EPA has rejected an industry petition to exempt stationary combustion turbines from hazardous air pollutant regulations.
EPA announced its decision April 15 and said it was part of a continuing, comprehensive approach to limit climate- and health-harming pollution from these sources.
EPA said stationary combustion turbines typically are located at power plants, compressor stations, landfills and industrial facilities, and burn a variety of fuels ranging from natural gas to distillate oil to landfill gas.
EPA said its regulations under Section 112 of the Clean Air Act limit emissions of air toxics, also called hazardous air pollutants, including formaldehyde, toluene, benzene, acetaldehyde and metals such as cadmium, chromium, manganese, lead and nickel.
In August 2019, the petitioners had asked EPA to remove stationary combustion turbines from the list of sources subject to Section 112 because they create a cancer risk of less than one in 1 million and therefore meet the statutory threshold to be delisted.
EPA said it rejected the petition because it was incomplete and because the agency could not conclude there was adequate data to determine that delisting thresholds were met.
An EPA database last updated in October 2023 shows nearly 1,000 turbines at just over 500 facilities nationwide were subject to the regulations.
“Today’s action will ensure people who live, work and play near these facilities are protected from harmful air pollution,” EPA Administrator Michael S. Regan said in a news release. “EPA is committed to ensuring every community has clean air to breathe, especially those that have been overburdened and disproportionately impacted by poor air quality for too long.”
The petitioners were the American Fuel & Petrochemical Manufacturers, the American Petroleum Institute, the American Public Power Association, the Gas Turbine Association, the Interstate Natural Gas Association of America and the National Rural Electric Cooperative Association.
American Petroleum Institute spokesperson Scott Lauermann said in a prepared statement: “While we are disappointed with this decision, we will continue to work with the EPA to ensure any new or revised emissions standards for combustion turbines are cost effective and technically feasible.”
But Earthjustice and other environmental groups applauded EPA’s announcement.
“Today’s decision upholds critical environmental protections that are essential for safeguarding public health, particularly in communities that have historically borne the brunt of industrial pollution,” Earthjustice Director of Federal Clean Air Practice James Pew said. “EPA did the right thing by rejecting industry’s attempt to dodge these requirements and get a free pass to pollute.”
The Sierra Club said it had been pushing back against the exemption request for five years.
“The EPA’s denial of the petrochemical industry’s bid to ease regulations for these major sources of toxic air pollution is a victory for public health and the environment,” said Jane Williams, who chairs the organization’s National Clean Air Team. “The EPA’s commitment to upholding these standards reinforces the importance of robust regulatory frameworks prioritizing our planet’s health and its people over industrial convenience.”
The federal government has finalized rules that will decrease the cost of siting renewable energy generation on public land and increase the cost of leasing it for oil and gas development.
The Department of the Interior announced the final Renewable Energy Rule on April 11. It reduces rent and capacity fees, streamlines the application process, allows for noncompetitive bidding and makes the process more predictable.
The department announced the final Fluid Mineral Leases and Leasing Process Rule the next day. It increases bonding requirements, adds protection for key wildlife habitat and cultural sites, increases royalty rates, boosts the minimum bid amount and creates a per-acre fee for expressions of interest.
Reaction fell along likely lines, with environmental advocates praising both rules and the petroleum industry panning the mineral rule.
Renewable Energy
The renewable rule derives from the Energy Act of 2020. According to a fact sheet, it reduces capacity fees 80% until 2035, then steps the discount down to 20% by 2039. It also establishes incentives for solar and wind projects that entail project labor agreements and use U.S.-made materials.
And it gives the Bureau of Land Management discretion to hold competitive bidding in places where the greatest competitive interest exists; the process for this will be standardized.
DOI said in a news release that the revisions are intended to reduce consumer energy costs and promote clean energy development.
But even as President Joe Biden presses the energy transition away from fossil fuel use, U.S. natural gas output has set records and the U.S. is producing more crude oil than any other nation, ever, according to the Energy Information Administration.
Oil and Gas
The mineral rule is BLM’s first major update to the onshore oil and gas leasing framework since 1988 and entails the first increase in royalty rates since 1920. Some of the provisions in the update were set in the Inflation Reduction Act and the Infrastructure Investment and Jobs Act.
The intention is to “increase returns to the public and disincentivize speculators and irresponsible actors,” DOI said in a news release.
Among the changes, summarized in a fact sheet, are that royalty rates for new oil and gas leases on public land will increase from 12.5% to 16.67%; minimum rental rates will start at $3/acre and rise to $5 and $15 in years three and nine, respectively, of a lease; noncompetitive leasing is eliminated; minimum lease bond is increased to $150,000 and statewide bond to $500,000; and wells will be considered idled after four years rather than seven.
Also, the revisions will guide BLM as it tries to steer leasing toward areas with existing infrastructure and high oil and gas potential — the areas most likely to be developed — and away from areas with sensitive wildlife habitats, high recreational use and cultural resources.
The higher bonding amounts are an attempt to shield taxpayers from the cost of cleaning up orphan wells.
Reactions
“These new regulations are the kind of common-sense reforms the federal oil and gas leasing program has needed for decades,” the Sierra Club said. “The days of oil and gas companies locking up public lands for decades for pennies on the dollar and leaving polluted lands, water and air in their wake are over.”
Friends of the Earth praised the oil and gas lease changes but said the underlying issues remain unaddressed.
“While we support BLM’s steps to curb financial giveaways to Big Oil, this rule fails to confront the massive tide of climate emissions stemming from its leasing program,” FOE said. “If Interior intends to manage our public lands for the public good, then it must account for the future generations living under the threat of catastrophic climate change. Interior must do what the science demands and end the expansion of fossil fuels.”
Fossil industry groups had a different reaction.
The Independent Petroleum Association of America said the Biden administration was trying to “placate a small group of environmentalists” and “further reduce” American oil and natural gas production.
“The final rule will not improve stewardship of federal lands, as BLM claims, but will have the effect of driving mineral production off of these areas. The regulatory environment has become so hostile to American oil and natural gas producers operating on federal land that it’s clear the Biden administration intends for ‘multiple use’ lands to only be used for conservation and recreation. The true losers with this misguided policy are states and localities that rely on revenues from federal land extractive industries to meet their budget obligations year after year.”
The BLM rule will drive small producers off public lands, the Western Energy Alliance said. “The bonding amounts are excessive when there are just 37 orphan wells out of more than 90,000 wells on federal lands. Increasing bonding amounts twentyfold in order to take care of a problem on just 0.004% of wells is way out of proportion. This is another rule by the Biden administration meant to deliver on the president’s promise of no federal oil and natural gas. Western Energy Alliance has no other choice but to litigate this rule.”
More than two dozen Western electricity sector entities sent a letter to SPP expressing support for the continued development of the RTO’s Markets+, which is competing for participants with CAISO’s Extended Day-Ahead Market (EDAM).
The April 12 letter from the 26 entities, addressed to SPP CEO Barbara Sugg, arrived nearly three weeks after the RTO filed the Markets+ tariff with FERC and two weeks after Bonneville Power Administration staff issued a tentative recommendation that the federal agency choose Markets+ over EDAM. (See SPP Files Proposed Markets+ Tariff at FERC and BPA Staff Recommends Markets+ over EDAM.)
“We collectively appreciate the effort and process that has resulted in the filing of the Markets+ tariff, and we look forward to participating in the ongoing development of the protocols and other market details,” the organizations said.
SPP noted that the signers include organizations from the Pacific Northwest, Desert Southwest and Mountain West and represent about 57 GW of peak demand across 10 states and one Canadian province.
“SPP is proud to receive support from a broad and diverse group of stakeholders across the Western Interconnection for the continued development of Markets+,” Vice President of Markets Antoine Lucas said in a statement issued April 15.
Twelve of the U.S.-based signatories represent balancing authorities that will face a choice between the two day-ahead market offerings. They include Arizona Public Service, Avista, BPA, NorthWestern Energy, Public Service Company of Colorado, Puget Sound Energy, Salt River Project, Tacoma Power, Tucson Electric Power, and the Chelan, Douglas and Grant county public utility districts in Washington state. Another, Powerex, is the marketing arm for BC Hydro, the BA for the province of British Columbia.
The other signers consist mostly of publicly owned utilities in the Northwest, most of which are in BPA’s BA area, as well as Tri-State Generation and Transmission Association, whose members span four states, three of which are in the Western Interconnection.
The letter highlighted the “preferred aspects” of Markets+ for the signatories. Key among them is the market’s “independent, inclusive and robust governance structure,” a point BPA staff heavily emphasized in its recommendation.
“As most of us were Phase 1-funding participants of Markets+, we have seen first hand the benefits and importance of the Markets+ governance structure. Critically, Markets+ has had independent governance from Day 1, including the establishment of an Interim Markets+ Independent Panel,” the organizations said.
They also lauded SPP’s “stakeholder-driven decision-making” process, for which RTO staff provide a supporting role but do not lead. Some Northwest stakeholders have criticized CAISO for its more staff-driven stakeholder process, saying it creates a bias in favor of California interests.
“We believe that the Markets+ framework would provide a level playing field for participants at the outset,” they said.
WRAP Integration
The organizations also praised the fact that Markets+ will require participants to take part in a common resource adequacy framework, the Western Power Pool’s Western Resource Adequacy Program.
“This requirement would help ensure that there are adequate resources to reliably serve load throughout the footprint and that such resources are installed and/or secured well ahead of market operations. It would also ensure that all market participants are equitably contributing to the reliability of the market footprint and that no participants are systemically leaning on others,” they said.
They also noted that many of them “express specific support for the concept of the Markets+ design choice to deliver congestion rents to those participants with monthly or longer firm transmission rights, including both network service and point-to-point transmission rights.”
The congestion rent mechanism would provide two benefits, they said.
“First, it could help ensure equitable outcomes for firm transmission customers by providing the appropriate revenues (or hedges) to each customer on a path-specific basis. Second, it could create an appropriate ongoing investment incentive for firm transmission service, which helps protect transmission providers’ main source of revenue, preventing cost shifts between customers,” they said.
They pointed favorably to other aspects of the Markets+ tariff, including “a must-offer requirement ensuring resource sufficiency that supports market liquidity and reliability,” treatment of greenhouse gases “that supports state requirements” and “prioritization of load service inside the Markets+ footprint over low-priority exports.”
“We’re glad to see Western entities base their support on characteristics of our market design that we think make Markets+ a wise choice for the West, including enhanced system reliability, the affordability of wholesale energy, support for goals related to sustainability and equity in everything from governance to market pricing,” SPP’s Lucas said.
The letter did not indicate financial commitments for the second phase of developing Markets+.
“Each of us have different requirements around our decision process regarding moving forward with participation in a day-ahead market, and some of the undersigned stakeholders do not expect to make decisions about funding and joining a day-ahead market until the end of this calendar year,” the signatories wrote.
Thirty-six entities participated in Phase 1 of Markets+.
New grid-scale battery storage in Maine would be cheaper than new fossil peaker plants when accounting for societal costs of air pollution and carbon emissions, according to a new report by the Clean Energy States Alliance and Strategen.
“Today, existing fossil-fueled peaker assets in Maine are aging and are seldom dispatched economically,” the authors wrote. “Many of these assets are likely to retire soon, making their replacement with cleaner alternatives timely as it would materially contribute to the reliability of the grid, as well as minimize the health and environmental impacts.”
The authors emphasized the potential benefits of four-hour battery storage. While two-hour storage would outperform four-hour storage under ISO-NE’s existing resource capacity accreditation (RCA) rules, ISO-NE’s ongoing work to update how it accredits capacity — intended to take effect in 2028 — would make four-hour batteries cheaper than both two-hour batteries and new fossil peakers, the report found.
“The relative cost-effectiveness of four-hour storage is generally dependent on the capacity accreditation framework,” the authors wrote.
While the accreditation rules treat two-hour and four-hour batteries similarly, ISO-NE has indicated the new RCA framework would increase compensation for longer-duration storage resources. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.)
The authors also found the results changed significantly when climate and public health were not included in the cost comparison; without these costs, the study found that new peakers would be cheaper than batteries in the updated accreditation scenario.
While new fossil plants would be more efficient than aging incumbent generators, they still likely would result in an increase in statewide emissions and air pollution, the authors noted. Because new plants would be cheaper to run, they would be able to run more frequently, resulting in more pollution, they wrote.
“Replacing fossil-fueled peaker plants with battery storage would avoid this increase in emissions, resulting in environmental and human health benefits including lower risks of respiratory illness, cancer, disease and premature mortality,” the analysis said.
The authors noted the state’s peaker plants typically are located near urban areas, disproportionately exposing lower-income communities to adverse health impacts.
The state is developing a procurement of up to 200 MW of utility scale battery storage, authorized by legislation signed in the summer of 2023.
While the state has about 50 MW of installed battery storage, maxing out at two-hour duration, the procurement should focus on four-hour storage to maximize benefits to the grid, the authors said.
“While two-hour resources might be viable in the near term, as the penetration of renewables and storage increases, longer duration assets such as four-hour [battery energy storage systems] represent more durable, future-proof investments,” the report concluded.
ALBANY, N.Y. — Industry speakers at the 2024 New York Energy Summit told attendees the state has already missed its goal of 70% renewable energy by 2030 even as state officials maintained their optimism.
Attendees at the Infocast event April 8-10 keyed on New York having some of the nation’s highest clean energy targets and a tough environment for reaching those milestones, which includes 100% zero-emissions electricity by 2040.
Less often mentioned is that the state is starting from a low baseline, has not estimated cost or fully identified a source of funding for the transition, pledges to give full consideration at every step to fractious stakeholders and has a constitution that empowers local governments to slow or block progress.
This dichotomy was a frequent point of discussion at the three-day event.
State officials at the summit spoke of the importance of the looming 70-by-30 milepost, but not about the likelihood of reaching it.
Private-sector attendees were not so reticent.
Timothy McClive, director of energy policy and regulation at Central Hudson Gas & Electric, pointed to the math.
“Renewable has to go from 25% currently up to 70%,” he said. “That would require about a 90 to 95% reduction in the amount of power coming out of gas and oil plants by 2030. That is a huge lift.”
At the start of a discussion on ramping up onshore wind and solar development, one panelist after another said 70-by-30 is out of reach.
“We won’t hit it,” said Paul Curran, chief development officer of CleanCapital, “but I don’t think that’s a bad thing, because we’ll have a goal, and the goal is aspirational.”
“The resource that we don’t have a lot of right now is time — we’re out of time. Everybody is just managing time, and we’re not doing it very effectively right now,” said Keith Silliman, chair of the Alliance for Clean Energy New York’s board.
“I don’t think we have a large enough labor pool to build that many megawatts in the six construction seasons we have left, and there’s not enough transmission capacity,” said Stephane Desdunes, vice president of grid-scale power development at EDF Renewables North America. He predicted the state would be able to contract the renewables by 2030 but not get them built by then.
“There are a lot of issues in New York that we have not thoroughly thought out on this clean energy transition,” said Gavin Donohue, CEO of the Independent Power Producers of New York (IPPNY), whose members provide more than 75% of in-state power generation.
John O’Leary, the state’s deputy secretary for energy and environment, acknowledged industrywide challenges. Contracts totaling more than 10 GW of renewable capacity were canceled in New York as the terms became untenable in 2023. But the projects themselves were not canceled, and many were bid into the expedited solicitation process that followed.
“I’m confident that the rapid rebid process that is underway with [the New York State Energy Research and Development Authority] will yield projects that can move forward into construction around the state this year. I’m very excited about that,” O’Leary said. “It’s no question that renewable energy has been dealt some major setbacks and experienced a market reset in the past two years, but we are navigating through these challenges.”
NYISO CEO Rich Dewey told RTO Insider the state presents advantages and challenges to the grid operator.
“Cost allocation in the multistate jurisdictions tends to be the really contentious issue that ends up bogging down a lot of projects, and the failure to agree on that tends to be the death of a lot of them,” he said.
“In New York, being a single-state ISO, it’s a much easier task. You still have the upstate-downstate [split] — exactly which customer is going to pay [and] who really benefits, and there’s a careful consideration of that — but I think it definitely makes it easier,” Dewey said. “It’s probably the biggest reason we’ve been so successful with our FERC Order 1000 projects so far.”
On the flip side, New York has a strong home-rule tradition, and local governments are not shy about exercising it.
“Siting is hard,” Dewey said. “Siting specifically downstate is much more difficult because of the geography and the nature of the population density. A lot of jurisdictions have local opposition to certain types of development projects.”
The state’s creation of the Office of Renewable Energy Siting has helped streamline this process, Dewey added, but not smoothed out all bumps.
Local Opinion
ORES has a delicate choreography to perform: usurping local authority on large-scale projects while still incorporating local input and meeting all the state mandates placed on renewable energy development.
“For folks here in this room that have built or developed large-scale renewables in New York state, they know that [it’s] more than science, it’s art,” ORES Executive Director Houtan Moaveni said. “It is not easy; it is very challenging work; and it takes a lot of commitment to balance multiple issues at the same time in a parallel path.”
One after another, speakers raised the same point as Dewey: local opposition to renewable energy construction.
New York Solar Energy Industries Association Executive Director Noah Ginsburg said small-scale developers wish for something like ORES.
“We really see New York favorably, based on the sustainability and longevity within the market that we believe exists,” said Zachary Muzdakis, director of market development for Madison Energy. “I think there’s a few areas where we can target improvement,” naming punitive local zoning restrictions and moratoria, and a desire to place generation closer to load centers.
Dan Voss, senior director of project management at Kearsarge Energy, said New York is a great market. While interconnection has been an issue in other states, siting is the bigger challenge, he said. “We’re finding some inconsistencies from a permitting perspective. Moratoriums, they’re difficult. We’re fortunate to be able to play the long game, but many developers can’t do that.”
Other Observations
CleanCapital’s Curran said the specificity of New York’s mandates and the commitment behind them have their own benefits.
“When you go to a bank and you talk about a New York project, they understand what VDER [Value of Distributed Energy Resources] means; they understand the goals going forward,” he said. “Having certainty is an enormous help when you’re trying to explain what you’re trying to do. And that’s a big advantage New York has over other places in the country.”
ACE NY’s Silliman said he appreciates the commitment of New York’s agencies promoting or enabling clean energy construction but wishes they had greater coordination and a better understanding of how their individual roles fit into the larger whole.
Richard Bratton, director of market policy and regulatory affairs at IPPNY, said New York has some of the strongest climate mandates in the nation, but that is not enough to foster the renewable energy development the state wants. Developers also need to see market price indications that the private sector can profit.
Joshua Feldman, vice president of investments at Generate Capital, made the case for state and local incentives for projects.
“It is important for the state of New York to consider the fact that this is true everywhere in the United States and that we are essentially faced with this decision on a recurring basis of, is New York state the best place for us devote our capital? And New York is not the easiest place to do business in. I think having local incentives to make sure that the industry stays focused on New York is critical.”
John Howard, whose term on the New York Public Service Commission recently ended, said the state’s interconnection queue is better than most. “While it is a nightmare everywhere else, it is some nights just a bad dream here.”
ALBANY, N.Y. — Development of potential fossil fuel replacements was a recurring focus of the 2024 New York Energy Summit.
Presentations at the Infocast event April 8-10 focused on alternate energy sources individually and collectively.
Offshore Wind
Offshore wind is potentially one of the largest components of New York’s energy transition, with multiple wind farms envisioned to provide several hundred megawatts each of emissions-free electricity.
But it is also the most problematic, relying on limited or nonexistent domestic manufacturing capacity and infrastructure and getting buffeted by macroeconomic trends. The state’s roster of contracted offshore projects was all but erased as rising costs rendered the contracts untenable in 2023, guaranteeing that already huge costs will jump even higher.
However, with each project carrying a budget in the billions, and billions more in ecosystem investments expected, industry interest is keen. New York’s offshore wind reset was a topic through multiple presentations at the summit.
Gregory Lampman, offshore wind director for the New York State Energy Research and Development Authority, reaffirmed what is widely known: New York remains fully committed to offshore wind, not just as a source of carbon-free electricity, but as a new industry with its own ecosystem. It just may take longer than expected to come to fruition.
“I think we’re all realizing that our aspirations and the goals and timelines that we had in mind were pretty exceptional,” he said. “The goals are still really massive, and we’re on track to do some really great things over the next couple of years.”
Adaptation will be key, Lampman said. The state cannot just write contracts for projects; it must work with industry to move projects forward.
Peter Lion of NYSERDA and David Whipple of Empire State Development said the state’s willingness to provide seed money — with more than $1 billion in grants — has helped advance the new sector.
“Private industry is unable to do this on their own, from what we’ve seen, and New York is happy to be a public investor,” Lion said.
Rubiao Song, managing director of energy investments at JPMorgan, said that from a tax equity perspective, the top concerns for investors are supply chain constraints, shortage of vessels and lack of a robust insurance market.
“Hurricane risk is a real issue here,” he said. “We need a significant presence from the insurers.”
Sergio Garcia, executive director of project finance in the Americas for Rabobank, said he believes the wind energy projects proposed off the New York coast will obtain their needed financing.
“I think the expectations have to change a little bit. They’re not going to be financed the same as Vineyard Wind,” he said, referring to the 800-MW facility being built off Massachusetts, which in 2023 became the first major U.S. offshore wind project to put “steel in the water.”
“I think at that point, banks were overly excited [and] extremely optimistic, and we saw what happened.”
Yet the willingness to finance these projects endures, Garcia said, despite the slow pace of development and dearth of critical infrastructure such as ports and ships. “It’s not as fast as we would like it to be, but yes, there is appetite for those types of assets.”
Aude Schwarzkopf, Equinor’s East Coast head of commercial development, said an important piece of infrastructure began to take shape in April as construction started on an offshore wind operations and maintenance port at the South Brooklyn Marine Terminal. Equinor is developing the site for its Empire Wind project but intends it to be a resource for other projects as well.
“From the developer perspective, 2023 was hell, so it can only get better from here,” Schwarzkopf said. “At least that’s what I hope.”
Equinor started 2023 with three contracted New York projects and ended the year with none, she explained. But in late 2023, Empire Wind was greenlit by federal regulators, and in early 2024, it won a conditional new contract from New York state.
“I think that this more stable time is the time that the industry needs to focus on building the supply chain,” Schwarzkopf said.
Brian O’Boyle, director of transmission development at National Grid Ventures, spoke of Community Wind, his company’s joint venture with RWE. It’s in a much earlier stage than Empire Wind, so it has a long road ahead.
“I think we’re holding the course” in the face of the industry’s challenges, O’Boyle said. “A lot of it is building the supply chain up more than it is building the individual project, which in itself is a herculean undertaking.”
Fred Zalcman, director of the New York Offshore Wind Alliance, said some momentum has been lost: Almost every East Coast state with offshore wind contracts saw cancellations in 2023.
“Is it fatal? No. Absolutely not. And I think in large measure the credit goes to state policymakers,” Zalcman said, noting that NYSERDA took just three months to issue a rush solicitation for offshore wind proposals after existing contracts became untenable in 2023.
New York’s three previous solicitations had taken 14 months on average to prepare.
Solar
Discussion of solar energy development at the summit veered between appreciation for New York’s support of community solar projects and dismay at increasing local opposition to construction.
Nicola Armacost, mayor of Hastings-on-Hudson in Westchester County, discussed the village’s success streamlining its solar permitting process. It is hardly a microcosm of New York state — a small, progressive-minded village with many preservationists among its populace — but the process has helped it gain recognition as a clean-energy community.
“There isn’t a lot of resistance on either the residential side or on the municipal side, and I think that makes it much easier,” Armacost said.
Not so in other parts of the state. Resistance to solar and other renewable energy installations is firm, and it is spreading.
Noah Ginsburg, executive director of the New York Solar Energy Industries Association, said he asked his members to identify municipalities that have enacted restrictions, then had to send out another email telling them to stop because he had enough names to make his point.
“Mayor Armacost, please come and run for mayor in many other towns across New York state that are banning solar,” he said. “It’s easier in many parts of New York state to get a permit for a 100-MW solar facility than a 5-MW solar permit.”
Solar installations of less than 5 MW have been the majority of those installed in the state and are the majority of those proposed, he said, but they do not qualify for the expedited review the state Office of Renewable Energy Siting provides to larger projects.
A subset of small solar installations — community solar — has done very well in New York thanks to supportive state policies. In 2023, the state surpassed 2 GW of installed community solar, the most of any state.
Max Joel, director of NY-Sun at NYSERDA, said the state is on track to meet its distributed solar targets: 6 GW by the end of 2025 and 10 GW by 2030.
“The residential solar space has been a mainstay,” he said. “I think like everywhere in the country, we do have that doughnut hole in large rooftop commercial and industrial. Not that we don’t have plenty of that, but it hasn’t grown in proportion to the other sectors.”
Storage
Energy storage is a necessary complement to the intermittent offshore wind, onshore wind and solar generation New York envisions.
Solar is particularly fickle, with a capacity factor that shrivels to the single digits during the short, cloudy days that mark a New York winter. But wind lulls can be problematic as well.
State leaders have appropriately ambitious goals for storage, but buildout is off to a slow start.
Long-duration storage is not available at scale; the present market structure is not favorable for short-term storage; the industry is waiting for the state to finalize a revised roadmap for deployment; and a spate of highly publicized fires has galvanized local resistance to siting.
William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, said the need and opportunity for intraday energy storage is pressing and the need for longer-duration storage is looming.
“We’ve got to get going on those things,” he said. “Getting projects built [faces] a number of barriers in New York state, and the roadmap identifies those barriers, creates programs to knock them down and to develop projects. To us this is one of the most important things that needs to happen right now.”
David Sandbank, NYSERDA’s vice president of distributed energy and transportation, said there is about 12 GW of storage in interconnection queues. NYSERDA itself has contracted 1.3 GW, but less than 300 MW of that is operating or under construction.
“It’s not a lot. And the 1.3 is about 1.1 right now because of some bulk storage projects canceling,” he said. “I think what you’re going to see in the very near future is a lot of retail 5-MW, four-hour battery storage projects getting built in New York City. There’s about 150 MW right now that are shovel ready.”
MD Sakib, National Grid’s director of future of electric, repeated that New York now has 250 MW of the 6 GW that the revised roadmap calls for by 2030.
“Let that sink in,” he said. “There’s a lot that we need to do, and I think there’s a lot of outreach and education that needs to happen.”
Projects are stalling in the application and review phases, and costs have soared, Sakib said.
“I think we have the right roadmap in place. … It’s just a matter of getting down to it and making sure we execute those things.”
Hydrogen
Haiyan Sun, hydrogen and clean fuels program manager at NYSERDA, said hydrogen remains a key part of the state’s decarbonization strategy, even after the U.S. Department of Energy did not award New York and its New England partners the hydrogen hub they were seeking.
“It will play an instrumental role,” Sun said. “What New York needs to do for hydrogen long term is not going to be affected by whether we have a DOE hub or not. It affected the short-term momentum, certainly, but we respect DOE’s decision. We did not get an answer [on] why we were not selected.”
Hydrogen will help decarbonize hard-to-electrify sectors, Sun continued. “Hydrogen will also play a critical role in [stability and reliability] of the New York grid while we march along to 70-by-30 and especially when we try to reach zero emissions by 2040.”
Plug Power Chief Technology Officer Tim Cortes said New York’s support for manufacturing has been an important part of the growth enjoyed by the company, which is headquartered only a few miles north of the capital.
The proposed federal 45V tax credit rules have given the company pause, however. Much of the hydrogen industry is gnashing its teeth over the draft guidance, Cortes said.
Jeffrey Goldmeer, director of the global hydrogen value chain for GE Vernova, said technology is not likely to be the sticking point for hydrogen adoption. A greater challenge is likely to be the infrastructure supporting it, he said, recalling a 2021-2022 hydrogen combustion demonstration project at a New York Power Authority peaker plant that was dictated by the availability of green hydrogen, several tanks of which were trucked in each day.
There is a potential geographic split between where hydrogen is generated and used, Sun said, as well as a seasonal split between the greatest need for green hydrogen and the greatest availability of renewable energy to generate it.
ERCOT told Texas regulators their initial reliability study of the Permian Basin, the nation’s largest oil production field, indicates “substantial amounts” of local transmission projects are needed to meet the 24 GW of load projected to be added by 2038.
During the Public Utility Commission’s open meeting April 11, the grid operator’s Kristi Hobbs said it will have to add about 565 circuit miles of new 345-kV lines, eight new 345/138-kV substations with 18 new 345/138-kV transformers and about 344 miles of new 138-kV lines. ERCOT also needs to upgrade about 326 miles of existing 345-kV lines (55718).
None of that includes “significant” regional upgrades needed to transfer power across the ERCOT system. The grid operator said it will begin identifying import paths into the Permian.
“There is not a lot of generation within the Permian Basin region to serve all the additional load that is being forecasted,” Hobbs, vice president of system planning and weatherization, told the commissioners. “We will continue looking at revising the plan for the local region as well as coming to you … for what is going to be needed for imports across the state into the region.”
Hobbs said 58% of the nearly 12 GW of expected non-oil and gas load is composed of crypto mining facilities. Green hydrogen represents 22% of the coming load, with commercial industrials accounting for 12% and data centers 8%.
“This is just one example of what we’re going to continue to see throughout the rest of the state as we look at reliability plans,” Commissioner Lori Cobos said.
The PUC last year directed ERCOT to develop a reliability plan for the Permian Basin, a response to legislation passed earlier in 2023 to address the region’s rapidly increasing demand for power. The commission prioritized the plan’s development as it addresses the state’s population and economic growth.
Saying he senses ERCOT conducts its various modeling studies in silos, Commissioner Jimmy Glotfelty asked Hobbs whether staff could combine some of that analysis.
“I think this will have an impact on inverter-based resources [in the Permian],” he said. “It will have [an] impact on what we can import to that area and export out of that area, and I just think we need to have a better picture with all of those things modeled together.”
Hobbs said one of ERCOT’s key goals is evolving the transmission planning process. Staff already are studying 765-kV transmission lines and their integration into the grid. Hobbs promised a report will be delivered to the commission this summer.
“We’re moving on a fast timeline,” she said. “We recognize the tremendous load growth on the system. We also recognize that the types of resources that are being added to this system are not the traditional resources that we want to plan for. We are looking at ways that we can continue to evolve the process to meet the needs for the fast-growing state.”
The Permian Basin encompasses 66 counties in southeastern New Mexico and western Texas. It produces nearly 40% of the nation’s oil and roughly 15% of its natural gas, according to the Federal Reserve Bank of Dallas.
Other Business
In other actions during the open meeting, the PUC approved a 150-MW El Paso Electric (EPE) solar facility (54929) and Xcel Energy subsidiary Southwestern Public Service’s (SPS) rate case (54634).
EPE’s Texas Solar One is composed of two components: a 50-MW portion the utility plans to dedicate to a voluntary subscription program and a 100-MW portion to serve retail customers. Under an agreement with the city of El Paso, the Office of Public Utility Counsel and Texas Industrial Energy Consumers, EPE will place a capital cost cap on the facility and add a performance guarantee and a commitment to credit its customers with 100% of Texas Solar One’s production tax credits.
The commission signed off on an unopposed agreement between SPS and various parties that provides for a $65 million increase in the utility’s Texas retail revenue requirement.
FERC has approved a proposal by ISO-NE reducing its Forward Reserve Market (FRM) offer cap from $9,000/MW-month to $7,100/MW-month and delaying the publication of offer data from about four months to a year after each auction (ER24-1245).
ISO-NE designed the market changes in response to concerns raised by its Internal Market Monitor that recent summer FRM auctions had been “structurally uncompetitive” and that future auctions could be susceptible to market power.
The IMM concluded the previous $9,000 offer cap “substantially overstates a reasonable upper bound on competitive forward reserve supply offers,” while the shorter timeline for offer publication “may provide strategic information to participants” in subsequent auctions.
In an April 12 order, FERC found that the offer cap reduction provides “sufficient flexibility for resources to participate at their expected costs within the upper end of a competitive offer, while also providing protection from the potential exercise of market power.”
Then commission also found the delay of offer data publication “balances the need for market transparency with the need to limit the possibility that market information may lead to noncompetitive outcomes.”
The changes take effect on April 15, 2024, in time for the opening of the first 2024 FRM auction April 17.
Two competing day-ahead markets from CAISO and SPP are taking different approaches to resource sufficiency and adequacy, according to presenters at a workshop included in an effort that will likely help shape NV Energy’s decision on which market to join.
The Public Utilities Commission of Nevada (PUCN) hosted the workshop April 10 to discuss regional market designs.
In CAISO’s Extended Day-Ahead Market (EDAM), balancing areas will undergo a daily resource sufficiency evaluation (RSE) ahead of the market’s 10 a.m. cutoff.
The balancing areas will work with their load-serving entities and suppliers to ensure sufficient resources and transmission are available to the market, said CAISO Chief Operating Officer Mark Rothleder. The resources must be enough to meet the demand forecast, plus an operating reserve and an imbalance reserve.
Resources from all participating balancing areas will then be optimized to meet demand across the market and minimize cost, Rothleder said. Entities that don’t pass the RSE will still be able to participate in the market but will be charged a premium.
In contrast, SPP’s Markets+ day-ahead market will not use a daily resource sufficiency test, said Carrie Simpson, SPP’s director of services development.
Instead, all load-serving entities in Markets+ must belong to Western Power Pool’s Western Resource Adequacy Program (WRAP), which SPP runs.
The WRAP includes a forward-showing component that will require participants to demonstrate they have sufficient capacity and 75% of the transmission needed to deliver it seven months before each summer and winter. Those who fail the requirement will face penalties.
Simpson said obligations coming out of WRAP will inform a day-ahead market participant’s must-offer requirement, “so that we ensure that we have sufficient generation offered into the market.”
SPP “heard loud and clear” from entities participating in the development of Markets+ about the need for a uniform resource adequacy program, Simpson said.
“In Markets+, we have a uniform approach so everyone’s on the same playing field,” Simpson said. “To the extent that someone is short today, well, they’re part of the larger program, and we’ll have the capability to have someone else offer for them, and so you get that shared pooling advantage.”
Rothleder, with CAISO, described EDAM’s resource sufficiency evaluation as “a universal adapter” that can accommodate WRAP, California’s resource adequacy requirements or other RA programs.
Resources developed under the RA programs can then be used to satisfy resource-sufficiency evaluations, he said.
“I am not suggesting resource adequacy programs are not important. They are very important,” Rothleder said. “All I’m suggesting is that you don’t have to have a one-size-fits-all resource adequacy program for a day-ahead market optimization to work.”
The RSE may even be a way to compare different resource adequacy programs, Rothleder suggested.
“To the extent that the resource adequacy program is performing less than another resource adequacy program, that will be tested by the resource sufficiency evaluation,” he said.
Competition Heats up
The workshop was part of PUCN’s efforts to find ways to evaluate a utility’s choice of a regional market or RTO. An April 3 workshop focused on studies of day-ahead market benefits. (See Nev. RTO Effort Turns Focus to NV Energy Day-ahead Studies.)
NV Energy and other utilities across the West are drawing closer to decisions on which day-ahead market to join. Some have already chosen.
PacifiCorp, the Balancing Authority of Northern California (BANC) and Portland General Electric are among the entities pursuing EDAM membership. CAISO is aiming to launch EDAM in 2026.
NV Energy hasn’t revealed publicly its day-ahead market choice. The utility was among more than three dozen entities that participated in developing tariffs and protocols for Markets+, in a process SPP calls Phase 1, but a recent study by The Brattle Group found the utility would realize greater financial benefits from joining EDAM. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.)
Phase 2, expected to start next year, will begin Markets+ implementation, with a go-live date projected for early 2027.
Antoine Lucas, SPP’s vice president of markets, said SPP is asking its Phase 1 participants to indicate this quarter whether they’ll be moving forward with Markets+, even if their commitment is nonbinding at this point.
“I know there is some level of … participants looking to each other to see what they might do,” Lucas said during the workshop.
When asked what level of participation would be needed to make Markets+ feasible, Lucas said Phase 1 participants decided that 150 TWh of net energy for load annually and two contiguous balancing areas would be enough to move forward.
WEIS’ Role Clarified
Some entities that join Markets+ might now be participating in CAISO’s real-time Western Energy Imbalance Market (WEIM). In that case, they would leave the WEIM and instead participate in a real-time market that is bundled with the Markets+ day-ahead market.
The real-time market associated with Markets+ is different from SPP’s Western Energy Imbalance Service (WEIS), a real-time market now in operation, SPP officials noted during the workshop.
Current WEIS participants, mainly from Wyoming and Colorado, are expected to join Markets+ or SPP’s planned Western RTO expansion, known as RTO West. At that point, SPP expects to discontinue the WEIS, Simpson said.
The U.S. Department of Energy released a study of offshore wind transmission last month,1 which it said charts a path for a reliable and affordable electric system with HVDC backbone transmission interconnecting offshore wind projects along the East Coast.2 (See DOE Study Adds to Case for Interregional Offshore Grid.)
For starters we need to be clear: In no way does this study establish, or even claim, that offshore wind makes economic sense. Of course it couldn’t, for reasons I’ve given before,3 which are reinforced by all the news of the past year or so.4 Instead, we should be building onshore wind and, where economic, transmitting it from west to east.
What the study actually claims is that hypothetical offshore wind projects of 85 GW along the East Coast, if interconnected among themselves with an offshore transmission “backbone,” would have a positive cost-benefit ratio relative to 85 GW of wind projects separately interconnected to shore with “radial” lines.
In other words, the study claims that if we were to spend $96.3 billion5 on radial transmission lines for 85 GW of offshore wind, it would make sense to spend another $20 billion for offshore north-south HVDC transmission lines to interconnect everything offshore — and, oh yeah, based on year 2050 projections of everything.
Now let’s get to some specific problems with the study.
Legal and Commercial Barriers
Because offshore wind is so expensive, it happens only with large customer (and taxpayer) subsidies through a given state procurement program. For example, in New Jersey’s latest procurement, the developer is receiving $131/MWh in offshore wind renewable energy credits (ORECs) with a price escalator.6 Such procurements effectively or literally require all the wind generation to be delivered to the procuring state.7
Even if a developer were legally able to divert some generation elsewhere, it would have no reason to do so under programs like New Jersey’s where all project revenues are credited back to customers.8 And even if there were no revenue-crediting requirement, a developer isn’t going to divert wind generation elsewhere, such as to New York, except in hours when it could get more than $131/MWh.9 This rarely occurs, and when it does, it is likely that energy prices in New Jersey also would be high.
Energy Price Differences
Assuming the above legal and commercial barriers didn’t exist, let’s examine the study’s principal economic benefit claim: There are huge price differences between different East Coast regions such that there are huge customer savings to be had from moving power up and down the East Coast for injection onshore at different points. “In modeled estimates using the radial topology in 2050, price differences between suitable POIs [points of interconnection] for offshore wind averaged over $100/MWh”;10 for example, “approximately $130/MWh on average between ISO-NE and SERC.”11
This appears to be a mistake. For the year 2050, DOE’s Energy Information Administration projects average generation sector prices of $66.8/MWh in New England and $54.7/MWh in SERC East (South Carolina and the non-PJM portion of North Carolina).12 That is a difference of about $12/MWh, not $130/MWh. The biggest regional price difference is between New England and PJM-East (which contains New Jersey and the Delmarva Peninsula) with a difference of about $16/MWh.13 So there are no $100/MWh average regional price differences that an offshore transmission backbone could arbitrage for the benefit of customers.14 And even if there were, stakeholders subsidizing their state’s wind projects would be none too happy for their wind to be diverted elsewhere in times of high prices.
Oh, by the way, the study’s specific quantifications of customer energy savings are based on a production cost model.15 But, except for the Carolinas and Virginia, customers don’t pay production costs; they pay LMPs.
And the study also implicitly assumes, contrary to actual experience, that resources could and would be dispatched efficiently among regions.16
Resource Adequacy
The study’s second biggest category of claimed benefits is resource adequacy. The study claims $940 million of incremental annual resource adequacy benefit in 2050, relative to a radial transmission design.17 The prime example is that PJM could rely on wind off the Carolinas to be delivered to PJM during peak conditions so the RTO would need less internal generation capacity.18
This also appears to be a mistake. PJM has FERC-approved capacity market rules to ensure resource adequacy that require external generation resources to give operational control to PJM so that external resources are functionally equivalent to internal resources.19 Stakeholders in wind projects off the Carolinas are not going to give PJM operational control.
And if I might pick a nit, the study says Carolina wind would be delivered to “winter-peaking parts of PJM” and specifies Maryland.20 None of the coastal states in PJM are winter peaking, including Maryland.21
Modeling Assumptions
The study has a couple modeling assumptions that seem to put thumbs on the scale.
First, the study assumes “limited [new onshore] interregional transmission.”22 Yes, despite new onshore interregional transmission being all the rage these days, the study assumes nothing is built for the next 26 years.23 If new onshore interregional transmission were built, any price/cost differences would decline as more energy would be deliverable from low-cost areas to high-cost areas, and backbone offshore transmission would be less valuable.
Second, the study assumes “limited-access siting regimes for land-based wind and utility photovoltaics.”24 This assumption is not explained, but it seems safe to observe that if one assumes limited onshore renewable resources, offshore resources will look more attractive. This assumption is belied by the hundreds of gigawatts in proposed onshore renewable resources.25
Incremental Annual Cost
In developing its benefit-cost ratios, the study doesn’t provide detail for its capital costs.26 But the study does drop a footnote for its assumptions on converting capital costs to annual costs,27and we can back into the annual costs. So, for example, comparing the radial scenario with the backbone scenario, we know that if claimed incremental “economic value” is $3,940 million28 and if claimed incremental “net annual value” is $2,470 million,29 then the implied annual cost is $1,470 million.
If the incremental capital cost is $20 billion and the annual cost is $1,470 million, then that means the assumed annualized cost percentage is 7.35%. But that is not realistic. For example, the annual carrying charge rate for transmission owners in PJM is about 11.8%,30 and annual O&M expense is on top of that.
Engineering Feasibility
I am no engineer, but there is an Argonne National Laboratory study that says HVDC systems can’t have more than five substations: “The number of substations within a modern multi-terminal HVDC transmission system can be no larger than six to eight, and large differences in their capacities are not allowed. The larger the number of substations, the smaller may be the differences in their capacities. Thus, it is practically impossible to construct an HVDC transmission system with more than five substations.”31 And National Grid describes major issues with multi-terminal HDVC systems.32
The DOE backbone design has 26 substations.33 How does that reconcile with the Argonne and National Grid analyses? I have no idea, but these are things the study should have addressed.
And there’s another potential engineering issue called the “most severe single contingency,” which involves the sudden loss of a single source of electric generation, generally around 1,200 MW. It is unexplained how aggregated offshore wind generation delivered onshore in excess of the MSSC would not trigger reliability and reserve issues.
What Else Could Possibly Go Wrong?
Spend $20 billion here, $20 billion there, and pretty soon we’re talking real money. And those who might rationalize spending “only money” on offshore wind backbone transmission should consider how much a focus on standard design among offshore transmission projects, in order to enable backbone transmission, might delay or even frustrate such projects.
In Conclusion
DOE should rethink this.
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
[13] From north to south, EIA projects average generation sector prices in 2050 to be: $66.8/MWh in NPCC-New England, $61.8/MWh in NPCC-New York City and Long Island, $50.7/MWh in PJM-East, $50.8/MWh in PJM-Dominion, and $54.7/MWh in SERC-East. Tables 54.7, 54.8, 54.10, 54.13 and 54.14.
[14] Perhaps the study meant to say that there are some hours with at least a $100/MWh price difference and that the average price difference of those hours is more than $100/MWh, which of course it would be by definition. Who knows?
[21]https://www.pjm.com/-/media/library/reports-notices/load-forecast/2024-load-report.ashx, Tables B-1 and B-2. Taking Maryland as the example given in the study, the summer peak loads for the furthest year out, 2039, are 7,495 MW for Baltimore Gas and Electric and 6,870 MW for Potomac Electric Power Co., relative to their respective winter peak loads of 6,803 MW and 6,081 MW.
