply chain, knowing how we can support some of our neighboring states, in Delaware, Virginia, New Jersey, and where we can fit in,” she said. “Not every state is going to be their own regional hub for supply chain. We’re going to have specialists in each state,” some for the supply chain, and others for transmission issues, she said.

The potential benefits of collaboration were underscored by the release on the conference opening day of a strategic action plan by the Northeast States Collaborative on Interregional Transmission, which comprises nine states: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Rhode Island and Vermont. The collaborative was formed to explore “opportunities for increased interconnectivity” between ISO-NE, NYISO and PJM. The latest plan outlines an interstate planning process for transmission projects. (See Plan Lays out Steps for State-led Interregional Transmission in Northeast.)

Part of the plan ensures there are consistent standards — such as for technology — used in procurement through the collaborative members, said Bruce Ho, senior policy adviser of the Connecticut Department of Energy and Environmental Protection.

That could “give confidence to the manufacturers that this is where not just one state is going, but where a whole group of states are going,” he said, adding this approach could lower costs.

Ready to Fight

Georges Sassine, vice president of large-scale renewables at the New York State Energy Research and Development Authority (NYSERDA), said stakeholders need to understand how this situation is different from the past, when projects became mired in supply chain problems, cost inflation and the legacy of unsustainably low bids.

“Before, it was a crisis. How do you lead in a crisis?” he said. “Today, our collective leadership challenge is how to lead in a time of uncertainty. And that that requires a completely different reaction.”

Part of that leadership, he said, can be seen in New York Gov. Kathy Hochul’s commitment to vigorously oppose the stop work order issued to halt Empire Wind, and also to keep pursuing wind and transmission projects, and even solicitations.

“We really have to fight, and we would like to partner with you, the stakeholders, to join us in that fight,” he said.

“Our goal here is to figure out how do we protect the projects under construction and make sure that they get built?” he said. “The second goal is, how do we make sure that the industry across the board keeps on investing over the next four years, and keeps on building, and then how do we position ourselves to pick back up exponentially, when the industry wants it, whether it’s in the short term or the long term?”

For all stakeholders, a key element of the pushback, he said, will be “telling the story, a cohesive story, around the value of offshore wind and offshore energy.”

Derisking Projects

Several speakers said stakeholders need to position wind sources to become routinely accepted as one of the “all-of-the-above” categories of power considered in the public debate.

Analysts predict a rapid rise in demand from data centers, which consume vast amounts of power, and from electric vehicles and appliances. The closure of fossil-fuel generators across the region highlights the need for more generation.

“A lot of studies have been coming out over the past couple months that have pointed to the same thing,” Salustro said. “Some estimates are 50% (demand increase) over the next 10 years. Some of it is double over the next 20 or 25 years. Offshore wind is going to be a key part of helping solve this problem of the need for more energy and getting it online fast and soon. Offshore wind is the shovel-ready industry right now. We have projects that are permitted, ready to go.”

With that in mind, Mark Mitchell, senior vice president for project construction for Dominion, said at the conference that his company has drafted a plan to provide energy to 3 million Virginia homes through an “all-of-the-above energy approach” using OSW, solar, battery power, natural gas generation and small nuclear reactors.

“Having a variety of generation sources helps maintain reliability by avoiding over-reliance on any given power source,” he said. “It also helps maintain affordability by insulating our customers and the company against outsize price shocks for a particular fuel source or generation component.”

Still, he added, “renewables are a key element of our strategy,” and the CVOW project is “expected to save customers $3 million of fuel cost over the next 10 years.”

A representative of Ørsted, which closed two New Jersey projects — Ocean Wind 1 and 2 — in 2023 due in part to rising costs and supply chain issues, offered a more cautious assessment when asked in one forum what trends could affect future projects.

May 4, 2025May 6, 2025

Massachusetts Lawmakers Focusing on Energy Affordability in 2025

In the wake of skyrocketing energy costs over the past winter and the loss of federal support for state clean energy initiatives, Massachusetts policymakers are facing difficult questions about balancing decarbonization with energy affordability in the state’s 2025/26 legislative session.

Lawmakers have passed major climate and energy bills in each of Massachusetts’ past three sessions. Most recently the House and Senate agreed to compromise legislation after the conclusion of formal sessions in 2024, overhauling clean energy permitting and siting, updating utility regulations to enable gas pipe decommissioning and authorizing a sizeable procurement of energy storage resources. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track and Compromise Climate Bill Finally Approved by Mass. Legislature.)

The two prior bills, passed in 2021 and 2022, included sector specific decarbonization targets, a new opt-in municipal building code, authorization for offshore wind procurements, electric vehicle rebates and EV sales mandates.

Sen. Mike Barrett (D), co-chair of the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE), told RTO Insider his “first priority is to make sure Massachusetts emerges from the Trump years with its climate capacity intact.”

“We are basically trying to change over an entire economy,” Barrett said. He added the state should avoid “unintentionally paralleling federal cutbacks with cutbacks of our own. We can’t compensate literally for the missing federal dollars, but we want to sustain a very serious state effort, rather than throw up our hands.”

If the Trump administration prevents additional offshore wind procurements, Massachusetts should consider focusing its efforts on rooftop solar, which does not rely on federal approvals, Barrett said. He added the state’s decarbonization strategy is meant to be flexible, and the state could amend its clean energy procurement laws to readjust its strategy.

Barrett also emphasized the importance of maintaining sources of work for the state’s clean energy workforce throughout President Donald Trump’s second term, and that pivoting toward distributed energy resources could help provide these opportunities.

“You might concede that Trump can slow you down, but you don’t want to give him the opportunity to destroy the effort altogether,” Barrett said.

Rising Energy Costs

The winter of 2024/25 was the first since 2014 to feature sustained below-normal temperatures, driving a significant increase in natural gas prices and demand. On Feb. 1, gas supply rates increased 16 to 22% for customers of the state’s investor-owned gas utilities. The supply rate increase coincided with increased delivery fees, which were caused in part by adjustments to the Mass Save efficiency program and continued investments to repair and replace leaky pipes.

High residential energy costs caused significant public pressure on state officials to provide ratepayer relief, and the Department of Public Utilities required temporary reductions in delivery fees and ordered $500 million in cuts from the 2025/27 plan for Mass Save “to protect ratepayers from excessive bill impacts.” The Mass Save cuts drew some criticism from clean energy advocates, who argued the move would hurt ratepayers in the long run.

Meanwhile, Gov. Maura Healey (D) announced in March an “energy affordability agenda,” returning to ratepayers $125 million in funds collected from alternative compliance payments for state clean electricity standards. Healey also committed to filing “an energy affordability and independence bill to explore new ways we can make Massachusetts more affordable.”

Residential Competitive Supply Ban

Heightened attention on energy costs may boost efforts to ban competitive residential electricity suppliers, a proposal that fell short in the negotiations for the 2024 compromise bill. Healey, the Office of the Attorney General (AGO), the city of Boston and top senators all expressed support for a ban during the session, but the proposal ultimately was derailed by opposition in the House.

Competitive suppliers in the state currently are allowed to market directly to ratepayers, and the state has struggled to prevent predatory suppliers from locking customers into deceptive and expensive supply contracts. Supporters of the industry have argued that predatory practices can be addressed through reforms, while critics have argued that a ban is the best way to protect consumers.

“I don’t think any of us are backing off on the determination to bar competitive suppliers from selling to low-income households door to door,” Barrett said.

A 2024 report by the AGO estimated that residential customers of competitive electricity suppliers paid over $577 million more than basic utility service customers over an eight-year period. The report also found that “low-income consumers and people of color continue to suffer a disproportionate amount of the consumer harm.”

Larry Chretien, executive director of the Green Energy Consumers Alliance, said a ban is “is likely the easiest thing to do to make energy more affordable, because it doesn’t require taking money from one account … it doesn’t require tax dollars, and it doesn’t require raising one person’s rate to lower another person’s rate.”

“We’re going to hope that the House takes an open-minded view of this,” Chretien added.

Utility Reforms

While lawmakers and advocates are quick to support the idea of energy affordability, in practice, the concept can motivate widely ranging policies with varying effects on decarbonization efforts.

Kyle Murray, director of state program implementation at the Acadia Center, said he would like to see the energy affordability bill include limits on utilities’ return on equity, potentially restricting ROE to an average of the surrounding Northeast states.

“Our position has long been that utility return on equity is really inflated and could serve to come down a few points,” Murray said, while also acknowledging that passing ROE reforms would be challenging due to the complexity of utility ratemaking and likely opposition from investor-owned utilities.

Murray also said he hopes lawmakers will consider changing the funding mechanism for some programs currently funded through volumetric charges in electricity and gas rates. He said funding programs like low-income discounts, Mass Save and renewable energy charges through fixed bill charges or through the tax base could save most ratepayers money.

He also expressed interest in legislation limiting the expansion of the state’s gas network, a priority shared by Mass Power Forward, a large coalition of climate and environmental justice groups.

One of the main bills backed by the coalition would prohibit the state Energy Facilities Siting Board from approving new fossil infrastructure within five miles of state-designated environmental justice communities. The group also is pushing for legislation to prevent utilities from using ratepayer funds to cover the costs of industry associations, lobbying activities and promotional advertising.

Mass Power Forward coordinator Claire-Karl Müller said lawmakers should address utility incentives that encourage expansion of the gas network and undermine Massachusetts’ decarbonization mandates and long-term strategy to reduce gas reliance. (See Massachusetts Moves to Limit New Gas Infrastructure.)

“If you’re in a hole, stop digging,” Müller said. “We have to stop expanding the gas system immediately.”

The coalition’s other priorities include a proposal to make fossil fuel companies pay for the costs of climate resilience through a “climate change superfund,” as well as new outdoor and indoor air pollution protections for vulnerable communities.

Looking Forward

The state is in the early stages of its 2025/26 legislative session, which will conclude at the end of July 2026. Lawmakers already have submitted nearly 250 bills to the TUE committee, which has yet to begin bill hearings.

The House TUE co-chair, Rep. Mark Cusack (D), is new to the committee this year, and it remains to be seen whether his priorities will differ from Rep. Jeff Roy (D), who served as the House co-chair from 2021 through 2024. Roy was not reappointed to the committee after the Boston Globe reported he had a romantic relationship with a lobbyist working for clients regulated by the committee, including a third-party electricity supplier.

While no longer serving on the TUE committee, Roy has been appointed to House leadership by speaker Ron Mariano (D) and could remain an influential voice in the House on energy issues. Neither Cusack nor Roy responded to requests for comment.

Meanwhile, the Healey administration is expected to file energy affordability legislation in the near future, which should help define the scope of the legislature’s discussions and negotiations on climate and energy issues.

A spokesperson for the Massachusetts Executive Office of Energy & Environmental Affairs said Healey soon will “file an energy affordability and independence bill to explore new ways we can make Massachusetts more affordable,” adding that the administration “will use every tool we have to help make sure families and businesses can afford to heat their homes and keep the lights on.”