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November 20, 2024

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Jackson Named Texas PUC’s Interim Chair

Texas Gov. Greg Abbott on Wednesday appointed the Public Utility Commission’s newest member, Kathleen Jackson, interim chair. She will lead the commission until a permanent chair is named, Abbott said.

Jackson was appointed to the commission in August and only confirmed by the Texas Senate in May. She replaces Peter Lake, who stepped down last week and will leave July 1. (See Texas PUC’s Lake Steps Down as Chair.)

“I’m honored and humbled by Governor Abbott’s trust and confidence in me to lead the Public Utility Commission at this very important time for the agency and for Texas,” Jackson said in a statement.

The commission’s other four members were all appointed in 2021. They replaced the previous commissioners, who all resigned after the February 2021 deadly winter storm.

Jackson has led the PUC’s grid-related energy efficiency efforts. She previously served as a board member of the Texas Water Development Board from 2014 to 2022.

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Debt Deal Weakens Odds for Increased FERC Siting Authority, Glick Tells EBA

WASHINGTON — Giving FERC a larger role in transmission siting would aid decarbonization and grid reliability, but it is unclear whether Congress will have the appetite for that any time soon, former FERC Chair Richard Glick told the Energy Bar Association’s Electricity Steering Committee on Tuesday.

Permitting “reform” has been a hot topic on Capitol Hill this session, and Congress’ debt ceiling agreement included provisions to shorten reviews under the National Environmental Policy Act. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)

But the changes “weakened the legislative momentum,” making it much more difficult to find a legislative vehicle for giving FERC increased powers this year, said Glick, a former Senate aide who opened a consulting shop after his term at FERC expired. (See Former FERC Chair Richard Glick Sets up Consulting Shop.)

He noted that the Infrastructure Investment and Jobs Act gave FERC authority to overrule state denials of transmission lines designated by the Department of Energy as National Interest Electricity Transmission Corridors. (See FERC Backstop Siting Proposal Runs into Opposition from States.)

“I think there’s still going to be issues with regard to transmission siting [for] certain lines,” Glick said. “Certainly, it’s not going to happen as quickly as it might have happened, because there’s no one-stop-shopping, so to speak, at FERC.”

The current system of leaving most siting decisions up to states might have made sense for many decades, he said. But with major transmission lines needed to bring renewables across multiple states, or to increase minimum transfer capability among regions to deal with increasingly volatile weather, the current system needs to change, he said.

Rights of First Refusal

Glick and other speakers at the EBA meeting also weighed in on FERC’s controversial proposal to reinstate a federal right of first refusal (ROFR) on transmission construction for incumbent utilities that work with a partner. The change was included in the commission’s April 2022 Notice of Proposed Rulemaking on transmission planning, which Glick supported (RM21-17). (See ANALYSIS: FERC Giving up on Transmission Competition?)

FERC Order 1000 in 2011 eliminated the federal ROFR on regional transmission projects. Glick said he supported reinstating the ROFR because utilities responded to Order 1000 by reducing spending on bigger regional projects in favor of local transmission that remained exempt from competition.

“The answer that I first thought when I was at FERC was why not just subject all of them to competition?” Glick recounted. “And staff convinced me that wasn’t a workable solution.”

Glick acknowledged it was hard to police local transmission projects that often fall under formula rates and have varying levels of state oversight. FERC Commissioner Mark Christie has suggested getting rid of formula rates when states lack the ability to adequately oversee such local lines.

“The states that don’t have that [oversight] authority would quickly act to get that authority because getting rid of formula rates would be complex — and that’s an understatement,” Glick said.

Some states reacted to Order 1000 by imposing ROFRs on any transmission line that goes through their territory. LS Power Development Senior Vice President Sharon Segner said it is an open legal question whether such laws “invade” FERC’s exclusive jurisdiction over interstate transmission.

A group of MISO transmission customers filed a complaint last year asking FERC to effectively override such state laws (EL22-78). (See Consumer Groups File FERC Complaint Against MISO.)

“They interfere with interstate commerce,” Segner said. “And we’re talking about states interfering with regional projects that are paid for by citizens outside of the state, yet you have state protectionist laws coming into play.”

WIRES Executive Director Larry Gasteiger holds the opposite opinion on ROFRs, contending that FERC’s NOPR would get more interregional transmission built.

“Our general approach to ROFR and to competitive transmission issues comes from the standpoint of … how is it impacting transmission development and the ability to get transmission developed in a timely basis?” Gasteiger said.

More than a decade after FERC introduced competition to transmission, the policy does not seem to be working and is producing results that go against other transmission policies that FERC and others support, he said. Competition makes it more difficult to build the huge amount of transmission that is forecasted as needed to get the grid to net zero emissions, he added.

“It’s taken us over 100 years to get to where we are now,” Gasteiger said. “So, you’re talking about doubling or tripling that amount of transmission in a third of the time.”

Gasteiger argued that it made sense to keep local projects away from competition because often they are needed quickly and are often fairly small — such as the need to raise a substation to avoid floodwaters.

Segner said LS Power does not want to compete with incumbent utilities on such projects. But she said local transmission lines of 100 kV or above should be open to competition.

Making that many lines open to competition would lead to even more states passing their own ROFR laws, said Perkins Coie Partner Jane Rueger. But major interregional lines could benefit from competitive processes, she said.

Major transmission lines that cross states are often built by one company, but those efforts could run into a state ROFR law that blocks them from getting built.

“You might see more pressure to have a federal solution, so again, that everything is rowing in the same direction,” Rueger said.

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CALSTART Brings Electric Vehicles to Hazy Capitol Hill

WASHINGTON — With hazy skies in the nation’s capital produced by Canadian wildfires, clean transportation nonprofit CALSTART brought four commercial electric vehicles to the foot of Capitol Hill on Wednesday for a press event with some of the industry’s supporters in Congress.

CALSTART works with governments and industry to develop clean and efficient transportation solutions. Its members include Audi, Ford, General Motors and Volvo.

Sen. Martin Heinrich (D-N.M.) said the assembled vehicles showed that the industry had made major strides and was ready for real-world use. The vehicles included a Nikola semitruck, a Workhorse box delivery truck, a Monarch Tractor and an electric ice cream truck.

“They just do the job better, and it couldn’t come at a more important time,” Heinrich said, referencing the haze and low air quality from the wildfires. “Those of us in the West are familiar with this. We’ve lived with it for 15 to 20 years now. This is the result of 100 years of burning fossil fuels. And it means we’re now burning our forests because the planet is a warmer place.”

Decarbonizing transportation is key to limiting further impacts from global warming, and while commercial vehicles represent just 5% of the overall fleet, they are a quarter of the sector’s emissions, Heinrich said.

“We won’t be able to tackle the challenge without setting the most ambitious standards to lead transportation emissions and move the market through policy,” Sen. Alex Padilla (D-Calif.) said.

Padilla grew up in Los Angeles, which historically had such bad air quality that he would sometimes be sent home from school because of it. As a tour bus’ diesel engine rumbled past, he described riding to and from school in yellow buses with the same engines and recalled their smell.

“You can imagine the health issues and the learning issues that that would lead to,” Padilla said. “We refuse to accept that as normal and will not impose that same reality, the same environmental harm and health risk on future generations. That’s why California is proud to have set some ambitious goals when it comes to tackling emissions. No state has fought harder to transition to electric vehicles than California.”

The state wants to get to 100% emissions-free medium- and heavy-duty trucks by 2045, he added.

CALSTART worked with the California Air Resources Board to get those first-in-the-nation regulations passed, which have now been adopted by another nine states, organization President John Boesel said.

“What’s really important now is that the U.S. EPA is considering regulations in this space,” Boesel said. “And they have a draft regulation that’s out there for comment, and industry and others are providing input.”

The industry already offers more than 100 types of zero-emission commercial vehicles, especially in states that offer their own incentives on top of those from the Inflation Reduction Act, he added.

“Those vehicles are cost effective today,” Boesel said. “They have much lower operating costs than their diesel equivalent. And that includes both the cost of electricity and maintenance costs. And I think as we see battery technology improve, that business case is only going to get better and better.”

Innovation to limit carbon emissions used to be something to look forward to, but it is here now, Rep. Paul Tonko (D-N.Y.) said.

“Trucks and buses that are the backbone of our current economy, that provide vital services to our communities, can be run in a clean and effective manner,” Tonko said. “These vehicles in the past have disproportionately contributed to air pollution.”

The Biden administration was also represented at the event through the Joint Office of Energy and Transportation, in which the respective departments coordinate their efforts on EVs. Executive Director Gabe Klein said he came from the business world, where he set up an organic food truck company with 16 EVs in the 2000s, when there was nowhere to charge them, not even in D.C.

“The world has changed dramatically, and now these vehicles are mainstream,” Klein said. “And our job at the joint office … is to bring together DOT, DOE and all the resources within the federal government to help to get this job done.”

President Joe Biden set a goal for the U.S. to have 500,000 EV chargers by 2030. The country added 21,000 chargers last year, up from an average of about 5,000 a year, and now the country has about 143,000 in total.

Nikola is building semitrucks out of its factory in Arizona that are aimed at dealing with regional cargo transportation needs with a range of 330 miles, said senior manager for state and local affairs William Higgins. The trucks are already being used at Los Angeles International Airport and the nearby ports of Long Beach and Los Angeles.

“Nikola believes that the electrification of the medium- and heavy-duty sector is critical to reducing carbon emissions given that, on average, one zero-emission truck avoids 106 metric tons of CO2 annually,” Higgins said.

The firm is also to release a hydrogen fuel cell truck this year, with a range of 500 miles that can be used for longer-distance cargo, he added. Nikola also early this year launched its own hydrogen fuel brand, called HYLA, to support the continued evolution of clean heavy trucking.

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RTOs Report Diminished Solar Output, Loads as Wildfire Smoke Passes

VALLEY FORGE, Pa. — RTOs in the Northeast are experiencing diminished solar output and lower-than-expected loads as smoke from wildfires in Canada passes over the region.

“In recent days, smoke from wildfires in Canada has traveled to New England, significantly lowering production from solar resources in the region compared to what ISO New England would expect absent the smoke,” ISO-NE said in a statement Thursday.

Most solar generation in ISO-NE is behind-the-meter of retail loads, leading the smoke’s impact to manifest as increased energy demand in the region. Lower temperature from the smoke has had a counterbalancing effect, reducing energy consumption from air conditioning.

“These two factors — decreased production from solar resources and decreased consumer demand due to lower temperatures — [have] made forecasting demand for grid electricity challenging,” ISO-NE statement said. “In forecasting real-time and future demand for electricity, ISO New England relies on historical data from similar days, adjusting for changing system conditions. Because these smoky conditions are unprecedented in the region, there is little, if any, historical information to rely on, creating further complications in generating accurate forecasts.”

PJM spokesperson Dan Lockwood said the smoke has been having a similar effect as it passes over the mid-Atlantic region as well.

“Smoky conditions throughout the RTO this week have caused a reduction in visibility, reducing solar and keeping temperatures several degrees lower than usual. It is difficult to single out the effect of smoke alone, especially when PJM has not seen an expansive plume like this. However, the cooler temperatures and decreased visibility are similar to what we experienced during the period of July 19-21, 2021, when the RTO was covered with smoke from wildfires in the western U.S. PJM is closely watching the smoke maps and taking these factors into consideration as it forecasts load for its zones,” Lockwood said in an email.

NYISO reported total peak solar output over June 6 and 7 was 1,466 MW lower than forecast, including both utility-scale and behind-the-meter resources.

“Based on data compiled by NYISO forecasters, wildfire smoke cover significantly reduced incoming solar irradiance across the state on June 6 and 7. … While the haze caused by the ongoing Canadian wildfires had a significant impact on solar energy production, the two-day total peak production still reached 4,405 MW. The NYISO will continue to monitor this situation as it develops,” spokesperson Andrew Gregory said.

Jeff Weiss, executive chair of Distributed Sun, said one of their rooftop units in NYISO peaked at 63% of its nameplate capacity Thursday. A few weeks away from the summer solstice, he said solar should be operating at “full blast” this time of year, reaching full nameplate even at 75% solar irradiance due to the oversized inverters installed. While the lower output likely reflects the impact of the smoke, Weiss said upstate New York was expected to have reduced solar output to some degree due to wind, cloud cover and similar atmospheric conditions.

“While this extra particulate matter is certainly blocking out the sun, a detailed atmospheric analysis is required to accurately measure the specific impact of multiple factors,” he said.

A September 2020 analysis by the Energy Information Administration found that average solar output declined by 30% when smoke from wildfires covered California over the first two weeks of the month compared to the July average. Despite 659 MW in new utility-scale solar installations in the region, a 5.3% increase and an 11% growth in distributed solar, overall generation from solar was 13.4% lower for those weeks than in the corresponding period in 2019.

“In July 2020, daily solar-powered electricity generation, which includes generation from solar photovoltaic and solar thermal electric generators, ranged from 104 to 119 GWh, averaging 113 GWh for the entire month. Daily solar-powered generation began declining as large wildfires broke out in mid-August, reaching a low of 68 GWh on Aug. 22 before returning to approximately 100 GWh by the end of the month. Solar-powered generation began declining again as wildfire activity rose in September, falling as low as 50 GWh on Sept. 11 as PM2.5 smoke pollution increased,” EIA wrote.

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NJ BPU Pulls Offshore Tx Project Mod from Agenda After Complaint

New Jersey’s Board of Public Utilities (BPU) on Wednesday pulled an item from its meeting agenda that concerned modifying the scope of the state’s $1.1 billion offshore transmission project after the Division of Rate Counsel complained that it had not been properly advised of cost increases.

In a letter to the BPU on Monday, the Rate Counsel said it believed the cost of the project, which was approved in October, had already increased by $127.3 million, or about 12%. But the counsel said it was unaware whether that was the modification sought by the BPU at the meeting because the board had not provided details of the change or advance warning, as is required by law.

The apparent increase is the first for a project that marks the first use of the FERC-authorized State Agreement Approach (SAA).

The cost increase comes as the state’s ambitious plan to install 11 GW of offshore wind capacity by 2040 has come under increasing scrutiny from Republicans and business groups expressing concern that its cost to ratepayers is not clear.

fiordaliso-joe-2018-10-30-rto-insider-fi.jpgBPU chair Joe Fiordaliso | © RTO Insider LLC

At the same meeting, the board approved a five-week delay in the deadline for submissions in the state’s third OSW solicitation, and BPU President Joseph Fiordaliso criticized the state’s OSW developers for creating “intolerable” delays.

The BPU used the SAA process to solicit 80 proposals outlining ways to enhance and develop infrastructure that would enable OSW projects to tie into the state grid, and then picked one main project using pieces of two submissions and several smaller projects. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) The state is now preparing to launch a second such transmission solicitation.

In his letter, Rate Counsel Brian O. Lipman said that as a legally recognized party to the process, his office should have been notified of any proposed budget changes and “provided a fair opportunity to be heard” because ratepayers will “pay 100% of the costs.” He urged that the agenda item be “removed from consideration” because of the way it was handled.

“Rate Counsel did not learn of the matter until it was posted on the agenda,” he said. As a result, he said, “it is not clear if the board will now ratify those changes, or if there are additional costs that will be passed to ratepayers.”

Fiordaliso did not explain the removal when he announced it at the start of the meeting. The BPU did not immediately respond to a request for comment from RTO Insider.

Lipman told RTO Insider he first heard about the cost increases at the May 9 meeting of the PJM Transmission Expansion Advisory Committee. He provided a PJM presentation from the meeting that showed a cost increase of $127 million, bringing the total to $1.192 billion.

5-Week Delay

The board approved a five-week extension of the deadline for developers to make submissions under the state’s third OSW solicitation process, which began in March.

Two new board members, Christine Guhl-Sadovy and Marian Abdou, did not vote on any items at the meeting. (See NJ Senate Approves Two BPU Commissioners.)

The board agreed to shift the deadline from June 26 to Aug. 4. It also delayed by the same amount of time other deadlines by which certain tasks in the application must be completed, such as deposit payments and the board’s response to clarifying questions.

The third solicitation could double the state’s approved capacity of 3,758 MW and would allow the BPU to approve projects totaling between 1.2 and 4 GW, and perhaps more. A board award of 4 GW in the third solicitation would take the state to approved capacity of 7.58 GW. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

The order that was approved does not explain the change except to say it will “allow applicants more time to develop their applications.”

“I think this is in the best interest of the ratepayers,” Fiordaliso said. “I think it also gives the developers an opportunity to come up with the best possible proposal that they can.”

Earlier in the meeting, however, Fiordaliso lashed out at the state’s offshore developers for creating what he said were repeated delays. It was unclear, however, what issue he was referring to, or what prompted the statement.

“We have had, almost since Day 1, delay after delay after delay,” he said. “We have … staff members who have busted their backs. And I’m looking at two of them right now on offshore wind. And all one developer in particular has done is delay this process for one reason or another.”

He did not identify the developer, and he added that “climate change continues to progress at a rate that is dangerous.”

“We cannot afford any more delays,” he said. “So I’m issuing a recommendation to those developers: Put your nose to the grindstone, and let’s get this going again. Because my patience is short, and your delays are intolerable. And if you can’t do that, we have to have a very intense discussion.”

Asked about Fiordaliso’s comments, Madeline Urbish, head of government affairs and market strategy in New Jersey for Ørsted, said the company is “committed to delivering Ocean Wind 1,” the state’s first OSW project.

“Today’s comments are unexpected, as we are working and have worked closely with the BPU, [the New Jersey Department of Environmental Protection] and federal agencies throughout the development process to ensure the project moves forward in a responsible and expedient way despite early delays in federal permitting under the previous administration,” she said.

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NYISO’s Latest Queue Overhaul Draft Confuses Stakeholders

RENSSELAER, N.Y. — NYISO left members of the Transmission Planning Advisory Subcommittee bewildered and dissatisfied on Monday when it presented another revised proposal for overhauling its interconnection study process.

Mark Younger, president of Hudson Energy Economics, summarized the mood: “You have succeeded in totally confusing me,” he said to laughter in the room.

NYISO’s new concept incorporates previous stakeholder feedback but still left many wondering if the revised proposal would solve existing project backlogs, reduce delays plaguing the queue and address stakeholder concerns. (See “Queue Window Comments,” NYISO Shares Details of Potential Long Island Tx Projects.)

NYISO has been investigating ways to improve its interconnection process, which has been getting longer and more complicated as projects with more advanced technologies enter the queue.

Thinh Nguyen, NYISO senior manager of interconnection projects, said the ISO “wants to create a process that improves interconnection studies by reducing time and increasing efficiency while maintaining system reliability and providing sufficient incentives and disincentives to commercial projects.”

Overview of Approach

The approximately three-year-long class year queue window (CYQW) concept keeps parts of the interconnection study process that are popular, such as the class year study but gives developers more opportunities to exit the queue without significantly compromising their finances or impacting other queued projects.

For example, the proposal would maintain current class year structures with a defined application phase and a clustered feasibility study that replaces individual system reliability impact studies, but it would use a two-staged class year study with more stringent validation requirements and run queue window groups in parallel.

NYISO’s presentation to the TPAS on Monday delved broadly into the three portions that constitute the CYQW: the application phase, the clustered feasibility study and the two-stage studies.

The application phase would be a 90-day period when project applications are submitted and validated, developers post their preliminary study deposits, and the initial interconnection diagrams are provided.

The next stage, the cluster feasibility study, would be when projects in a group are initially evaluated. During this 180-day period, NYISO would conduct environmental review, perform multiple sensitivity analyses, identify any system upgrades necessary to accommodate a project and give nonbinding cost estimates. Afterward, project developers would have 15 days to decide whether they want to either move forward to the class year study or leave the queue if they are found to be infeasible. Projects electing to leave the queue would see 75% of their study deposit refunded.

The class year study would consist of two eight-month stages where two project groups (i.e., Group A and B) are studied. Each stage would be followed by a 30-day decision period.

In stage 1, NYISO would perform localized analyses, which developers can use to inform their decision about whether to move ahead. Projects that take this initial offramp would lose only 50% of their application deposit.

In stage 2, study results would be refined based on projects that left, and remaining analyses would be conducted to identify any system upgrades required to install the proposed projects. Projects withdrawing during stage 2 would forfeit their entire deposit, while developers who accept their cost allocations would post security for any system upgrades identified for their projects.

NYISO asked stakeholders to address several open issues left unanswered in the proposal, including definitions, penalty determinations and whether prioritization processes should be established for projects proposing to interconnect at a similar location.

The ISO will spend the summer with stakeholders discussing and refining the CYQW proposal and hopes to begin vetting tariff language in the fall. It requests stakeholder comments on the proposal be sent to stakeholder_services_IPsupport@nyiso.com before June 16.

Stakeholder Comments

Stakeholders expressed discomfort about many aspects of NYISO’s proposal, but their focus was on the interactions between different groups of projects in the queue and dissecting the graphic that the ISO created to explain the construct. Many stakeholders were confused by how all the groups interact and impact one another.

Mark Reeder, representing the Alliance for Clean Energy New York, was concerned about how projects in Group C or D could simultaneously conduct their own feasibility studies as earlier CYQW projects (i.e., Groups A and B) conduct class year studies, even though there may be potential interactions.

Anthony Abate, lead energy market adviser with the New York Power Authority, sought to clarify, saying, “If you’re in Group C or D and are worried about potential interactions, what’s key to me is that the feasibility work for Groups A and B have likely already vetted or weeded out any surprises. So theoretically, this design should result in fewer dropouts because projects have already gotten feasibility evaluations.” Nguyen said Abate gave a nice summary.

Nguyen would expand on this issue in response to later questions posed by Hudson’s Younger, who asked how CYQW timelines overlap and what the graphic’s different colors represent.

“These are parallel processes where a transition class year study is ongoing, and at the same time, we have Group A and B undergoing their cluster’s feasibility studies,” Nguyen said. “Then, once those [feasibility studies] are complete, we start the class year for Group A and B, and as that class year study begins, we start the next group of feasibility studies for Group C and D.”

Given the novelty of the CYQW proposal, a swarm of questions was perhaps inevitable, but the complicated styling of the graphic seemed to make the proposal even harder to understand for stakeholders.

“I am having trouble understanding Group A and B interactions because [the graph] seems to show no overlap and just sequential pieces,” Younger said. “And so I don’t understand the benefit of having a Group A and a Group B if you’re going to do Group A’s analysis and then just wait to proceed to the class year for Group B’s analyses.”

Ngyuen responded, “Let’s say a developer in Group A cluster discovers some issues in the feasibility study; [developers] have the opportunity to submit a new interconnection request for Group B, so that’s why we have two groups. Then we also want to make sure that the class year does not run into any problems; therefore, as we conduct Group B’s feasibility analyses, we include Group A’s results in the baseline to allow us to consider potential interactions.”

Ngyuen clarified that Group B constitutes a separate cluster queue window that includes both projects from Group A that found out about problems and resubmitted an application and other potential projects not already studied.

Howard Fromer, who represents Bayonne Energy Center, asked why projects in Group A that already completed their feasibility studies had to wait for projects in Group B to move ahead to class year studies.

NYISO attorney Sara Keegan responded that “whether or not there’s a Group B, Group A cannot enter into the class year until the start date and so are stuck pending the subsequent class, so [NYISO] is just taking advantage of that time between class years to do as much as we can.”

Multiple stakeholders requested NYISO redo the graphic and come back to stakeholders with a picture that more explicitly shows the interactions and the timing between both different groups and windows.

NYISO did not explicitly promise to redraw the graphic but said it will return with updates after considering stakeholder feedback.

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OSW Developers Seeking More Money from New York

Almost all of New York’s offshore wind portfolio may not be able to move forward under the terms negotiated, developers said Wednesday.

In petitions submitted to the state Public Service Commission, they asked permission to amend their offshore wind renewable energy certificate (OREC) agreements with the New York State Energy Research and Development Authority.

NYSERDA is leading the state’s aggressive climate-protection efforts, which include a goal of 9 GW of offshore wind capacity online by 2035. The projects in question would get New York almost halfway to that goal by 2028.

But as with major wind projects in New England, developers of the New York projects say the cost to create the power generation infrastructure has grown, while the value of the power generated has not.

The petitions submitted Wednesday cover 4,230 MW of the 4,360 MW of offshore wind infrastructure under active development to feed the New York grid: the 924-MW Sunrise Wind project by Ørsted-Eversource, and three projects by the Equinor-bp partnership: Beacon Wind (1,230 MW), Empire Wind 1 (816 MW) and Empire Wind 2 (1,260 MW).

NYSERDA estimates commercial operation dates ranging from 2025 to 2028.

The only other project in New York’s pipeline is the 130-MW South Fork Wind. Construction of the Ørsted-Eversource venture is now underway, and it is expected to start generating power this year.

Six development teams submitted proposals totaling 8 GW in New York’s most recent offshore wind solicitation, which closed in January, but they are not in the pipeline yet. NYSERDA will announce awards this summer and execute contracts this autumn.

This latest solicitation included a provision for inflation-related revision of financial terms. The developers point out that they had no such provision and, as a result, are suffering amid the spiraling costs of recent years.

Sunrise said the negotiated $110.37/MWh payment from NYSERDA for the ORECs it generates is no longer enough.

Sunrise Project Development Director Ryan Chaytors told NetZero Insider via email:

“New York’s most recent solicitation made available to future projects inflation adjustments and interconnection cost-sharing mechanisms that more appropriately reflect today’s market conditions. We believe applying comparable inflation and interconnection cost-sharing adjustments now available to future projects to Sunrise Wind is fair, transparent and sufficient to advance the project.”

Sunrise in its petition notes the remarkable series of events that started soon after it signed its OREC agreement with NYSERDA in October 2019: COVID, decades-high inflation, decades-high interest rates, the worst war in decades, material shortages.

“These unanticipated, extraordinary economic events beyond Sunrise Wind’s control have upended its careful financial and developmental planning for the project. The project’s capital budget has increased from approximately $[X] billion to approximately $[X] billion. Without incorporating inflation and interconnection cost adjustment mechanisms into the OREC agreement, Sunrise Wind believes it would not be able to obtain a final investment decision allowing it to fully construct the project.”

As with other offshore wind projects, the cost of Sunrise is a trade secret, redacted from publicly viewable documents.

Empire and Beacon make a similar plea in their petition: “Despite petitioners’ cost control efforts and advances in permitting and interconnection, these unforeseeable events have substantially reduced the projects’ ability to attract the approximately $[X] investment necessary to support their construction and operation in a globally competitive market.”

The developers say in their petitions that they remain committed to completing the four offshore projects and delivering the promised benefits of the new clean energy source.

In a statement to NetZero Insider on Wednesday, Teddy Muhlfelder, vice president of Equinor Renewables Americas, said Equinor and bp did not take this step lightly but saw no alternative.

“Empire Wind and Beacon Wind remain on track to support thousands of jobs and billions of dollars of economic activity while helping New York meet its renewable energy goals,” he said. “Equinor and bp remain strongly committed to our projects and our partners in New York, and we are optimistic that together we can find a path forward in the weeks and months ahead.”

NYSERDA had limited response Wednesday.

“NYSERDA is aware of the petitions filed with the Public Service Commission and is reviewing the petitions,” a spokesperson said.

Also Wednesday, the trade organization Alliance for Clean Energy New York (ACENY) petitioned PSC for something it has long sought informally: an inflation adjustment mechanism for previously contracted large-scale onshore wind and solar projects in New York, many of which languish in permitting and interconnection processes for years between execution of contract and start of construction.

Here again, ACENY noted that recent contracts have such an adjustment mechanism, but older contracts do not.

The New York Offshore Wind Alliance, which is part of ACENY, represents offshore wind developers working in New York, associated companies, organized labor and environmental groups.

Director Fred Zalcman told NetZero Insider he had not seen Wednesday’s offshore petitions but is familiar with the issues they raise.

“All these projects are subject to the same macroeconomic pressures that we’ve seen manifested in the New England projects,” he said, referring to the SouthCoast and Commonwealth offshore wind projects, which are seeking to exit their Massachusetts power purchase agreements for the same reasons.

“So, it’s not very surprising to see. For better or worse, these projects are subject to fixed-price contracts. We do recognize the need for relief for these projects.”

If NYSERDA agrees to higher strike prices, Zalcman said, the cost will trickle down to ratepayers. But it would be unfortunate, he said, if NYSERDA refused and the nascent industry lost the momentum it has started to build after several years in New York. Offshore wind developers have begun to make progress toward building workforce development pipelines, shoreline infrastructure, and a local manufacturing and supply chain in New York, he added.

The three petitions filed Wednesday are part of PSC Case No. 15-E-0302, the proceeding to implement a large-scale renewable energy program and a clean energy program.

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Va. Air Board Approves RGGI Withdrawal

Virginia Gov. Glenn Youngkin’s (R) bid to remove the state from the Regional Greenhouse Gas Initiative (RGGI) passed its final regulatory hurdle as the Air Pollution Control Board narrowly approved ending the state’s participation in the program.

The board voted 4-3 at its meeting Wednesday to repeal the regulation implementing Virginia’s participation in the 11-state cap-and-trade program, a proposal first approved by the board and published for public comment in December. (See Va. Air Panel Votes to Exit RGGI.) Youngkin’s administration argued in a report last March that RGGI constituted a “direct carbon tax” on residents and businesses, saying that none of Virginia’s revenue from the program has been used to provide rebates to customers. (See Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers.)

Withdrawing from RGGI was one of Youngkin’s campaign promises, and the governor began the process just hours after taking office through an executive order directing Virginia’s departments of Environmental Quality (DEQ) and Natural Resources to draft emergency regulations that would allow the Air Board to repeal its 2019 rule allowing the state to join.

But even as representatives of Virginia’s energy industry urged the board to pass the measure during the comment section of Wednesday’s meeting, the majority of commenters called the repeal misguided at best and illegitimate at worst.

Only those who submitted comments during the public comment period earlier this year were allowed to address the board; the meeting agenda noted that about 1,600 of the 2,500 comments received were in opposition to the proposal.

Nate Benforado, a senior attorney with the Southern Environmental Law Center, joined many other presenters in arguing that the board was overstepping its authority because Virginia’s participation in RGGI is mandated by a state law passed in 2020.

“The law requires DEQ to issue this regulation in the first place; it mandated this regulation be issued. It used the word ‘shall.’ It’s not optional,” Benforado said, listing instances where the law specified actions to be taken by state regulators. “Does this really sound like a law that … envisions a world in which we are not in RGGI [and] that punted the decision of whether to participate in RGGI … to DEQ or this board? … This is a thorough, comprehensive framework that told DEQ and the other agencies involved exactly what they are required to do.”

William Stiles, executive director of environmental advocacy group Wetlands Watch, echoed Benforado’s argument that “a regulatory body does not have the authority to reverse a legislative decision.” He also put forward an economic case for RGGI, pointing out that participating in the initiative “has generated many hundreds of millions of dollars for Virginia” by providing funding for energy efficiency and flood resilience projects.

“It’s been said that RGGI is a bad deal for Virginia. The bad deal for Virginia was the status quo that existed before RGGI, where the only money available to localities for planning was a few thousand dollars a year out of [the Department of Conservation and Recreation’s] dam safety and floodplain management program,” Stiles said. “So we’re very strongly advocating that we stay in RGGI, not just because you can’t get out of it by regulation, but because of the benefits that it produces.”

Although board members made no response to these points during the meeting — other than to thank the participants for their input — the DEQ did provide rebuttals to public comments in the agenda. The department pushed back on assertions that withdrawing from RGGI by regulatory action was “unlawful,” arguing that its regulation for voluntary participation in the program predated the legislature’s mandate and that no “provision of law [limits] the board’s discretion to repeal the regulation and thereby withdraw from RGGI.”

Regarding the funding for energy efficiency and flood projects, the DEQ pointed out that “RGGI is not the only possible source of funding [or] the most efficient or transparent means of obtaining this type of funding.” Adopting a legalistic argument of its own, the department said that “appropriations and funding distributions for these types of projects are rightly the purview of the General Assembly and not a third-party organization.”

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MISO Poised to Extend Missouri Coal Plant’s Life

MISO said Tuesday that it will likely be forced to renew a Missouri coal plant’s operating extension for almost two more years.

Ameren Missouri’s (NYSE: AEE) 1.2-GW Rush Island Energy Center has been operating under a system support resource (SSR) designation since September, when FERC approved a one-year SSR agreement. (See FERC: Rush Island Plant’s Extension Essential to MISO Reliability.)

During a Central Subregional Planning meeting Tuesday, MISO’s Grant Larson said staff reanalyzed the system without Rush Island’s assistance and again found transient voltage recovery and steady state voltage violations if it is allowed to suspend operations. Larson said Rush Island’s SSR status will have to be renewed for another year Sept. 1 unless stakeholders can suggest generation or transmission alternatives by June 20.

“MISO likes to consider SSRs a last resort,” Larson told attendees, but he said the RTO has “unfortunately” not found any reconfiguration, redispatch or demand-response alternatives to avert another extension.

“Transient voltage recovery violations, that result in cascading outages and instability, cannot be mitigated,” he told stakeholders. He said more than 1,000 MW of load is at risk due to the violations.

MISO restudies system conditions annually to assess the need for SSR agreements.

Larson said transmission upgrades in the area that negate the SSR won’t come online until mid-2024 and 2025. He said the wind, solar and battery storage projects proposed in Illinois and Missouri won’t be available in time either.

While some system upgrades that will be completed by September have improved reliability performance and mitigated a few of the issues since 2022, Larson said, it won’t be enough to allow Rush Island to suspend operations. He also said the SSR’s cost allocation to load won’t be “drastically” different, though some elemental pricing nodes will change.

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ERCOT TAC Endorses Agreement on ‘Exceptional’ Fuel Costs

ERCOT stakeholders on Monday unanimously endorsed a protocol change that requires resources to file exceptional fuel costs that include contractual and pipeline-mandated costs, following negotiations between consumer representatives and a generator.

The Technical Advisory Committee had tabled the nodal protocol revision request (NPRR1177) during its regular May meeting to give the two groups an opportunity to work out their differences. They said their edits allow ERCOT to determine ineligible costs, clarify that exceptional fuel costs are distinct from fuel adders, and codify some of the attestation’s language. (See “Fuel-cost Discussion Tabled,” ERCOT Technical Advisory Committee Briefs: May 23, 2023.)

“I think we’ve landed in a good place,” Eric Goff, a member of TAC’s consumer segment, said during the virtual meeting.

“We’re supportive of the consumer comments,” said Constellation Energy Generation’s Andy Nguyen, the NPRR’s sponsor. “NPRR1177 is a vast improvement to what we have today.”

Constellation modified the attestation’s language to add that fuel costs be “accurate and variable” so that it is based on the resource’s actual dispatch. However, Nguyen said the NPRR still does not address a gap in the protocols where a mitigated resource has no cost recovery mechanism if it is uneconomically dispatched.

The revised version accepts ERCOT’s draft language presented during the May meeting. It also removes from the NPRR the complex task of developing standardized contract language. That has been referred to TAC’s Wholesale Market Subcommittee for additional discussion with the ISO’s staff.

A 2027 sunset date was modified to Jan. 1, 2025, to allow a permanent solution for the standardized contract.

TAC also re-visited NPRR1169, which expands the qualifications for generation resources that may be a firm fuel supply service resource or an alternate.

The Public Utility Commission urged additional discussion of the issue during its May 25 open meeting. The commissioners and ERCOT staff deliberated over safeguards to prevent facilities from being inappropriately disqualified if the qualified scheduling entity serves public needs through a gas distribution company elsewhere in the state.

The two staffs are working to ensure that pipelines providing firm gas supply to generators aren’t curtailed should the gas be designated for residential customers first.

Attorney John Arnold, who represents gas suppliers Kinder Morgan and Enterprise Products before both the PUC and the Railroad Commission, proposed an alternate definition for qualifying pipelines that addresses their deliverability at individual generators instead of systemwide.

TAC’s members declined to add comments to the NPRR, but ERCOT plans to file additional comments for the Board of Director’s consideration during its June 19-20 meeting.