Vineyard Wind 1 is on track to start generating power by the end of this year and achieve commercial operation by the end of 2024, Avangrid told investors in its third-quarter earnings call for 2023.
The 806-MW project’s construction is about 60% complete, with the offshore substation, 15 array cables, 25 monopiles and two turbines already installed, Avangrid CEO Pedro Azagra said.
Vineyard Wind is competing with New York’s South Fork Wind to be the first utility-scale offshore wind project to begin operations in the U.S.
“The lessons learned will be invaluable as we continue developing this project and others in the U.S,” Azagra said.
On Oct. 25, the company announced a $1.2 billion tax equity transaction for the Vineyard Wind 1 project with J.P. Morgan Chase, Bank of America and Wells Fargo. The financing uses tax credits from the Inflation Reduction Act (IRA), and marks “the largest single asset tax equity financing and the first for a commercial scale offshore wind project,” the company said.
“The IRA is bringing tremendous opportunities to the industry,” Azagra said, adding that the act is essential to the company’s plan to repower up to 4.6 GW of renewable assets by 2032, with the goal of increasing production by about 30%. “Repowering does not require full development and permitting, allowing the projects to reach completion much faster.”
Azagra also touted the successful termination of the Commonwealth Wind and Park City Wind power purchase agreements.
“By terminating these contracts, we have improved the economics of our offshore wind projects, and avoided billions in write-offs at minimum costs,” he said. “Now we have two highly valuable leases ready to leverage, and experience as part of Iberdrola Group developing, financing and constructing offshore projects like Vineyard Wind 1.”
“We’re not going to put in danger the financial health of the company,” Azagra said. “We’re not going to be in the race of growth for megawatts, we’re in the race of making money.”
Azagra also addressed what he called the “challenging regulatory environment in Connecticut.” Earlier this year, the state’s Public Utilities Regulatory Authority (PURA) denied a request from Avangrid subsidiary United Illuminating for an 8% rate increase over three years. In response, United Illuminating has filed an appeal with the New Britain Superior Court.
PURA’s decision would prevent the company from recovering “reasonably incurred costs, and [earning] a fair return on enough capital,” Azagra said. He added that this would “hinder [Avangrid’s] ability to invest in the grid to improve the storm resiliency and reliability and would slow down the state’s progress on its clean energy goals.”
The Energy and Policy Institute (EPI), a utility watchdog group, has alleged the company was behind a pressure campaign that coordinated employees and charitable organizations to oppose a draft version of PURA’s decision. EPI found the comments contained similar or identical language that it traced back to a United Illuminating lobbyist.
Solicitor General Elizabeth Prelogar has urged the Supreme Court to dismiss a petition to review a 2022 appeals court ruling that found Texas’ right-of-first-refusal law violates the Constitution’s dormant Commerce Clause.
Prelogar filed a brief with the high court Oct. 23 asking it to deny Texas’ request for a writ of certiorari, a formal request to review a lower court’s judgment against the petitioning party (No. 22-601).
At issue is the 5th Circuit Court of Appeals’ ruling last year that the Texas law (Senate Bill 1938) giving incumbent transmission companies the right of first refusal (ROFR) to build new power lines within the state is unconstitutional. Texas, with former Public Utility Commission Chair Peter Lake as the lead petitioner, requested the review in December. (See Texas Petitions SCOTUS to Review ROFR Ruling.)
“The court of appeals correctly determined that SB 1938 discriminates against interstate commerce by prohibiting any company without an existing in-state presence from competing in the market for the construction and operation of electric transmission facilities that would be part of the interstate transmission grid,” Prelogar said in her filing.
She said the Texas law “discriminates on its face against interstate commerce” and that the state’s “contrary arguments lack merit.” Prelogar also noted that FERCOrder 2023, which would overhaul transmission planning, would render moot a review of the 5th Circuit decision.
“If FERC were to adopt the proposed rule (or some alternative) while this case was pending before the court, that development might require supplemental briefing or otherwise complicate this court’s consideration,” she wrote.
Consumer advocacy group Electricity Transmission Competition Coalition welcomed the solicitor general’s filing.
“ROFR laws are not just unaffordable, they are unconstitutional,” the organization’s chair, Paul Cicio, said in an emailed statement. “Texas’ ROFR law was unconstitutional from the outset, and this was affirmed by the [appeals court]. Electricity transmission competition benefits consumers in the form of lower electricity prices; the filing of the United States is a welcome addition to the cause of lower electricity prices.”
Chris Reeder, a partner with Husch Blackwell in Austin, told RTO Insider that the Supreme Court’s request for the solicitor general to provide its opinion “indicates the court views the legal issues as having significant constitutional implications on which the government should weigh in.”
The opinion also means briefing on Texas’ request has been completed, he said. The justices will vote on whether to grant review and, if they do, the case will be set for argument and additional briefing requested.
“If it declines review, then the Supreme Court proceeding is over as a practical matter,” Reeder said. “The 5th Circuit’s ruling would become the ‘law of the case.’”
Texas could seek a rehearing of the denial, but those rehearing requests are almost never granted, Reeder said.
NextEra Energy brought an appeal to the 5th Circuit after the U.S. District Court for Western Texas rejected the utility’s challenge of SB 1938. The district court ruled the legislation didn’t discriminate against interstate commerce because it “regulates only the construction and operation of transmission lines and facilities within Texas.”
At the time, NextEra had been awarded a pair of competitive projects by MISO and SPP in Texas’ non-ERCOT regions. Both projects have since been cancelled, but NextEra has said it intends to pursue other projects in Texas.
The NYISO Management Committee recommended Oct. 25 that the Board of Directors approve the ISO’s proposed $194.8 million budget for next year, a $4.8 million (2.5%) increase. Because the spending will be allocated across a forecast throughput of 152.1 million MWh, a 2.9% drop from 2023, the Rate Schedule 1 charge/MWh will increase to $1.281/MWh, a 5.6% increase.
The spending plan adds 19 new positions, primarily in the planning and operations units. Other sources of the spending increase are hikes in consulting fees and staff salaries, which are proposed to increase by $7.1 million and $7.4 million, respectively. Much of the increase is offset by the $10 million increase in proceeds from debt.
The ISO said growth drivers, including new large loads, electric vehicles, heating electrification and economic growth, would be more than offset by growth in energy efficiency and behind-the-meter solar.
At the September MC meeting, some stakeholders were taken aback by the proposed staffing increases. (See “Draft Budget,” Emilie Nelson Named NYISO COO, Replacing Rick Gonzales.) Alan Ackerman, director of NYISO regulatory affairs at Customized Energy Solutions, however, justified the ISO’s draft budget, saying, “I think this does a great job of balancing the costs against the long list of items that need to get done next year.”
The spending plan was approved unanimously by the MC on Wednesday. The board is expected to vote on the budget Nov. 14.
NYISO/PJM Joint Operating Agreement
The MC recommended that the board approve proposed revisions to the ISO’s joint operating agreement with PJM, which governs coordination and data collection between the two grid operators.
The changes would migrate a list of interconnection tie facilities between NYISO and PJM from the JOA onto the web, add language clarifying that each operator adheres to its own procedures when developing and maintaining interconnection reliability operating limits (IROL), and make clerical edits to facilitate cooperation in the resource adequacy and transmission planning areas. The IROL are the limits the ISO and PJM develop to ensure steady state and transient performance on the grid, such as voltage stability and transfer capability.
Peer comparison | NYISO
Howard Fromer, who represents Bayonne Energy Center, asked about PJM’s status on this project and how the proposals would be filed with FERC.
Cameron McPherson, an associate market analyst with NYISO, responded, “we worked jointly with PJM to develop these revisions and they are in agreement on what we’re submitting.” He added, “[PJM] did present this information to their stakeholders earlier this month and did not receive any comments or questions.”
These proposals were approved by the Business Issues Committee in September and are projected to be implemented in the first quarter of 2024, assuming approval by the ISO’s board and FERC. (See “NYISO/PJM Joint Operating Agreement,” NYISO Business Issues Committee Briefs: Sept. 14, 2023.)
Interconnection & Transmission
The MC recommended that the board approve tariff revisions intended to improve the coordination between NYISO’s interconnection and transmission expansion studies.
The revisions would revise the criteria for including transmission projects in study assumptions, better capture generators outside NYISO’s interconnection procedures for the purposes of future system planning and improve coordination among transmission projects moving through the ISO’s interconnection processes.
The changes were recommended by the Operating Committee late last year, but the ISO delayed presenting them to the MC while it waited for FERC to rule on proposals by transmission owners concerning their right of first refusal for public policy transmission upgrades, which the commission approved in April of this year. (See “Interconnection & Transmission,” NYISO Operating Committee Briefs: Oct. 11, 2023.)
The board will vote on the revisions in November. Assuming they are approved, NYISO will request its proposals become effective 60 days from when they are filed with FERC.
September Operations
NYISO’s Emilie Nelson delivered her first monthly market and operations reports as chief operating officer, telling the MC that September experienced the summer’s highest peak load (30,206 MW) and that year-to-date energy prices were down 57% compared to last year, declining from $92.27/MWh to $40.06/MWh due to continued decreases in gas prices.
The peak load Sept. 6 happened during a multiday heat wave in which temperatures exceeded 90 degrees Fahrenheit. NYISO examined how this summer’s extreme weather events impacted grid operations and found that they currently pose little threat but will increasingly become a problem to the ISO’s operations should the pace of fossil fuel retirements continue to outpace the addition of renewable generators. (See “Summer Operations,” NYISO Operating Committee Briefs: Oct. 11, 2023.)
The ISO also added 20 MW of energy storage and 60 MW of behind-the-meter solar resources in September.
MC Election, Promotions
The MC voted to elect Glenn Haake, vice president of regulatory affairs at Invenergy, as new vice chair of the MC.
Haake reminded the MC that he was previously elected to be vice chair of the MC back in 2011, saying, “I’m excited at the prospect of being able to finish what I started a little more than a decade ago.”
He will work with MC Chair Julia Popova, NRG Energy’s manager of regulatory affairs, in his new role next year.
Nelson also told the MC that Shaun Johnson has been promoted to the ISO’s director of market design and Joshua Boles promoted to director of market mitigation and analysis.
CenterPoint Energy Thursday announced a leadership change atop the organization, with COO Jason Wells replacing the retiring David Lesar as CEO.
Wells will become CenterPoint’s CEO on Jan. 5. Lesar will work closely with his successor in the meantime to ensure a seamless transition, the Houston-based company said.
“I have full confidence that Jason is the right person to take the helm,” Lesar told financial analysts during the company’s third-quarter earnings conference call. “Now is the right time to advance this transition as our very strong third-quarter results demonstrate. We have great momentum and a solid foundation in place. Making this change at the beginning of 2024 allows Jason and the team to hit the ground running.”
Lesar, a former CEO with Haliburton, was brought out of retirement in 2020 to provide leadership after the Texas Public Utility Commission reduced a $161 million rate case settlement to $13 million. Scott Prochazka resigned as CEO shortly after the decision. (See New CenterPoint CEO Promises to ‘Simplify the Story.’)
Wells joined CenterPoint as its CFO in 2020, shortly after Lesar was appointed CEO. The two have worked together to “reshape and launch our utility-focused strategy,” he said.
Wells previously spent 13 years with PG&E Corp., where he worked his way up the ladder before eventually serving as CFO. He holds bachelor’s and master’s degrees in accounting from the University of Florida.
He thanked Lesar for his “tireless” leadership, mentorship and friendship and said he has “incredibly big shoes to fill.”
CenterPoint reported earnings of $256 million ($0.40/diluted share), compared to $189 million ($0.30/diluted share) for the same period a year ago. The company said the results primarily were driven by growth, regulatory recovery and favorable weather.
It was the 14th straight quarter CenterPoint has met or exceeded expectations, Lesar said. Zacks Investment Research had projected earnings of $0.37/share.
Commiserating with CenterPoint’s executive team over the Houston Astros’ recent elimination from the MLB playoffs, one analyst said, “You can win every year in the utility business, but you can’t in baseball.”
“So true,” Lesar responded. He closed the conference call by saying, “Just stick with us, because the best is yet to come.”
CenterPoint’s share price closed at $27.60 Thursday, a gain of 13 cents for the day.
At Wednesday’s meeting of NERC’s Member Representatives Committee (MRC), attendees reviewed their ongoing efforts to improve the group’s effectiveness representing the electric industry and providing “coordinated, thoughtful and valuable input to [the Board of] Trustees as well as NERC’s leadership,” in the words of Chair Jennifer Flandermeyer.
The meeting, conducted virtually, was the MRC’s last gathering of the year. Unlike most MRC meetings, the event was held separately from the ERO’s board meeting, as announced when the groups last met in Ottawa in August. (See “Future Meetings,” NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023.) The board’s final meeting of 2023 will occur Dec. 12 and also be held virtually.
The bulk of Wednesday’s meeting was dedicated to reports from the subgroups that the MRC established after the August meeting to examine how the committee could better fulfill its function representing industry in the ERO. Each subgroup is intended to explore a different theme:
Culture of collaboration and engagement — focused on succession planning and sustainability of the MRC, along with exploring how NERC’s structure can be used to facilitate committee engagement;
Balancing technical and policy discussions — intended to find the appropriate level of technical detail in discussions regarding NERC operations and strategy;
MRC structure review — evaluating the committee’s sectors to ensure they provide effective representation to the board;
Closed MRC meeting opportunities to discuss committee strategy — exploring the use of strategic closed sessions in which confidential information can be shared freely to promote grid reliability, security and resilience; and
MRC value proposition — exploring ways to align stakeholders on the committee’s value and responsibilities, and find further opportunities to add value.
Flandermeyer went first with a presentation on the collaboration and engagement subgroup, which she co-leads with MRC Vice Chair John Haarlow, of the Snohomish County Public Utility District.
As Flandermeyer put it, her subgroup is an “umbrella that overlays all the work across the different groups.” She said its discussions to this point have mainly focused on how best to bring new MRC members up to speed on the group’s purpose so they can start to “work effectively across the ERO Enterprise and with our industry peers.”
The subgroup has already begun to take action on “low-hanging fruit,” Flandermeyer said; examples include overhauling the MRC’s informational session, typically held the month before its quarterly meetings, to provide more context on the action items to be discussed at the gathering. Another topic of discussion at the subgroup is starting an “MRC ambassador” program next year, to help new members meet each other and branch out beyond their own sectors to build industry-wide collaborations.
Mark Spencer, director of identity and access management at GE Power, spoke next, discussing the technical and policy discussions subgroup that he co-leads with Greg Ford of Georgia System Operations Corp. Spencer said the subgroup has been setting up a “survey of the technical work that is being performed” by NERC’s other committees, which MRC members will be able to review for “reliability or resiliency gaps.” While the survey is not complete yet, Spencer said the subgroup intends to reconvene soon to “put more meat around the bones.”
After Spencer came the report of the MRC structure review subgroup, delivered by subgroup co-leader Rachel Snead, director of environmental services at Dominion Energy. The team has met twice so far, Snead said, and has determined that while “the appropriate sectors” are currently represented on the MRC, there is a need for members’ “expectations [to] be clarified to ensure the entire industry is represented by the individual MRC representatives.”
Elaborating on this point, Snead explained that the MRC was originally designed “along business lines and not fuel or function,” which has the potential to create problems as the grid moves to new generation sources that don’t cleanly fall into existing categories. She said members have specifically worried that operators of inverter-based resources like solar panels and wind plants might not be adequately represented in the current structure.
Snead said the subgroup considered adding new sectors, but considered this might “make the MRC too large [and] reduce its efficacy.” She said another option is to “solicit increased involvement and participation” among new participants and representatives from sectors that are currently “less populated,” reminding members that the MRC is “not for technical experts, but for strategic leaders that are representing their entire sectors … and are really agents for change.”
NYISO CEO Rich Dewey followed with an update from the closed MRC meetings subgroup, which has been examining the “untapped opportunities” for the committee to provide value to the board, particularly through policy input letters from the various sectors.
Dewey said that one topic of discussion for the subgroup is whether rather than “just forwarding that input along,” the MRC could help to analyze these means of communication, finding common concerns and areas of consensus. The subgroup is also looking for ways it can provide input for the board to help set priorities and strategy.
Finally, Matt Fischesser, of energy management company ACES, presented on the MRC value proposition subgroup. He said the subgroup has focused on assessing the MRC’s responsibilities relating to electing trustees, amending NERC’s bylaws and advising the board on the development of the ERO’s annual business plan, budget and other business. The next stage of their work, he added, will be to devise ways to bring greater transparency, effectiveness and efficiency to these areas.
Flandermeyer reminded subgroup heads that they are to report their findings to the MRC at its next meeting in February, to be held in person, along with NERC’s board meeting, in Houston. She said the MRC will then “take all of the recommendations … together to make sure that they’re coordinated, not duplicative, and that we’ve covered the most ground we can.”
Flandermeyer, Haarlow Re-elected
Wednesday also saw the MRC hold its annual leadership election, with Flandermeyer and Haarlow volunteering to another one-year term as chair and vice chair. ElectriCities CEO Roy Jones, who served as MRC chair in 2022, managed the meeting during the vote, for which Flandermeyer and Haarlow exited the virtual session. After their unanimous re-election, Jones congratulated the two leaders and thanked them for their willingness to continue serving.
“We’ve got so many things going on with the MRC; I think this is great, that we will have a couple of years of some continuity as we work through some of the initiatives that we’ve got on the plate,” said Jones.
Nominations opened in August to replace representatives whose terms will expire in February and will close Monday. Voting on nominees will begin Nov. 9 and wrap up Dec. 8.
Saying “divorce is not an option,” California Gov. Gavin Newsom met with Chinese President Xi Jinping in Beijing on Wednesday to bolster climate cooperation between his state and the People’s Republic of China.
The talks with Xi and other Chinese officials focused mainly on climate and economic issues, but also touched on human rights and the fentanyl crisis, according to the governor’s office.
While noting “major differences,” Newsom said working together on climate change “can be the bridge we’ve been missing.”
“I made it clear to Chinese leaders that California will remain a stable, strong and reliable partner, particularly on low-carbon, green growth,” Newsom said in a statement.
Also Wednesday, Newsom signed an agreement with Chairman Zheng Shanjie from the National Development and Reform Commission to combat climate change and advance clean energy development.
China is the world’s largest emitter of greenhouse gases and is responsible for almost a third of global GHG emissions. The U.S. is the second-largest GHG emitter, with roughly half the annual emissions of China in 2020.
About half of China’s GHG emissions come from its power sector, and the nation continues to add new coal plants.
California aims to reach carbon neutrality by 2045; China has set a 2060 goal.
Citing the impacts of the climate crisis on California, including floods and wildfires, Newsom called for efforts to meet carbon neutrality goals earlier. He emphasized the urgent need to transition away from fossil fuels.
As part of the discussion, Newsom touted battery storage technology. California has increased battery storage resources from 770 MW in 2019 to 6,600 MW as of this month, a number expected to grow to 8,500 MW by the end of the year, the state announced this week.
The California-China cooperation aims to reduce carbon emissions while fostering economic growth. The governments will work to accelerate the clean energy transition, including zero-emission vehicles, offshore wind and advanced energy storage technologies.
Newsom’s meeting with Xi on Wednesday was part of the governor’s weeklong trip to China.
On Tuesday, he visited China’s Greater Bay Area, a region consisting of Hong Kong, Macao and nine major cities. There, he visited the world’s first zero-emission city bus fleet, and the state entered a climate partnership with Guangdong Province.
The trip comes at a time of tense U.S.-China relations, and some say the visit could be politically risky for Newsom.
Given the complexities of the U.S.-China relationship, some see “subnational” efforts as key to climate action.
“The states really are where anything substantive is going to happen,” David Victor, co-director of the Deep Decarbonization Initiative at the University of California, San Diego, told NBC News.
Newsom coordinated his travel with the White House, Politico reported, and he was accompanied by Nicholas Burns, the U.S. ambassador to China.
“This was a very positive and consequential day for the United States,” Burns said in a statement following Wednesday’s meetings.
FERC on Oct. 24 fined independent power producer AES $6 million for failing to fulfill resource adequacy obligations related to eight of the company’s 12 generating units operating in Southern California (IN23-15).
At issue in the order was the performance capability of eight AES units at the Alamitos and Redondo Beach power plants, which were contracted through CAISO resource adequacy purchase agreements from June 2018 to May 2020. All 12 of AES’s units received payments for providing capacity to the ISO’s market during that time frame.
CAISO had contracted with the resources to bid energy into the ISO market and deliver their maximum output — or Pmax — should it become necessary during Southern California’s hot summer months. Before entering the contract, AES was required to submit a master file containing the operating and technical characteristics of each unit, including their Pmax ratings. ISO guidelines stipulate that a Pmax value be based on the highest MW output a unit can sustain over a 30-minute interval.
However, in August 2019 CAISO’s Department of Market Monitoring (DMM) notified FERC’s Office of Enforcement (OE) that AES had submitted inaccurate master file parameters to the ISO that overstated some of the resources’ Pmax values before entering the contract.
DMM reported to OE that summer readiness tests CAISO performed in spring 2019 and exceptional dispatches occurring in July 2019 showed that AES’s Alamitos units 3, 4, 5 and 6 and Redondo Unit 7 were unable to meet the Pmax values submitted to the ISO in the original master file, resulting in a total deficiency of 91.80 MW.
According to the DMM’s referral, the eight AES units were either unable to reach or maintain full capacity for a 30-minute interval after they were dispatched by CAISO. Regardless, AES had sold and, in some cases, financially benefited from RA contracts stating that their resources were operating at full capacity, FERC said.
As a result, OE found AES to be in violation of multiple sections of the CAISO tariff. The company did not admit or deny the violations but agreed to pay $2.97 million in disgorgement to CAISO and $3.03 million in civil penalties to the U.S. Treasury.
AES owns and operates a portfolio of generation of approximately 32,300 MW of energy worldwide. As of 2022, AES was one of the largest independent producers in California, with a capacity of 3,799 MW in the state.
New Jersey has revised its strategy for building the infrastructure to link offshore wind (OSW) projects to the grid onshore, abandoning a plan to have the developers in the state’s third solicitation submit connection proposals along with their wind farm plans.
Instead, the New Jersey Board of Public Utilities (BPU) on Oct. 25 agreed to split off the connection infrastructure part of the project from wind farm development and hold a separate solicitation for the infrastructure work. The wind farm solicitation, which is expected to be concluded with project selection in early 2024, will continue as planned.
Jim Ferris, deputy director of the agency’s division of clean energy, said that after reviewing the infrastructure component of the four bids submitted in the OSW solicitation, his staff concluded the original plan “imposes an unreasonable burden” on ratepayers. Splitting the two would increase competition by allowing infrastructure proposals from developers who had not submitted an OSW generation project, he said.
The BPU’s 4-0 vote — one seat is vacant — was one of two decisions at the meeting triggered by implementation challenges involved in creating infrastructure that can handle the massive escalation in electricity generated that’s expected as the state’s clean energy policies unfold.
Separate from the OSW decision, the BPU agreed to extend the development deadline of five community solar projects after the developers filed petitions stating the utility to which they would connect their projects, Atlantic City Electricity, would take between 20 and 32 months to connect them to the grid. That delay effectively would prevent them from meeting program-imposed deadlines, the developers said.
BPU Commissioner Zenon Christodoulou acknowledged the OSW decision would not please some stakeholders but was necessary.
“I understand the frustration that this must cause on behalf of some of the developers that solicited [projects] in good faith,” he said. “But we appreciate their partnership and look forward to working with them in the future to provide and promote a better product that will serve them the projects and the ratepayers.
Commissioner Mary-Anna Holden echoed the sentiment but said she was “very comfortable” with the decision.
“It is frustrating, but we’re moving ahead,” she said, adding that she backed the “approach that you’re going to take with the pre-build, and soliciting people that really have an expertise in this transmission building.”
New Solicitation
The state’s third OSW solicitation, which could add capacity of between 1.2 GW and 4 GW and perhaps more, follows a 2019 solicitation in which the BPU backed the state’s first OSW project, Danish developer Ørsted’s 1,100-MW Ocean Wind 1. In the second solicitation, the state backed Ørsted’s 1,148-MW Ocean Wind 2 project and the 1,510-MW Atlantic Shores project.
Gov. Phil Murphy (D) has set a state wind capacity target of 11 GW, of which the BPU so far has awarded 3,758 MW. Four bidders have submitted plans in the third solicitation (See NJ’s 3rd OSW Solicitation Attracts 4 Bidders.)
The BPU on Oct. 27, 2022, approved onshore transmission upgrades totaling $1.07 billion that were submitted under a groundbreaking use of FERC Order 1000’s State Agreement Approach. The approved projects would create a new substation to accept OSW electricity, known as Larrabee Collector Station. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The BPU acknowledged at the time that the projects’ selection under the SAA would not prevent future OSW generators from proposing different landing points or different routes to connect their offshore projects with the grid. In response, the board said it would require a successful bidder in its third OSW solicitation to “prebuild” offshore ducts and cabling to connect projects to the grid, known as PBI — creating a single corridor from the shore crossing to the Larrabee collector.
Ferris told board members Wednesday that the BPU planned for the offshore connection to link four OSW projects and land at the New Jersey National Guard Training Center in Sea Girt, from where it would connect to the Larrabee station. That “would minimize environmental and community impacts by resulting in a single short crossing and a single or limited onshore corridor to the point of interconnection,” he said. The BPU planned to recover the cost of the infrastructure through the state’s Offshore Wind Renewable Energy Certificate (OREC) system, which also would fund the OSW projects, he said.
However, Ferris said, the agency now believes the use of the “OREC funding mechanism” and the “requirement that the PBI could only be awarded to a developer who also receives an award as a qualified offshore wind project imposes an unreasonable burden on New Jersey’s ratepayers.”
“Staff has determined that a separate solicitation for the PBI open to transmission developers, transmission owners, offshore wind generation developers and other qualified firms.”
A separate solicitation would “would increase competition and lead to ratepayers’ savings,” he added. He said the BPU staff believed the move would “not affect the generation project component of the third offshore wind solicitation applications.”
Deadline Extension
In a separate case, the board approval of five deadline extensions in the state community solar program highlighted the difficulties faced by solar projects in some parts of the state in connecting projects to the grid.
Solar developers have for a while expressed concern about the challenges, and delays involved in getting projects connected, and cited the area served by Atlantic City Electric (ACE) in South Jersey as the worst. (See Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)
In outlining the case for an extension, Sawyer Morgan, clean energy representative for the BPU, noted that only 3 MW out of 33 MW of community solar project capacity that was approved by the BPU in the ACE area was expected to open within the program deadline.
The board’s unanimous vote comes as the state prepares to transition to a permanent program — the Community Solar Energy Program (CSEP) — after two heavily oversubscribed community solar pilot programs that resulted in the approval of 150 projects totaling 235 MW. (See NJ Opens Community Solar and Nuclear Support Programs.)
The BPU approved the five projects seeking extensions in the second pilot program. They include two rooftop solar projects developed by Solar Landscape in Millville; two by Trina Solar Development on a Pennsville landfill; and a landfill project created by Greenpower Developers in Stafford Township. The projects had an initial 18-month deadline requiring them to become operational by May 4, 2023, which the BPU subsequently extended to Nov. 4, 2023, Morgan said.
“The petitioners each separately engaged in discussion of alternative interconnection options, but ACE’s construction timelines still extended beyond the deadlines,” the BPU representative said. “All three indicated that they would have been able to fully complete project construction by the deadline were it not for the upgrades required for interconnection.”
The BPU representative said the difficulty of getting community solar projects online in areas served by ACE “may raise equity concerns for potential subscribers, as substantially more projects in other parts of the state have been able to become operational.”
A deadline extension is warranted, he said, because the problems they face “were systemic, unforeseen and unforeseeable by petitioners, and wholly outside of their control.”
Asked about the comments, Francis Tedesco, ACE spokesman, said in an email to RTO Insider that the company is “committed to continuing to work with local and state partners to accelerate the clean energy transition, including community solar, for the communities we serve.”
“We continue engaging with state electric utility companies, solar developers, the NJ Board of Public Utilities and other stakeholders and are actively working toward performing necessary energy grid upgrades to help accommodate community solar projects in our service area,” he said.
Speaking before the ERCOT Board of Directors on Oct. 17, the grid operator’s Independent Market Monitor, Potomac Economics’ Carrie Bivens, defended her organization’s recent report that the grid operator’s newest ancillary service “likely” raised the real-time market’s energy value by at least $8 billion.
Several directors latched on to the $8 billion figure during their meeting before Bivens stood at the podium, saying the figure was “erroneously reported” and “a billion-dollar headline that was inaccurate.”
In the report, the IMM said ERCOT’s recent implementation of ERCOT contingency reserve service (ECRS), its first ancillary service in 20 years, has nearly doubled the amount of required online reserves and resulted in “enormous” increases in market costs and shortage pricing when the market is long.
Procuring and deploying the service has reduced supply and liquidity in the day-ahead market, “significantly” raised demand for ancillary products and resulted in inefficient day-ahead ancillary service (AS) price spikes, Bivens said during a September working group presentation. (See ERCOT IMM Raises Concerns over Newest Ancillary Service.)
“We know that this service has not increased efficiency because of the analysis that we perform,” Bivens said, noting the ECRS business case focused on improving market efficiency. She said the report’s purpose was to show an “order of magnitude” so the board could understand the costs involved.
Bivens said the IMM intends to provide comments to staff’s annual AS methodology report to “tweak” how ECRS and non-spinning reserve is purchased “to bring that into alignment with what we think are more reasonable reliability goals.”
“I hope that we can engage you guys in December to talk more about the ancillary services methodology,” she said.
Former Rep. Bill Flores (R), the board’s vice chair and a proponent of dispatchable thermal generation, debated Bivens over AS products and their value in avoiding load shed, saying their additional costs are worth the alternative.
Board Vice Chair Bill Flores | ERCOT
“When you look at the cost of ancillary services that’s paid for to try to encourage reliability to try to create a reliable grid, the offset to that is that there was a cost of avoided load shed. What is the value of that?” he asked. “Basically, ancillary services are paying for the avoidance of load shed. I think you’d bet that reliability is important and that ought to be the goal of any grid operator.”
“Of course, absolutely,” Bivens responded. She said ancillary services are “very specific capacity products,” not general capacity products to meet a reliability standard.
“They’re very specific to follow the load and to ensure that the frequency is followed or, if a unit trips, to be able to replace those megawatts, but you still have reliability,” she said. “What I’m trying to point out is that they have very specific uses and, as specific uses, can be studied and analyzed to determine how many do you need to meet them.”
“The cost they’re offsetting is avoided load shed,” Flores said. “We need to look at the value of that. Somewhere, that’s got to be baked into this analysis … because load shed has a cost to consumers, the economy, to people, to physical health and so forth.”
“We should absolutely procure enough to have a reliable grid,” Bivens said. “We should have the right services to meet the specific attributes that the grid needs. But we should not buy more than that. More megawatts is just more cost. It’s not actually buying you any additional reliability. I think we would have been just as reliable this summer without these excess ECRS megawatts.”
The Public Utility Commission has a request for proposals out for the next four-year contract for a market monitor. Responses are due Oct. 30, with the new contract beginning Jan. 1. (See ERCOT Monitor’s Name Change Raises Legislative Concerns.)
1-Hour SOC for ESRs
The board approved a nodal protocol revision request (NPRR1186) that sets the minimum state of charge (SOC) for energy storage resources participating in two of ERCOT’s ancillary services (ECRS and non-spinning reserve), a move one energy storage developer said will have a “chilling effect” on attracting longer-duration batteries.
As modified by ERCOT and endorsed by the Technical Advisory Committee last month, the protocol change will reduce the requirement for storage resources to maintain a two-hour SOC down to one hour. The NPRR was remanded back to TAC by the board during its August meeting for further discussion and to address a “stranded energy” issue during scarcity conditions. (See ERCOT Technical Advisory Committee Briefs: Sept. 26, 2023.)
Storage developer Eolian, speaking for its segment, has opposed the measure throughout the stakeholder process. It says ESRs’ fast-ramping capability can be crucial during scarcity events and give other resources additional time to come online.
Ironically, ESRs produced a record 2.17 GW on Sept. 6, when ERCOT, faced with constrained renewable energy in South Texas, declared a Level 2 energy emergency alert after voltage dropped. (See ERCOT Voltage Drop Leads to EEA Level 2.)
ERCOT began the summer with more than 3 GW of energy storage and expects that total to hit 9.5 GW next year.
During a discussion before the board’s Reliability and Markets (R&M) Committee on Oct. 16, the ISO said it needs to know that a resource with an ancillary service obligation is available during the times it has bid into being available. The R&M unanimously approved NPRR1186.
“We came up with a better product,” committee chair Bob Flexon told the board. “We really did air it all out yesterday. I feel that all parties had ample time to express their thoughts and considerations.”
The board will direct staff to file priority NPRRs to handle compliance issues and financial penalties for nonperformance. The changes may be sent directly to TAC.
The board also approved two other revision changes:
NPRR1184, which clarifies ERCOT’s management of the interest it receives and is owed to counterparties for posted cash collateral and requires staff to credit counterparty collateral accounts for interest every month. The NPRR also requires ERCOT to report the interest calculation.
A system change request (SCR824) that increases the attachment file size and quantities allowed within the resource integration and ongoing operations system.
F&A Proposes Revised Budget
Flores, who chairs the board’s Finance and Audit Committee, said a review of ERCOT’s financial performance indicates the organization’s improved financials need to be considered when the PUC takes up the grid operator’s 2024-25 budget next month.
ERCOT has proposed a budget, approved by the board in June, that increases its system administration fee 27.9%, from $0.555/MWh to $0.710/MWh. The budget drew several questions from the PUC during an Oct. 13 public hearing. The commission will take up the budget a final time during its Nov. 2 open meeting. (See ERCOT Defends Admin Fee Increase Before PUC.)
Flores said interest income is expected to be about $27 million higher than initial forecasts and that this summer’s administration fee revenues were up about $6 million because of the additional load. Expenses that are down $4 million have given ERCOT about $36 million more available for 2025 than originally projected, he said.
“Those additional resources should be made available to reduce the impact of the cost of the system admin fee on the consumers of the state,” Flores said. “If you were to prepare the budget today and present that to the PUC, you could possibly come up with a system admin fee somewhere less than the 71 cents that we originally proposed.”
The F&A Committee, following Flores’ lead, has asked ERCOT staff to submit a revised rate calculation to the commission.
PUC Holds Weatherization Workshop
ERCOT staff and stakeholders updated the PUC on Friday during a public hearing reviewing winter weather preparedness, grid reliability and resiliency, and industry compliance with weatherization standards ahead of the 2023-24 winter season.
The grid operator said weatherization inspections are ahead of schedule in meeting PUC rules. Power plants are required to winterize their equipment against extreme cold and identify critical components susceptible to cold weather.
ERCOT also briefed the commission on its new firm fuel supply service, which ensures generators have backup fuel available on site, and demand response programs in the ERCOT region.
“Today’s work session was a great opportunity for us and the public to review the many steps Texas has taken to prepare for extreme cold weather,” Commissioner Will McAdams said.
The grid operator does not expect emergency conditions this winter but has issued an RFP for 3 GW of additional capacity to increase its operating reserves. Resources have until Nov. 6 to respond to the RFP; awards for three-month contracts (December-February) will be announced Nov. 23. (See ERCOT Searching for 3 GW of Winter Capacity.)
FERC agreed today to extend the compliance deadline for its interconnection queue rulemaking by four months to April 3, 2024, in response to requests from RTOs and utilities (RM22-14).
FERC Order 2023, issued in July, revised the pro forma generator interconnection queue rules to shift from a first-come, first-served serial process to a first-ready, first-served cluster study process, an effort to unclog backlogged queues filled mostly with renewable projects and storage.
The order also increased financial requirements for developers and set penalties for transmission providers that fail to meet deadlines for completing interconnection studies. Interconnection studies also must consider grid-enhancing technologies (GETs). (See FERC Updates Interconnection Queue Process with Order 2023.)
American Electric Power, Dominion Energy, PacifiCorp, the Edison Electric Institute and PJM filed requests for rehearing or clarification of the order, which the commission effectively denied when it failed to respond within 30 days.
The commission responded only to the extension requests, saying it would address the other issues raised on rehearing in a future order.
FERC initially set the compliance date for 90 calendar days after the rule’s Sept. 6 publication in the Federal Register, or Dec. 5. The new order extends the 90-day clock to 210 days for all transmission providers except for those with wholesale distribution access tariffs, which will have 90 days beginning when their RTO or ISO submits its compliance filing.
The commission said its extension “does not change or modify any other determination or other deadlines established by Order No. 2023, including the deadline for eligibility for interconnection customers to opt to proceed with a transitional serial study (for those interconnection customers tendered a facilities study agreement) or transitional cluster study (for those interconnection customers assigned a queue position) or to withdraw their interconnection requests without penalty (i.e., 30 calendar days after the transmission provider submits its initial compliance filing).”
