President Joe Biden on April 22 announced $7 billion in funding from the Inflation Reduction Act, to be used by states and nonprofits across the country to install solar in low-income and disadvantaged communities.
The Solar for All grants, part of the IRA’s Greenhouse Gas Reduction Fund, will fund 60 programs aimed at installing solar on low-income single-family and multifamily homes, as well as building community or shared solar programs that target consumers, such as renters, who cannot put solar on their roofs.
EPA, which is administering the program, estimates that Solar for All projects could save more than 900,000 households in low-income and disadvantaged communities $350 million annually.
Consumers who sign up for community solar programs typically receive credits on their utility bills. The selected awardees all have committed to providing at least 20% savings on utility bills for all households served by their projects, according to a senior administration official speaking on background.
Speaking in Prince William Forest Park in Virginia, Biden estimated households benefiting from Solar for All projects would save about $400 per year on utility bills.
“Energy costs are among the biggest costs for families … particularly for middle-income families,” he said. “In fact, low-income families can spend up to 30% of their paycheck on their energy bills. It’s outrageous.
“Solar for All will give us more breathing room and cleaner breathing room.”
The program also could add about 4 GW of distributed solar to local electric systems while cutting the equivalent of 30 million metric tons of carbon dioxide, according to EPA.
EPA Deputy Administrator Janet McCabe provided a breakdown of the funding during an April 19 press call: $5.5 billion will go to 49 state-level awards, $500 million to projects in tribal communities and $1 billion to multistate organizations serving low-income communities not well served by the private market.
Grant amounts range from $43.7 million to $249.8 million.
The multistate grants will “focus on low-income communities; communities around historically Black colleges and universities, Hispanic-serving institutions, and tribal colleges and universities; households served by rural and municipal electric co-ops; families in the industrial heartland; and low-income customers who are unable to build rooftop solar but could still benefit from community solar,” McCabe said.
The Clean Energy Fund of Texas will partner with the Bullard Center for Environmental and Climate Justice at Southern Texas University to provide technical assistance and grants for community solar projects in “low-income and disadvantaged communities on the frontlines of energy policy and grid vulnerability challenges,” according to EPA.
These projects also could include energy storage, to deliver “grid and community benefits by powering community resilience centers,” EPA said. While based in Texas, the program will fund projects in 19 Mid-Atlantic and Southeastern states, from Pennsylvania to Texas.
“EPA’s Solar for All awards will mean that low-income communities, and not just well-off communities, will feel the cost-saving benefits of solar,” John Podesta, White House senior adviser for international climate policy, said in a statement.
“Residential solar electricity leads to reduced monthly utility bills, reduced levels of air pollution in neighborhoods and ultimately healthier communities,” said Adrianne Todman, acting secretary of the Department of Housing and Urban Development.
Biden noted that Prince William Forest Park, now part of the National Park System, originally was developed by the Civilian Conservation Corps, a jobs program President Franklin D. Roosevelt launched in 1933.
The CCC was part of the inspiration for the American Climate Corps, which Biden also announced would accept applications for its initial 2,000 positions via a new website. First proposed in 2021, the initiative aims to provide corps members with jobs and training to mitigate climate change.
As part of the corps, they also will be able to access the North America’s Building Trades Unions’ (NABTU) apprenticeship-readiness program, Biden said. And the U.S. Office of Personnel Management will expand eligibility for federal employment to individuals who have completed qualifying career or technical education through Climate Corps programs.
Reactions
Clean energy and environmental advocates were mostly supportive of Solar for All while also warning of potential obstacles ahead.
Jeff Cramer, CEO of the Coalition for Community Solar Access, said the $7 billion in federal funds could “unlock multiples of private capital. … Community solar is a critical tool in the broader toolbox of distributed solar options for American households.”
Chelsea Barnes, director of government affairs and strategy for the nonprofit Appalachian Voices, called the program “a game-changer for so many under-resourced and environmental justice communities seeking a more sustainable, reliable, democratized energy system.”
“For vulnerable households that depend on electricity for their health and security, the solar and battery storage systems resulting from Solar for All could act as a literal lifeline during times of emergency,” said Marriele Mango, project director for the Clean Energy Group, which will receive funding from Solar for All as part of the Community Power Coalition.
But “smart state energy policies and streamlined implementation will determine whether American families ultimately see the savings from Solar for All on their electric bills,” said Harry Godfrey, managing director at Advanced Energy United. He pointed to “lengthy and burdensome interconnection requirements, bureaucratic permitting processes, and state energy policies and regulations that undervalue or simply obstruct community and distributed solar.”
In addition, awardees still must negotiate and finalize agreements with EPA before they can access the funds. EPA estimates all contracts will be finalized by Sept. 30.
FERC is set to vote on its long-awaited proposed rule on transmission planning and cost allocation for regional lines at a special open meeting May 13, the commission announced last week ahead of this month’s usual meeting (RM21-17).
Parties who have worked on the rule spoke with RTO Insider and in other venues April 22 about what they expect to see from the commission.
“I want to make sure that it’s sufficiently strong so that planners really do plan for the anticipated resource mix; so they actually are required to consider all the factors of what that future resource mix looks like,” Grid Strategies President Rob Gramlich said in an interview. “I want to make sure there’s an actual decision that gets made about cost allocation.”
States should obviously participate in the cost allocation process, Gramlich said, but if they cannot agree, the process should not end there; FERC should do something to move the ball forward.
The two biggest precedents in FERC’s allocation regime can often come into conflict, former Arkansas Public Service Commission Chair Ted Thomas said on a webinar hosted by the Conservative Energy Network (CEN). The ideas that beneficiaries pay, and costs are commensurate with benefits, can often clash.
If a group is having dinner at a restaurant and only one diner orders dessert to share with the table, that person effectively caused the cost, but anyone who has a morsel will be a beneficiary, said Thomas, who runs a consulting firm.
“These two principles are in conflict,” Thomas said. “Because it’s really hard to get everybody on board in the same way on the front end so that they’re all the cost-causers. But with 20/20 hindsight, when you can see that somebody benefits — well, under this other principle they’re supposed to pay. But at the end of the day cost allocation is always about negotiation.”
The rule will not change the fact that ultimately, states and other stakeholders need to negotiate over transmission cost allocation, Thomas said, but hopefully it will add guidelines to simplify that process.
The issue of cost allocation is one area where FERC’s internal debates have spilled out into public somewhat, with Commissioner Mark Christie repeatedly saying he does not want to see one state pay for another’s policies, most recently in response to a letter from a group of congressmen led by Rep. Andrew Garbarino (R-N.Y.).
“It would be grossly unfair for FERC to force consumers in other states to pay for projects implementing the policies of politicians they never got the chance to vote for, when their own states’ policymakers have not agreed to pay for those projects,” Christie said in his response. “Such an imposition is contrary to American principles of democracy, a core principle of which is that the people have the right to elect the policymakers who impose costs on them, so the people can hold them accountable.”
Commissioner Allison Clements wrote less in response to Garbarino, but she argued that the costs of failing to invest in the grid, from customers facing huge bills from last-minute reliability needs to economic development going elsewhere, need to be considered.
“The risks and costs of declining to plan holistically for a modern grid may far outweigh the short-term lure for states to ‘go at it alone’ from a transmission planning perspective,” Clements wrote.
While public policy has generated plenty of debate beyond two of FERC’s three commissioners, Clean Energy Buyers Association Senior Director Bryn Baker told the CEN webinar that is not a focus of the proposed rule.
“Public policy — I think we need to be clear that unless there’s a dramatic reversal, is not in the list of things to evaluate the need for these lines,” Baker said. “It’s not in the goal as one of those metrics. I think that was a smart decision.”
State renewable portfolio standards are not driving as much of the need for new transmission as the corporate renewable energy buyers that CEBA represents are, she added. Coupled with growing demand, getting enough supply online to secure new industries that face international competition should be key goals when considering building out the grid, she said.
MISO’s Multi-Value Project lines have helped bring online many new renewable generators, but those were much less focused on policy than reliability and economics, Gramlich told RTO Insider.
“The state policies, even in MISO, weren’t even really binding,” Gramlich said. “They would have had the same results even if they completely ignored them. So, the point is, look at the economics of generation and anticipated additions and retirements over this 20-year period. And then design the network that achieves the lowest delivered costs for consumers; and any region should be able to do that.”
Thomas said that Arkansas did give up some of its authority when it pushed Entergy into MISO, but he said that the deal was worth it.
“Do I worry about state jurisdiction? I really don’t,” Thomas said. “Particularly if you’re in a … market already, there’s some jurisdiction you give up to save $50 million a year. … You’ve bound yourself to work with other states that share these resources. But for $50 million a year that goes straight into ratepayers’ pockets, it’s worth it.”
MISO might be ahead of the other RTOs when it comes to planning, but Thomas said it was in a class of organizations that could all use improvements.
While the devil is in the details, the broad strokes of FERC’s proposal requiring proactive planning have wide support, as 174 organizations, including 59 consumer groups, supported the rule in their comments to the commission, Gramlich said.
The Future of Transmission Competition
Another issue dividing stakeholders is FERC’s proposal to pull back on Order 1000’s elimination of the federal right of first refusal for regional transmission lines, finding it caused incumbents to focus on local projects not subject to competition.
Many utilities want to see FERC at least stick with that proposal, while supporters of competition are going to appeal if the commission follows through with it.
“So, No. 1: FERC has got to tackle the competitive transmission issues they’ve teed up and re-examine rights of first refusal,” WIRES Group Executive Director Larry Gasteiger said in an interview. “I think if that’s not in there, it would kind of be a major disappointment.”
FERC has acknowledged that Order 1000 is not working correctly and the policies around ROFRs need to be reformed, he added.
The opposite needs to happen, according to Paul Cicio, chair of the Electricity Transmission Competition Coalition, made up of firms engaged in competitive transmission development and consumer groups.
“If [FERC] doesn’t embrace competition; if it doesn’t enforce Order 1000, this will be most likely the most costly consumer rule in history,” Cicio told RTO Insider. “And it’s because of the sheer magnitude of the amount of capital that is and will be spent on transmission going forward.”
Competition can serve to contain the costs of transmission, which has granted very healthy returns that stay in place for decades, he added. The price of electricity has outstripped the Consumer Price Index in terms of inflation, and in cheap natural gas and other forms of generation, transmission and distribution costs have been rising, Cicio said.
The returns on investment of 10 to 12% are very high when compared to the manufacturing industry, which Cicio also represents, and he would like to see FERC tackle cost-containment issues more generally.
Cost containment came up in many of the comments, but Gasteiger said it was not really addressed in the proposed rule.
“We’re hoping that they don’t try to add it in now, given that they haven’t really provided notice on it,” Gasteiger said. “But I know there was a lot of pressure from different commenters for FERC to weigh in on that issue.”
Any rule of this scope from FERC is guaranteed to be challenged in court; ETCC has already said it would appeal the final rule if the commission reinstates the federal ROFR, which Cicio reiterated. (See Pro Competition Group Plans to Sue if FERC Reinstates Federal ROFR.)
The Reserve Certainty Senior Task Force (RCSTF) is considering two proposals from PJM and the Independent Market Monitor aimed at improving the performance of reserve resources.
Stakeholders have been tackling reserve performance since the response rate for committed resources has fallen after a market redesign consolidated the Tier 1 and 2 synchronized reserve products and lowered the offer cap from $7.50/MWh to 2 cents. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
The PJM package would allow operators to modify the procurement targets for 30-minute reserves without having to do so for synchronized and primary reserves and create a formula for dynamically changing the 30-minute reliability requirement, PJM’s Emily Barrett told the RCSTF during its April 17 meeting. The calculation would use the larger of the primary reserve requirement, the largest active gas contingency and the average load forecast error, plus the average forced outage rate. The requirement is set at 3,000 MW, which was double the largest contingency when the requirement was established.
The changes would align the 30-minute reserve requirement with the breadth of operational risks dispatchers face and would grant flexibility to increase those reserves during periods of increased risks, such as harsh weather conditions, Barrett said.
PJM’s Lisa Morelli said staff will draft manual language and more details to present to stakeholders for a potential first read during the May 15 RCSTF meeting, with the intention of holding a vote June 12.
Monitor Focuses on Communications
The Monitor’s proposal would focus on getting reserve dispatch signals to generators in a manner that they can act on as quickly as possible. Joel Luna, of Monitoring Analytics, said the Monitor and PJM have been speaking with generation owners about the root causes of poor reserve performance since last spring and found that lags in communication can lead to generators not initiating their response until minutes after PJM has begun a reserve deployment.
Pointing to a synchronized reserve event Feb. 24, 2024, Luna said about 61% of the 1,882 MW resources deployed did not meet their assignment, of which he said 1,041 MW underperformed due to communication issues. Some units were waiting for a phone call from PJM to confirm their deployment. Others experienced lag between when the all-call signal was initiated by PJM and when it was received on their end due to how those generation owners relay signals between their control centers. And some experienced lag from the required switch to manual ramp from automatic dispatch signal.
The Monitor’s proposal would replace all phone communications used to convey deployment orders with automatic electronic signals and would include the deployment MW generators are being assigned through the existing security constrained economic dispatch (SCED) signals.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said many generators are being asked to run at a loss when providing reserves and compensation needs to be addressed alongside the communication issues.
“Prices need to reflect the system conditions, and clearly that’s not the case here,” he said.
Tom Hyzinski of the GT Power Group said adopting the Monitor’s recommendations could resolve some of the issues in the reserve market and clear the air to simplify addressing any remaining design issues. So long as all other options remain on the table should the proposal be endorsed, he argued there are no downsides to advancing the Monitor’s changes.
PJM and the Independent Market Monitor presented the Deactivation Enhancement Senior Task Force (DESTF) with two proposals increasing the notification generators seeking deactivation must provide PJM and standardizing compensation for those that agree to continue operating beyond their desired retirement date.
Speaking at the April 15 task force meeting, Monitor Joseph Bowring said that when requesting payment for reliability-must-run (RMR) contracts, generators include a combination of sunk costs and estimated costs in an artificial regulated utility rate case framework that results in significant overcompensation. RMR contracts are needed for generators that want to retire but which the RTO has determined must remain online to maintain reliability for a period that can extend to five years or longer.
Bowring argued the current practice is inefficient and creates uncertainty for all parties as settlement discussions last for years. He said the Monitor’s first principle is that compensation rules should be clear and unambiguous. Under the Monitor’s proposal, generators would be paid the actual costs the generation owner would incur in keeping the unit online, net of any revenues the unit received through PJM’s markets, plus an incentive. There would be a verification process for all such costs.
The proposal would allow generators to include in their RMR compensation: actual maintenance costs; short-run marginal costs, such as fuel and consumables; and new investments needed for the generator to remain available, along with an incentive payment calculated as a percent of incurred costs. Costs related to general overhead, artificial utility rate case elements, and previously incurred capital and inventory costs would not be included.
Generators seeking retirement would be required to notify PJM of their intent six to 12 months in advance of the capacity auction for the delivery year in which the unit would go offline, with the aim of giving other market participants time to offer resources that could resolve reliability needs prompted by the deactivation.
Resources operating on an RMR contract would be dispatched only when required for reliability and would not be included when calculating the capacity emergency transfer objective and capacity emergency transfer limit values, which are inputs used to determine the amount of capacity PJM aims to procure through Base Residual Auctions (BRAs). Market sellers operating on an RMR contract would not receive capacity performance (CP) bonus payments, nor would they be subject to underperformance penalties during emergency conditions. Bowring has argued that including RMR units in the capacity market and resource stack suppresses prices that could incentivize new generation.
Bowring also argued PJM should use the same reliability criteria in defining the demand in the capacity market as it uses to define the need for an RMR contract. Currently, a unit could fail to clear in the capacity market but be deemed necessary for reliability and thus eligible for an RMR contract.
Christian McDewell, of the Pennsylvania Public Utilities Commission, said FERC rejected limiting bonus payments to capacity resources and excluding energy-only resources when it rejected changes to the CP design PJM proposed following the critical issue fast path process (ER24-98). (See FERC Rejects Changes to PJM Capacity Performance Penalties.)
Bowring said consumers shouldn’t have to pick up all the costs of keeping a fuel production facility operational in addition to the marginal costs to keep the generator online. He added that potential interactions between RMR compensation and fuel procurement warrant further stakeholder consideration.
Responding to stakeholder questions of whether PJM should be granted the ability to mandate RMR contracts, Bowring said he believes that would be unnecessary if the RMR design ensures contracts provide appropriate revenues for generators contemplating deactivation. Bowring stated that compensation should be the same in both cases and cover all actual costs of being an RMR unit plus an incentive.
PJM Proposal Centers on Notification Deadlines
The PJM package focuses more heavily on the notification requirements for deactivation and leaves compensation changes for further stakeholder deliberation. The proposal groups deactivation requests into three classifications based on the energy that would be brought offline: Requests larger than 300 MW would be required to provide notification three years in advance of their desired deactivation date; units between 100 MW and 300 MW would require one year’s notice; and those under 100 MW would follow the status quo 90-day period.
The notification period could be curtailed under PJM’s proposal if the capacity auction for the delivery year in which the resource would go offline is after the notification deadline. In such cases, generators could submit a deactivation request before the deadline for them to offer into the BRA.
Generators also would be permitted to retire earlier if PJM finds no reliability violations from by taking the unit out of service.
FERC on April 19 conditionally accepted Oklahoma Gas and Electric’s (OG&E) proposed formula rate template revisions effective Jan. 1, 2024, as requested. The commission also directed OG&E to submit a compliance filing within 30 days of the order (ER24-722).
The commission found several errors and inconsistencies in OG&E’s proposed worksheets and formulas. It said the inclusion of populated plant balances, depreciation expense and revenue requirement for SPP allocation were not shown to be just and reasonable and ordered the company to remove the data in the compliance filing.
OG&E filed the revisions in December. It requested a waiver of the commission’s 60-day prior notice requirement so an effective date of Jan. 1, 2024, could be set. The company said allowing the proposed changes to take effect at the beginning of the rate year would avoid a midyear formula rate change and simplify the future calculation of the true-up adjustment.
Western Farmers Electric Cooperative, Arkansas Electric Cooperative Corp. and Oklahoma Municipal Power Authority, all OG&E customers, protested the filing. They argued the company did not provide sufficient information to back up its claim that the formula rate changes were “exclusively ministerial.”
FERC disagreed, finding the revisions are just and reasonable, pending OG&E’s compliance filing.
“We find that the revisions … are ministerial in nature and do not change the methodology by which the rate is calculated and will have no effect on rates,” the commission said. It noted the revisions will make the formula rate template easier for interested parties to review during the annual update process.
ERCOT last week told stakeholders that its staff are not supportive of modifications to the calculation of ERCOT contingency reserve service (ECRS) after recent changes resulted in lower quantities of the product this year.
ERCOT’s Nitika Mago told the Technical Advisory Committee on April 15 that last year’s annually required review of ECRS methodology, reduced 2024 quantities by an average of 442 MW in each hour. That is about a 21% reduction in the service, she said.
“We, as we do every year, will continue to see if there are any improvements that can be made,” Mago said. “We’ll continue to work on the analysis … but at least we’re getting ready for where we want to be.”
ERCOT has drafted a nodal protocol revision request (NPRR1224) creating a trigger allowing staff to manually release ECRS from dispatchable resources earlier than they did last summer. Stakeholders have requested additional analysis on the measure and have tabled it at the Protocol Revision Subcommittee, pushing off any likely decision until midsummer. Staff said that without the guidance on an “appropriately balanced ECRS deployment trigger,” they will release the product in a similar manner to last year.
“I think we do see this as a good step forward,” Jeff Billo, ERCOT’s director of operations planning, said of the NPRR. “We see other steps being necessary, but we see this as a good initial step forward.”
ECRS was deployed last June as ERCOT’s first new ancillary service in 20 years. The grid operator’s Independent Market Monitor said in December that ECRS has created artificial supply shortages producing “massive” inefficient market costs, totaling about $12.5 billion last year through November.
Staff promised last year to re-evaluate ECRS and share the results with stakeholders by April 30. They said a holistic review of the entire ancillary service methodology could soon be necessary. That same review would better address some of the IMM’s concerns, Mago said. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.)
Mark Dreyfus, representing a coalition of Texas cities, urged for a deeper review of the IMM’s $12.5 billion figure to determine whether ERCOT induced congestion by holding excess reserves out of the energy market.
“I’ve asked, and I think others asked way back when this issue first started: Let’s all drill down; this is so important,” Dreyfus said, noting the wholesale market’s “potentially unnecessary expense.”
“Let’s drill down and find out if that really happened or what were the circumstances. I don’t think we did that drill-down, and this conversation has suffered from that,” he said.
ERCOT has disputed the IMM’s analysis, calling the numbers “unknowable.” Billo said the long-term cost is really the cost of capacity being set aside.
ERCOT’s Jeff Billo (upper right) explains staff’s thoughts on ECRS. | ERCOT
“We all understand that $12.5 billion is not a real number,” he said. “I think the calculation was probably correct, but it’s not a real number or indication of what actual costs are. We don’t even know if it’s even the right magnitude of cost. That that’s an unknowable number, because we don’t know how bidding and offer behavior would have changed.
“We don’t know what capacity may have decided they didn’t want to be there because of that change. So, I think we need to focus more on the fundamentals of what do we need and what are the cost[s] from a capacity standpoint,” Billo said.
Michele Richmond, executive director for the Texas Competitive Power Advocates trade association, argued that there would have been behavioral changes “because when you change how something works within the market, that is just a natural result.”
“What we have seen is that ECRS has sent a signal to the market that investment in dispatchable generation is needed in ERCOT. Investment decisions are not based on what happened in the past; they’re based on what the expectations are for the future,” Richmond said. “I think we need to be really cautious that we don’t chill that investment or send a message that we want reliability, but it can’t cost anything, because that’s also not realistic. A balance needs to be struck. I think that making sure what we do is the right thing for the market — not just this summer and next summer, but in the long term — is really critical.”
ERCOT: Remand IBR Rule
ERCOT plans to recommend that the Board of Directors this week remand a controversial rule change to TAC, against stressing the risk to grid reliability, staff told members.
“We still have concerns about the reliability implications of [NOGRR245] endorsed by TAC,” Dan Woodfin, ERCOT’s vice president of system operations, told TAC.
Woodfin said staff will recommend that TAC address the reliability concerns and either modify stakeholders’ proposed language or explain how the NOGRR addresses ERCOT’s reliability issues.
The NOGRR is intended to align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid. Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances I and II, have added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Stakeholders have proposed software changes to fix the issues NERC and ERCOT have identified. They have said ERCOT’s proposals, if approved, “will implement the nation’s most aggressive ride-through performance requirements to date.”
TAC in March approved amended language that stakeholders pushed through despite ERCOT’s objections. Stakeholders said the language was “carefully crafted” to reach a solution balancing risk mitigation with “economic, technological and operational realities.” (See ERCOT Technical Advisory Committee Briefs: March 27, 2024.)
“We would like to see this matter be resolved and the ERCOT board endorse the TAC-recommended comments,” said Eric Goff, who has led the stakeholder group opposing staff’s recommendation. “We might be in opposition to further remand and delays in limitation of these renewable resources. This is affecting real-world investment decisions every day, and we would like to get this matter resolved as quickly as possible.”
“Working towards more consensus is always beneficial. If there is a remand, does this end up just becoming an appeal back to the board, or is there a path to further consensus or possibly strumming the ukulele singing ‘Kumbaya?’” Luminant’s Ned Bonskowski asked Woodfin. “We made a recommendation to the board, and the presumption was for a lot of us that there were going to be folks on both sides, and then the board would end up taking some action, and then there may be action further taken at the [Texas Public Utility] Commission level. I want to make sure that we’re moving forward in a way that will continue to sharpen the pencil, if it’s possible.”
“Part of the benefit of this remand will be to further flesh out all of the pros and cons of the different approaches on each of the many issues that we’re talking about,” Woodfin responded. “That will be in the record out in public, so that both the board and the commission will have all that in front of them and be able to see all the different moving parts as this goes forward.”
Goff said his group already has an “extensive and well developed record” addressing those questions and argued against further delays. A remand could push the NOGRR to the June or August board meetings. It will then still have to go before the PUC for final approval.
“The effective date for new resources could potentially be pushed even further, and we would really like to see this pass,” Goff said.
The board’s Reliability and Markets Committee will take up the NOGRR on April 22, and the full board will consider it the next day.
Key Date for RTC+B Project
Members endorsed a white paper detailing changes to the reliability unit commitment process necessary to co-optimizing energy and ancillary service procurements to meet forecasted load and ancillary service requirements.
The paper sets the guardrails for the Real-time Co-optimization plus Batteries (RTC+B) Task Force’s design work and its scope. The document has gone through three reviews without changes, said ERCOT’s Matt Mereness, the RTC+B’s chair.
“The white paper has dealt with the design elements we need to finish our design and begin building software. It sets the foundation that we will build from,” he said. “We don’t want to slow things down waiting to get the principles defined so the NPRR doesn’t get pulled in different directions other than this white paper.”
The white paper is the first of 20 issues the RTC+B team has identified and is addressing. Mereness said the task force is wrapping up its work on requirements and hopes to release a program timeline in September laying out the schedule for the remaining work. The project remains on track for delivery in 2026.
“At this point, 2026 is still the placeholder until told otherwise,” Mereness said.
ERCOT held the first of four technical workshops on the project April 19, sharing expected dispatch and data control changes. “These are really very technical workshops, which is why they have the word ‘technical’ in them,” Mereness said.
Hanson Rejoins Committee
National Grid’s Kevin Hanson has rejoined TAC in the independent power marketer segment. He received support from Pedernales Electric Cooperative’s Eric Blakey, who kiddingly said the “ever dependable” Hanson should be up for TAC’s Spirit Award.
“He has earned it,” said Blakey, chair of TAC’s Wholesale Market Subcommittee. “He’s currently chair of three working groups. We’re trying to take away one of his responsibilities, but he’s just done an amazing job stepping in.”
Hanson replaces Seth Cochran, who recently took a position with energy trader Vitol after 13 years at DC Energy. Cochran served on ERCOT’s board for five years (2016-2020).
$435M San Antonio Project OK’d
By unanimously approving its usual combo ballot, the committee endorsed ERCOT’s proposed $435 million San Antonio South Reliability II project addressing reliability issues south of the city.
The area has been plagued with significant congestion. The grid operator in February created four new generic transmission constraints in the area to limit power transfers in north-to-south and south-to-north directions.
The project will now go before the board for approval, as its price tag easily exceeded the $100 million threshold, requiring the directors’ approval.
ERCOT staff identified the project while studying a different proposal. ERCOT’s independent review found the project necessary under its and NERC’s planning criteria. Staff analyzed 15 options and shortlisted four before finding its preferred option.
The combo ballot also included NOGRR and Planning Guide changes (PGRR) that, if they go before the board and are approved, would:
NOGRR255: establish high-resolution data requirements.
PGRR112: set requirements for interconnecting entities to submit dynamic data models and for transmission service providers to submit final full interconnection studies for approval at least 30 business days before the quarterly stability assessment deadline.
A second combo ballot was conducted to allow for members’ abstention on two measures related to the use of electric service identifier IDs (ESI ID). The NPRR (NPRR1212) would clarify a distribution service provider’s obligation to provide an ESI ID for a resource site that consumes load other than wholesale storage load and is not behind a non-opt-in entity tie meter.
The cooperative segment abstained from the vote, which also included PGRR114, over complaints that the NPRR pre-empts the rights of co-ops and municipalities over access to their distribution systems.
In filings submitted to the Department of Public Utilities (DPU) on April 16, the Massachusetts Attorney General’s Office (AGO) and Department of Energy Resources (DOER) expressed concern about the climate effects of proposed utility supply contracts to keep the Everett Marine Terminal (EMT) LNG import facility operating until 2030.
Despite their concerns, the AGO and DOER did not recommend the DPU reject the utilities’ petitions, noting that the contracts may be needed to support the short-term reliability of the state’s gas distribution network. Instead, the AGO and DOER called on the DPU to make any approvals contingent on additional transparency and long-term planning requirements (DPU 24-25, 24-26, 24-27 and 24-28).
The contracts between four Massachusetts gas utilities and EMT owner Constellation are intended to keep the facility open through the winter of 2030. Everett’s main customer, Constellation’s Mystic Generating Station, is set to retire at the end of May of this year. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.)
With Mystic’s impending closure, Constellation can void the contracts if the utilities do not gain final approval from the DPU by May 1. This has led to expedited regulatory proceedings, in which state agencies and environmental groups have voiced concerns about the agreements’ projected $946 million price tag, as well as their alignment with the state’s decarbonization mandates. (See Everett LNG Contracts Face Skepticism in DPU Proceedings.)
In initial briefs filed April 16, the AGO and DOER expanded on their cost and emissions concerns and recommended additional guardrails to ensure the agreements do not hinder the state’s emissions reduction efforts.
“While the companies claim that the agreements are GWSA [Global Warmings Solutions Act] compliant, they have not provided any specific analysis to support these claims,” wrote the DOER.
National Grid, one of the state’s two major gas utilities, projects its gas demand to increase by about 11% by 2030, and its agreement with Constellation would allow the company to buy increasing amounts of LNG over the course of the contract.
The company argued in its initial brief that its agreement is needed to address “a deficit in the company’s available peak day and peak season resources.”
“The proposed agreement will not trigger any additional demand for gas,” National Grid wrote. “Any changes in demand in the commonwealth are independent of this proposed agreement, and customers will have the same demand for energy regardless of whether this proposed agreement is completed.”
Given the potential for gas demand to increase by the end of the agreements, the AGO stressed the need for the utilities to plan to develop an “exit strategy” from their reliance on Everett.
“Since 2015, [National Grid subsidiary] Boston Gas has taken no overt actions to address its readily apparent dependence on EMT,” the AGO wrote. “The company’s appetite for EMT LNG is only forecasted to burgeon four-fold over the next six years.”
Similarly, the DOER argued that “if the department approves the agreements, it should only be a short-term bridge to ensure reliability and must include a pathway to obviate each company’s need for EMT by the end of the contract terms in 2030.”
Throughout the proceedings, climate advocates have voiced concerns that the timing of the agreements lines up with the in-service date of a major pipeline expansion proposal for the Northeast. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)
The DOER recommended the DPU require the gas utilities to detail plans to “eliminate their reliance on EMT” in their Climate Compliance Plans due in the spring of 2025. The DOER also urged the DPU to mandate annual reports on gas costs, volumes, and third-party sales associated with the agreements.
These provisions are “essential in safeguarding consumers against the possibility that the companies would continue to be dependent on EMT in six-years or petition the department for approval of gas infrastructure alternatives that run counter to the Future of Gas principles or GHG emissions reduction mandates,” the DOER wrote.
Meanwhile, the AGO recommended annual reports from the utilities on their efforts to eliminate reliance on Everett, as well as on whether the agreements have aligned with the state’s decarbonization laws and the DPU’s recent “Future of Gas” orders, which discourage additional investments in gas infrastructure. (See Massachusetts Moves to Limit New Gas Infrastructure.)
Without such requirements, “ratepayers will again helplessly succumb to petitions by these LDCs [local distribution companies] for ongoing LNG supply from Constellation because, currently, these LDCs have no plan, obligation or intention [to] end their dependence on EMT,” the AGO wrote.
HOUSTON — The Gulf Coast Power Association’s 37th annual Spring Conference tackled the vexing assignment of how to reliably serve Texas’ unprecedented surge in demand with a cleaner energy supply.
The April 16-17 event featured experts from organizations trying to rise to the challenge and the companies behind the soaring demand.
“I just got to say it loud and clear: Since Uri, we’re too much talk and not enough cattle,” Hunt Energy Network CEO and former FERC Chair Pat Wood said during a keynote speech. “The fundamental fact is: We have told the world that Texas is ‘open for business.’ Everyone in this room believes it, and the world is responding. Companies are moving here in droves. People are flooding the state from both coasts.
“We’ve said we’re open for business, but we haven’t stocked the shelves. … We’ve invited gigawatts of new business and residential demand to come to our store, but we are woefully short on serving them.”
Wood said ERCOT needs to build a system that won’t “fail catastrophically from the center” but one that’s “redundantly resilient” to protect from overlapping risks. And Texas needs to unveil an “ERCOT 3.0” that adopts a “wartime-level sense of urgency,” upgrade the grid, streamline the interconnection queue and design pricing that inspires investors to build dispatchable generation without taxpayer subsidies. “Trucks and cranes from the Red River to the Rio Grande,” he said.
Wood also said Texas risks its “envy of the world” status in industry if it cannot employ creative solutions, including energy efficiency, load participation, and multidirectional flows on the transmission and distribution systems to unlock behind-the-meter generation.
“To paraphrase my old boss, we want no electron left behind. Let’s get back to work,” he said.
Wood said ERCOT’s future supply will be “digitalized, decentralized, diversified, democratized, dependable and decarbonized.” He said it’s ironic that Texas is at the vanguard of clean energy in a state that’s “almost embarrassed to talk about” climate change.
Outgoing Calpine CEO Thad Hill said it’s obvious Texas’ load is growing from data centers, manufacturing, natural gas and “maybe hydrogen.”
“This is more big-load-driven than it’s ever been. We’re talking about 300 to 400 MW hooking up to the grid at a time,” he said.
Hill said, however, he isn’t anxious over the future.
“What you’re going to hear from me is more hopeful,” he said. There’s cause for optimism because additions of price-responsive load are outstripping traditional load additions, and solar-and-storage combinations are blossoming, helping to solve ERCOT’s summer reliability issues.
Hill said ERCOT’s “major to do” should be creating a formal program for price-response load, more comprehensive than its existing Emergency Response Service. The hot summer and high prices in Texas in 2023 prodded new investment in dispatchable resources. He said gas plant plans in the ERCOT queue have doubled, with battery storage rising fivefold.
“Capital is flowing to dispatchable resources. … Gas is up; batteries are up. But man, we’ve got to find a way to institutionalize price-responsive load as a resource,” he said.
Hill also acknowledged that additions of short-duration battery storage have a ceiling on their usefulness.
“What happens when reserve events outlast the resources?” he asked, noting that ERCOT experienced two events upward of seven hours in which it needed consistent reserves, once in early September and once in early November. He said ERCOT should evaluate the duration it needs its ancillary services to last.
“Storage is doing great things for this market,” Hill said, but he urged market designers to be realistic about how long it can deliver. He said storage in ERCOT already has been found short of state of charge when called upon.
Hill advised Texas lawmakers to “take a legislative breather and let the experts work.” The legislature, which has been active the past two sessions, now needs to allow the Public Utility Commission’s and ERCOT’s plans to “take root.”
“We’ve got a good thing, though there’s been trauma along the way,” Hill said, referencing Winter Storm Uri. “I think we’re going to be just fine.”
On a panel concerning the “insatiable” demand for power, Entergy Texas CEO Eliecer Viamontes said his territory is seeing “once-in-a-generation load growth” that must be met with aggressive capacity buildout to elude load shed.
“This is game changing. We cannot propose incremental generation,” he said.
“I’ve been astounded at load growth. It’s something [that] 10 years ago, I wouldn’t have predicted,” said Jack Farley, HIF USA’s executive vice president.
Farley predicted about “one in five” of the approximately 60 GW of flexible load projects lined up in ERCOT’s queue will reach commercial operation.
“Nonflexible loads will have to become somewhat flexible going forward,” said Jeff Hanson, Digital Realty’s senior director of energy supply chain. It’s the “only way to address” infrastructure expansion failing to keep up with climbing load, he said.
Hanson said industry will remain drawn to Texas because of the welcoming regulatory climate that allows renewables to be built quickly, the “deep, deep pools” of sunshine and wind, the vastness of the state and the “lack of NIMBY-ism.”
Farley said behind-the-meter generation can help moderate runaway demand. Hanson added that large loads might consider adding their own onsite generation.
CenterPoint Energy Vice President of Regulatory Affairs Jason Ryan said Texas needs to employ an “all-of-the-above” strategy “to the max” to meet demand. With Houston’s energy needs set to double by 2050, he said the state already is behind in mounting major infrastructure buildouts. He asked the audience to consider the “100-plus years” it took for Houston to assemble its current grid.
Hanson predicted ERCOT will “be dancing on the edge” for a few tough years until infrastructure expansion can catch up.
Bryan Fisher, managing director of climate aligned industries at RMI, said industrial decarbonization alone could double the nation’s demand for power.
“Texas and the Gulf Coast are ground zero for industrial decarbonization,” Fisher told attendees. He said the Houston area alone has the potential to serve not only national demand for hydrogen, but the world’s market as well. He said RMI’s preliminary analysis shows Houston could be confronting 2.5 times its peak demand today by 2050 because of the added demands of industrial electrification, hydrogen production, and carbon capture and sequestration.
Calls for ERCOT Transmission Planning
Priority Power Director of Development Brian Hudson said a decade ago, forecasters talked about 300 to 500 MW of load growth. He said those figures exploded in recent years to gigawatts.
“It’s got to be stuff that we haven’t tried before to keep up with the pace,” he said.
He said in addition to dynamic line ratings, Texas should consider making it easier for behind-the-meter generation projects of 10 MW and above to interconnect to the distribution system and lighten load.
Kip Fox, president of Electric Transmission Texas (ETT), an American Electric Power and Berkshire Hathaway Energy partnership, said he’s trying to energize a new line but can’t get approval from ERCOT for the necessary outage of nearby equipment because of current levels of demand. He said if ERCOT doesn’t give the go-ahead for an outage soon, ETT likely will have to wait through the summer moratorium to energize the line.
“We’re not fast enough to build. … It’s not like we haven’t submitted ideas to build transmission. But at the end of the day, someone in the regulatory space is going to have to realize we need it,” Fox said.
Kris Zadlo, chief commercial and technology officer at Grid United, said it’s no longer the pandemic causing supply chain woes, but skyrocketing load growth.
“We have unprecedented demand for equipment, and that’s not dawning on some,” Zadlo said. He said data centers are even procuring transformers, making it more difficult for a small Texas electric cooperative to secure equipment.
Multiple panelists said ERCOT should move away from planning for spot solutions and examine what transmission will be needed longer term.
“Long-term transmission plans have been shelved, and we need to act on them today,” Zadlo said. He also said someone needs to “challenge the utility mindset” and say, “‘Look, what you built yesterday will not work.’”
“Data centers go up faster than transmission does,” noted Ali Amirali, senior vice president of Lotus Infrastructure Partners.
Amirali said developers should prepare lines today to be high-voltage-ready, with insulation and right-of-way procurement, and find “patient” investors who see the value in having the option to easily size up transmission capacity.
Zadlo said the mindset that HVDC lines are novel and untested should be scrapped.
“It’s not that complicated,” Amirali agreed. He joked that he became a power systems engineer when he was young because he was “lazy,” and he figured the last great technological advancement in the field was transformers. Now he lamented that he was proven right and there haven’t been more advancements.
“We cannot solve today’s problems using yesterday’s technology, and to be honest, we’re still in the ’60s,” he said. He later laughed and added a disclaimer that his views are “mine and mine alone.”
The Lure of Gas
In an earlier panel, CPS Energy Chief Supply Officer Benjamin Ethridge said there are opportunities in the future for zero-emission dispatchable generation. For now, he said gas plants will be the dominant on-demand power source for growing load, and gas infrastructure needs major expansion.
“It’s great to have 2035 or 2040 goals, but we need to be able to weather the next winter storm, the next Uri,” said Michael Enger, Austin Energy’s vice president of energy market operations and resource planning.
Rockland Capital co-Managing Partner Scott Harlan said his company is interested solely in gas-fired facilities to bolster dispatchable resources. However, he said gas supply can be uncertain with intrastate pipeline companies that function as unregulated monopolies without transparency.
All agreed that the Texas Energy Fund, which provides as much as $10 billion in subsidies to fund dispatchable resources, is a welcome development.
Kathleen Smith, president of Aegle Power, said she was “very pleased” to see the subsidized loans approved by Texas voters and is excited to see what projects are submitted next month.
Smith also predicted the Texas Legislature will be relatively quiet on the energy front this session barring any new emergency events.
“I really hope the legislature stands down, maybe does a few tweaks but not anything massive,” Harlan said. He added he’s also concerned about EPA’s power plant emissions rule, expected to be released at the end of the month. He said if gas facilities are required to install carbon capture, it would add years to commercial operation dates.
“I’m hoping they take a more tempered approach. If they’re aggressive and require carbon capture on gas plants, there are going to be lawsuits,” he predicted.
Enger said he hopes for a trouble-free, windy summer. Ethridge said that though Austin is gearing up for another hot summer, his utility has more wind, solar and storage, and he’s “bullish” on ERCOT market dynamics.
Martin Pasqualini, managing director and partner of boutique investment firm CCA Group, said Texas law shouldn’t be hostile to wind and solar project financing.
“I think the renewable market can deal with neutrality but not outright antipathy,” he said.
Pasqualini pointed out Texas no longer is the only market experiencing load growth. It might be more difficult to build in other regions, he said, but it’s possible for renewable developers to withdraw from ERCOT.
Dean Tuel, vice president of Goldman Sachs-backed compressed air storage company Hydrostor, said his company takes advantage of low-cost excess and furnishes grid reliability — effectively capacity, though ERCOT doesn’t have a capacity market.
Tuel said he would like utilities to look further on the horizon for procurement plans. Utilities shouldn’t simply plan on erecting solar panels and short-term energy storage for the next few years but also should procure dispatchable resources for beyond 2030. He said for his company, whose assets have a 50-year lifespan, long-term offtake agreements are key.
OnPeak Power Managing Partner Ingmar Sterzing also said ERCOT no longer has the market cornered on fastest queue processing time.
“The load is coming in so quickly that it could definitely be a challenge,” he said.
Pranay Reminisetty, a lead interconnection engineer with DNV, said constraints on the ERCOT grid are piling up and the state needs new transmission so it doesn’t hamstring new generation.
“You have significant load growth in hours that you’re not really building generation for,” said Luis Lugo, head of ERCOT trading at Mercuria. He said April’s prices already have been high on unseasonably warm weather.
“Fundamentally, we’ve done nothing to build generation for hot weather,” Lugo said.
During a panel concerning corporate sustainability goals, Chris Dorow, regional manager of power and utilities for BASF, said that although some companies recently pushed out sustainability goals, those timelines always were “aspirational” because they were made when technology feasibility wasn’t fleshed out.
Tina Moss, senior director of net zero strategy for LyondellBasell Industries, said her company’s climate goals still boil down to matching the targets laid out in the Paris Agreement on climate change.
Alex Beck, co-founder of renewable financial firm GoodLynx, said companies’ sustainability offices often are “kneecapped” and not bestowed the budgets or power to enact their goals. “Corporate America needs to reframe” how it incorporates zero-emission energy and buy tax credits to finance clean energy projects, he said.
New York’s offshore wind portfolio has collapsed, again. Three provisional contracts totaling 4 GW have been cancelled, wiping out a procurement 21 months in the making.
The offshore wind industry and its advocates say they view this as a temporary setback and will continue to push forward.
The New York State Energy Research and Development Authority (NYSERDA) announced April 19 the provisional contracts it awarded in its third offshore wind solicitation to Attentive Energy One, Community Offshore Wind and Excelsior Wind would not proceed.
All four contracts awarded in New York’s first and second solicitations — Beacon Wind, Empire Wind 1 and 2, and Sunrise Wind — also have been cancelled or are being cancelled.
Those four deals dated to 2019 and 2021. They were sunk by massive cost increases and supply chain constraints that developed after the terms were locked in, and by New York’s refusal in October 2023 to negotiate new terms on the grounds that doing so would undercut the competitive market. (See NY Rejects Inflation Adjustment for Renewable Projects.)
By contrast, the collapse of the third solicitation’s three provisional contracts is blamed on technical changes — notably, in the nameplate capacity of the turbines specified for the projects.
Some of the overarching problems that have dogged New York’s attempt to build an offshore wind industry have been addressed: The domestic supply chain and physical infrastructure needed to build offshore wind farms are slowly taking shape, and the provisional contracts in New York’s third and fourth solicitations carry much higher compensation for developers.
Given this, the offshore wind industry is putting the best face on this latest cancellation in a state that is one of the strongest champions of offshore wind development.
Will Brunelle, spokesperson for Community, said: “We look forward to evaluating upcoming solicitations in New York and to working with the state as it pursues its clean energy goals. As we move forward, a strong, local supply chain consisting of reliable partners will be vital to the success of the New York offshore wind industry.”
Andrew Doba, spokesperson for Excelsior developer Vineyard Offshore, said: “While this latest development is unfortunate, Vineyard Offshore looks forward to working with the [Gov. Kathy] Hochul administration and NYSERDA to advance the next solicitation process in New York. Together, we can deliver critical carbon reduction benefits, improve public health, and bring significant local investments and job creation to the Empire State.”
Missing Pieces
New York’s offshore wind contracts entail billions of dollars spread across a small army of contractors, subcontractors and suppliers, with baked-in ancillary goals such as workforce and supply chain development, environmental justice, and community benefits.
In its April 19 announcement, NYSERDA indicated that too many pieces of the puzzle began to change for the contract awardees and their partners to finalize the agreements.
NYSERDA singled out as a key factor the decision by GE Vernova to halt development of an 18-MW variant of its Haliade-X turbine.
Excelsior and Community expressed displeasure with GE Vernova.
“NYSERDA’s decision is warranted given GE Vernova’s failure to follow through on their commitment to deliver an 18-MW machine,” Doba said.
“Our commitment to offshore wind in the region is unchanged,” Brunelle said. “While we are disappointed that the wind turbine manufacturer was unable to fulfill its commitments and enable our provisional contract award to move forward, we believe in the fundamentals of the U.S. offshore wind market.”
GE Vernova will see a ripple effect from the contract cancellations: New York had committed to $300 million in subsidies for the company and subsidiary LM Wind Power to build two factories — one for offshore wind turbine nacelles, one for blades — along the Hudson River near Albany. That money instead will support offshore wind supply chain development in future solicitations, NYSERDA said.
Bigger Not Always Better
GE Vernova’s website indicates the Haliade-X is rated at 12-14.7 MW.
NYSERDA indicated the company was proposing to supply 15.5- to 16.5-MW variants for the New York projects that held provisional contracts, rather than the 18-MW version originally specified.
GE Vernova did not return a request for clarification for this story.
At GE’s 2023 Investor Day event, before the spinoff of General Electric’s power businesses as GE Vernova, an executive said the company was getting good industry feedback on a potential 17- to 18-MW variant of the Haliade-X.
A year later, the word “offshore” appears 42 times in a transcript of GE Vernova’s 2024 Investor Day conference call, often in the context of reversing its offshore wind business’ financial performance. At one point, an executive says the 14-GW Haliade-X is the workhorse that “positions us well to win.”
But there are zero references to a larger Haliade-X.
Shifting a 1,400-MW project from 18-MW to 16-MW turbines could boost its cost noticeably, requiring 13% more turbines and foundations and more time onsite for installation vessels that are exorbitantly expensive to charter.
The push for bigger turbines has been underway for years. The dozen turbines powering the nation’s first commercial offshore wind farm — New York’s South Fork Wind, completed last month — are rated at just 11 MW.
More power per tower is a lucrative prospect for developers but can carry significant hidden costs:
Manufacturers planning ever-larger models can get locked into an unending R&D cycle, creating quality-control risks; manufacturing facilities and installation equipment designed for a particular size of tower and blade may not be able to handle larger equipment; investing hundreds of millions of dollars for larger equipment comes with the risk that it, too, soon will become obsolete as customers clamor for even larger models; repairs are more difficult and costly to perform on the largest machines. (See Big Offshore Wind Plans Face Multiple Major Obstacles.)
Construction work nears completion earlier this year on South Fork Wind. | South Fork Wind
Positive Developments
Despite this latest development, there are positive signs in New York’s offshore wind sector:
Empire and Sunrise won provisional contract awards in February after they rebid into the fourth solicitation, and they both are close to construction-ready after years in development. (See Sunrise Wind, Empire Wind Tapped for new OSW Contracts.)
Community Offshore Wind 2 was waitlisted in the fourth solicitation — neither approved nor rejected as the state focused on the two mature projects.
State leadership remains firmly committed in word and deed to developing offshore wind as a source of clean energy and economic activity.
Equinor began work in early April on an offshore wind operations terminal in Brooklyn.
A wind tower factory originally planned for the Port of Albany has been cancelled due to delays and cost overruns, but Equinor and the port are pushing ahead with site preparation for an as-yet undetermined offshore wind manufacturing facility.
The Albany project is a microcosm of offshore wind development in New York, encountering multiple setbacks and pushing through them.
Port of Albany CEO Richard Henrick told NetZero Insider via email:
“The project is proceeding in a phased-approach to pad-ready status, to best position progress in preparation for offshore wind manufacturing on the Hudson River. This site is fully permitted and the most advanced site suitable for offshore wind manufacturing in the Northeast U.S. We are confident that it will be instrumental in fulfilling a domestic offshore wind supply chain in the United States.”
Latest Setback
The April 19 announcement was the second major collapse of New York’s offshore wind pipeline in six months. After the first, Gov. Hochul (D) and NYSERDA scrambled to get renewable energy development back on track, both offshore and on land.
This effort continues and the next steps will be announced soon, NYSERDA said April 19: “Amidst the evolving challenges faced by the offshore wind industry, NYSERDA is continuing to take proactive measures to respond to and address these issues head-on.”
Fred Zalcman, director of The New York Offshore Wind Alliance, said:
“We are disappointed with today’s news, but it is not surprising given GE’s recent reversal of its plans to make the new 18 MW wind turbines. That decision led to additional permitting challenges and costs for these planned New York offshore wind projects.
“This proves it is not easy to build an entirely new U.S.-based heavy industry, but we are confident that projects will continue to be planned, developed, permitted, and built off the shores of New York. Private industry remains committed to working with NYSERDA and other government partners to reassert New York’s leadership in the offshore wind space.
“There may be more setbacks in the future, but they will be far outpaced by the number of milestones for this industry.”
National trade group Oceantic Network directly blamed GE Vernova for the development.
CEO Liz Burdock said: “We are confident New York’s leadership will take the action necessary to maintain their market’s trajectory. The state has already shown its ability and willingness to move swiftly to secure projects on their timelines, and we fully expect the state will continue taking bold action in service of their 9 GW deployment goal.
“The U.S. market has been steadily building momentum, and while today’s announcement is disappointing, it is not unexpected and will not impact the market’s overall fundamentals.”
Advanced Energy United said:
“While project delay announcements aren’t welcome in any industry, and the offshore wind industry is no different, we view this as a minor detour on New York’s path toward a vibrant offshore wind energy future.
“When a building construction project doesn’t move forward, we don’t treat it as an indictment of the building construction industry, and it should be the same for offshore wind. This type of setback is very typical for construction projects of this size, particularly with the lasting impacts the pandemic had on supply chains, financing, and leasing.”
The return to demand growth around the country has the industry considering how to meet it, with many utilities and states considering new natural gas-fired units, while others are trying to avoid growing carbon emissions while maintaining reliability.
The Department of Energy on April 17 released a report on “The Future of Resource Adequacy,” which says firms investing in natural gas resources should make them able to be retrofitted with carbon capture and storage, or with the ability to burn clean hydrogen. (See related story, DOE Urges Utilities to Embrace ‘Holistic’ Reliability Solutions.)
“Building new natural gas plants without a strategy to address emissions risks infrastructure lock-in and stranded assets,” the report said. “To help address these concerns, new gas capacity should be capable of achieving and supporting clean electricity systems. For example, gas generators should be designed to operate flexibly and at lower capacity factors to effectively support systems with increasing amounts of variable wind and solar generation.”
Still, many utilities are trying to build new natural gas plants, with the Georgia Public Service Commission on April 16 approving Georgia Power’s request to add three new dual-fueled combustion turbine units at an existing generation site between integrated resource plans because of unexpected load growth in its territory. The commission also authorized the utility to invest in new grid-scale batteries.
The new capacity was needed because Georgia Power found its 2030/31 winter demand projections had gone up by 5,900 MW since it issued its 2022 IRP, according to a brief the utility filed early this month with the PUC. The firm found it would need new capacity by winter 2025/26.
“Given the continued increase, progress and pace of committed customer load, the commission should have an extremely high degree of confidence in the forecast and should approve the company’s load forecast as filed and agreed to in the stipulation,” the utility said.
Overhanging the regulatory cases around new natural gas plants are EPA’s looming rules under Section 111(d) of the Clean Air Act, which are expected to restrict fossil fuel emissions in the future. Ultimately, the rule’s fate depends on the presidential election, as similar rules were overturned the last time Donald Trump was in the White House.
The Southeast in particular has been a hot spot for new demand from Georgia up to Data Center Alley in Northern Virginia, Luis Martinez, the Natural Resources Defense Council’s lead for climate and energy in the region, said in an interview.
Dominion Energy has proposed building a major new natural gas plant in Chesterfield, Va., just south of Richmond.
“The troubling trend is the rush to build gas to meet it, which is what we’re hoping won’t come to fruition … because it will derail our short-term and long-term, I’d say, climate emission-reduction goals,” Martinez said.
Moving to more and more natural gas in the region also makes it more prone to sudden price spikes because of the commodity’s volatile market, he added. North Carolina’s Duke Energy has expanded its gas fleet in recent years, and customers have been pinched by spiking prices from recent winter storms and generally higher costs in 2022, which now are being felt on their power bills, Martinez said.
One reason the Southeast is seeing a flood of new natural gas plant proposals is that it relies on traditional regulation, meaning that as long as regulators approve the plant, it will get built.
“This risk of potentially having this new gas generation become a stranded asset, or not cost competitive, which you could see in other regions, is not present,” Martinez said. “Once they’re approved in the Southeast, then it’ll be on ratepayers to pay for that whole thing, even if in 10 years these things are no longer useful because they have to add carbon capture and storage or they have to transition them to hydrogen, as the EPA 111 rule would require.”
NRDC wants regulators around the region to evaluate all of the options they have to address the demand and pick the least-regrets ones, such as energy efficiency, before natural gas, he added.
California has long used the “loading order,” where its Public Utilities Commission prioritizes efficiency and clean energy and places expanding natural gas capacity as a last resort to maintain reliability. While the different politics of the region mean that will never be a formal policy, it could serve as rule of thumb, Jackson Morris, NRDC’s director of state power sector policy, said in an interview.
“There [is] tons of untapped energy efficiency on the system that needs to get tripled or quadrupled in scale. That’s No. 1,” Morris said. “Then you go to both utility-scale and distributed renewables projects. You also invest heavily in transmission and distribution investments, including both on existing reconducting efforts and things like that, as well as new lines and distribution infrastructure to maximize the capacity to move power around.”
Natural gas should be the last resort to solve resource adequacy issues, he said. And NRDC would prefer utilities build CTs at this time because even though on a unit basis they are less efficient than combined cycle, they run much less often.
Other states around the country are dealing with similar issues. Harvard Law School’s Electricity Law Initiative hosted a webinar this month with state regulators to discuss how to meet higher demand while staying on course for cutting emissions.
“I think the most important thing that we can do as states is to help to get the incentives right to balance the reliability and sustainability and clean energy goals that we’ve got,” Illinois Commerce Commission Chair Doug Scott said.
A big part of Illinois’ strategy is keeping its nuclear plants open. It pays them when natural gas is cheap, but customers actually received rebates in 2022 when the commodity’s price spiked, Scott noted. As far as new capacity, Illinois is working to expand renewables.
Minnesota Public Utilities Commission Vice Chair Joseph Sullivan noted the industry has dealt with even higher rates of demand growth in the past, such as when consumers adopted air conditioning en masse and demand grew from 7 to 9% every year.
“If you put on a data center, that’s 10% of the entire system; it’s a lot, and we’ve got to deal with that,” Sullivan said. “But if we plan for it, and we use the processes that we have, I think we’re going to get through it.”
