Beacon Wind submitted its construction and operations plan (COP) to the U.S. Bureau of Ocean Energy Management (BOEM) on June 5.
BOEM on June 29 announced it would initiate a review of the plan, inviting public comments through July 31 as it prepares an environmental impact statement for the project.
It’s the 11th offshore wind COP review BOEM has started since President Biden took office, with a goal of 30 GW of offshore capacity by 2030. But that burst of regulatory enthusiasm has not yet translated to a burst of construction activity.
Two small-scale projects totaling 42 MW are in operation and two utility-scale projects are under construction, both neighbors of Beacon.
Beacon itself has been in the pipeline for more than four years, and developers do not expect it to produce power until 2028. Nor do they expect to be able to build the first phase under the financial terms of the contract they signed with the state of New York in January 2021.
The development team of Equinor and bp petitioned in June 2023 for inflation adjustments for their Beacon Wind 1, Empire Wind 1 and Empire Wind 2 projects, saying the world had changed drastically and costs had risen dramatically.
Also, developers are trying to back out of power purchase agreements for two large Massachusetts OSW projects for the same reasons, and there are signs of financial strain in some other states’ OSW development portfolios.
Beacon occupies Lease Area OCS-A520 — 128,811 acres on the Outer Continental Shelf south of Massachusetts and east of New York. Equinor won a December 2018 BOEM auction with a $135 million bid, and the lease was executed in March 2019.
The developers in January submitted a proposal for Beacon Wind 2 in New York’s 2022 offshore wind solicitation, which has yet to result in contract awards. In this round, bidders had the option of including an inflation adjustment mechanism to address any cost increases.
BOEM says the Beacon Wind lease area holds the potential for at least 2,430 MW of nameplate generation. Beacon Wind 1 is proposed at 1,260 MW.
“BOEM is advancing the administration’s ambitious energy goals while remaining diligent in our efforts to avoid, minimize and mitigate impacts to ocean users and the marine environment,” BOEM Director Elizabeth Klein said in a news release. “As part of our environmental review process, we seek input from tribes, our government partners, the fishing community and other ocean users to inform our next steps.”
In-person public meetings for the environmental review are scheduled for July 18 and 20 in Dartmouth, Mass., and Queens, N.Y., respectively. Virtual meetings are scheduled for July 13 and 26. Details on the meetings and on submitting comment electronically are posted on the Beacon Wind page of BOEM’s website.
The Northeast Atlantic Coast is the early focus of the offshore wind industry, with clusters of multiple wind farms proposed east of Long Island/south of Massachusetts, as well as south of Long Island/east of New Jersey.
BOEM’s previously completed environmental impact statements for other wind projects in the region have predicted a potentially significant impact on marine life, and on area fisheries. But much remains unknown, due to the lack of operational data about offshore wind power projects individually and collectively.
The Northeast Fisheries Science Center of the National Ocean and Atmospheric Administration on June 15 announced a five-year partnership with the University of Rhode Island to explore the impacts of offshore wind on marine ecosystems and the people who live near or work on the ocean.
MISO and CAISO received above-average marks while other regions got middling to failing grades in a “report card” on transmission planning and development published last week by Americans for a Clean Energy Grid.
“Overall the grades leave a lot of room for improvement,” ACEG said in its report, which it intends to spur discussion about how the FERC Order 1000 transmission planning regions can improve their efforts.
“We hope parties in each region can see positive examples in other ones from which they might learn,” ACEG said. “Our intent is not to criticize. Instead, we aim to show that good performance is possible and achievable, and all regions can improve to reach an ‘A’ grade in the coming years.”
The Southeast region has the most room for improvement, “while the West (minus California), Mid-Atlantic (PJM), New England (ISO-NE) and Texas are also lagging in their planning and development efforts,” ACEG said.
ACEG represents a broad coalition of clean energy and conservation groups and companies such as Berkshire Hathaway Energy, Google and NextEra Energy, all “focused on the need to expand, integrate, and modernize the North American high-voltage grid.”
In its report, the group said FERC Order 1000 and the commission’s other efforts to promote regional planning have produced “lackluster” results.
In response, FERC issued a Notice of Proposed Rulemaking in April 2022 to require long-term regional transmission planning and increased state involvement in transmission cost allocation, among many other changes (RM21-17). (See Battle Lines Drawn on FERC Tx Planning NOPR.)
“The NOPR acknowledges that regional planning under Order No. 1000 failed to adequately plan for and meet transmission needs, driven largely by the changing resource mix and increasing load,” ACEG said.
ACEG is pleased to see growing recognition of the need for proactive transmission planning, Executive Director Christina Hayes said in a statement accompanying the report. “Without continued improvement, the U.S. grid will remain a barrier to reaching our climate goals, and result in more dangerous power outages that threaten lives and livelihoods.”
Assessing Transmission Capacity
The “Transmission Planning and Development Regional Report Card” was written by Grid Strategies Research and Policy Manager Zach Zimmerman. Hayes and Grid Strategies President Rob Gramlich helped develop its methodologies and analysis.
The report evaluates the performance of Order 1000 planning regions, not specific entities such as RTOs, because “many parties, besides the planning entities, bear responsibility for performance, including utilities, states, and other stakeholders,” it said.
It employs four metrics to grade the regions: planning methods and best practices; miles of transmission built and future transmission plans (i.e., plans that go beyond reliability upgrades); transmission capacity available for new resources; and congestion ($/MWh).
Transmission capacity available for new resources combined three metrics — cost to interconnect, time in queue, and project completion rate — “all of which indicate whether a region’s system has sufficient transmission capacity to connect new generation,” it said.
“No single metric is entirely dispositive, but in combination, they provide an accurate assessment of transmission capacity,” ACEG said.
Based on the criteria, Midwest/MISO and California/CAISO each earned a “B.” New York/NYISO and Plains/SPP received grades of “C+.” The report card gave “D’s” to Mid-Atlantic/PJM, New England/ISO-NE, Texas/ERCOT, Northwest/Northern Grid and Southwest/West Connect.
The Southeast region — composed of Southeast Regional Transmission Planning (SERTP), South Carolina Regional Transmission Planning (SCRTP) and Florida Reliability Coordinating Council (FRCC) — got an “F.”
Midwest/MISO
Transmission planning efforts earned MISO and CAISO their relatively high marks.
ACEG said MISO’s “B” grade — and its 86% score, the study’s highest — resulted largely from the ISO’s work on its 2011 Multi-Value Projects initiative and its first, $10-billion long-range transmission plan (LRTP) portfolio. The ISO would have received an even higher score if not for MISO South, “where relatively little transmission planning activity occurs,” the report said.
MISO said it plans to address system needs in MISO South and to establish stronger connections between its South and Midwest areas in future iterations of its LTRP effort. The grid operator also pointed out that its first LRTP portfolio is “one of the largest transmission portfolios in U.S. history.”
“Although we have not had the opportunity to fully review the report, MISO’s ranking highlights our continued focus on planning a reliable grid of the future,” MISO spokesperson Brandon Morris said in an emailed statement. “This is why transmission evolution is a key pillar of our ‘Response to the Reliability Imperative’ efforts.”
MISO refers to its joint responsibility with its members to ensure that the clean energy transition occurs in a reliable and orderly manner as its “reliability imperative.” It issued its latest report on those efforts in January.
California/CAISO
CAISO’s “proactive, scenario-based, multivalue” transmission planning over the past two years accounted for its high score, which at 85.8% nearly matched MISO’s.
The report highlights the ISO’s work with the California Public Utilities Commission and California Energy Commission to plan collaboratively for the state’s clean energy future and coordinate resource procurement and transmission development.
It commended CAISO’s inaugural 20-year transmission outlook, approved last year, which examined in-state needs and transmission lines required to import large quantities of wind energy from Wyoming and New Mexico. And it cited the ISO’s most recent transmission plan, which broke with CAISO’s traditional planning process to bring needed resources online faster while dealing with an interconnection queue that has grown too large and unworkable.
ACEG awarded CAISO an “A-” for its planning efforts but only a “C” for lines planned and built, giving it an overall grade of “B.”
“Although it received one of the highest grades with a ‘B,’ there is still room for improvement,” the report said. “California needs to develop the lines it is planning, which could create a congestion-specific metric and provide better public access to good interconnection cost data.”
In addition, “California receives a higher grade than most regions for taking a relatively successful and innovative approach to interregional planning,” it said.
CAISO’s 2021-22 transmission plan noted that the “interregional coordination process [with NorthernGrid and WestConnect] has not met expectations.”
As an alternative, “CAISO has implemented programs to enable import transmission from other regions, such as making the TransWest Transmission line a part of its balancing authority even though it is not in California, and the cost of the line will be paid for by off-takers,” the report said.
TransWest Express, which recently broke ground, will link Wyoming wind to markets in California and the desert Southwest.
“We are pleased that ACEG highlighted the value of this complex effort to develop a vision for what the transmission system will look like in 2040, and appreciative of close cooperation from the California Energy Commission and the California Public Utilities Commission,” CAISO Vice President Neil Millar said in a statement to RTO Insider.
New York/NYISO
After MISO and CAISO, New York/NYISO was the next highest scoring region with a 78.6% total, earning it a “C+,” “based on their transmission planning methods and recently developed plans for new transmission,” the report card said.
The grade reflected NYISO’s public-policy transmission planning processes, which identify high-voltage transmission projects necessary for New York’s transition to clean energy. It also gave NYISO good marks for building projects.
NYISO has a “proactive, scenario-based planning process … [that] incorporates multiple cases and scenarios over a 20-year evaluation time horizon and uses reliability, economic, and public policy metrics to evaluate projects and select a transmission solution,” ACEG said. “For example, New York, in its 2019 public policy transmission plan, studied transmission lines using three scenarios, including a base case, Clean Energy Standard and Retirement Scenario.”
“This planning process is why New York is graded relatively well,” it said.
New York has also succeeded in getting important transmission projects built, it said. “After many years of little planning, persistent congestion and little transmission, New York has improved dramatically in the last few years,” it said. “Significant lines connecting Quebec, upstate, and downstate areas reduced congestion, improved reliability, and achieved public policy goals.”
ACEG said that while “NYISO does very little proactive interregional transmission planning,” the recent lines, such as those connecting it to Quebec, might signal a more proactive approach.
NYISO’s cumulative grade might have been higher except for the “F” ACEG gave it for transmission capacity available for new resources. NYISO deserved the failing grade because New York had by far the slowest completion score (0% compared with 65% for SPP, the next lowest scorer) for getting new resources out of its interconnection queue studies and onto the grid, the report said.
In an email, NYISO responded that “New York has recently seen the most significant investment in new transmission in decades through the NYISO’s Public Policy Transmission Planning Process. While the process has been a great success, the NYISO has called for significant additional transmission investment through its Public Policy Transmission Planning Process to support the achievement of public policy requirements.”
“The NYISO’s System Resource Outlook report from 2022 found that extensive transmission investments will be necessary to deliver renewable energy to consumers and address new constraints from the future addition of new resources,” it said.
Plains/SPP
The report card gave SPP a “C+” while saying it has the potential to achieve an “A” if it continues with its planning upgrades.
The report points to SPP’s developing consolidated planning process (CPP), which integrates its transmission planning and generator interconnection processes. The CPP’s intent is to determine the transmission needed to interconnect new generation, provide transmission service, maintain reliability and resiliency and relieve congestion.
SPP also overhauled its generator interconnection process, instituting a three-phase approach that FERC approved last year, and says it is “aggressively” clearing the queue.
The grid operator currently has 556 projects in its queue, representing 111 GW of capacity; 43% of the proposed projects are solar resources.
According to the report, the Plains region has one of the lower completion rates for new projects, with a capacity-weighted rate of 2% for those entering the queue in 2017 and reaching commercial operation. In 2022, ACEG said SPP received almost triple the interconnection requests compared to their next-highest queue year in 2021.
“This historic queue will likely lead to problems going forward,” the report said.
Congestion is increasing in the Plains, thanks to significant curtailment of wind generation in recent years. The RTO’s Market Monitoring Unit reported in the 2022 State of the Market that average hourly curtailments increased “substantially” from 244 MW in 2020 to 1,260 MW in 2022.
ACEG credited SPP for its Joint Targeted Interconnection Queue (JTIQ) work with MISO but noted the process is “not necessarily reflective of all planning best practices … and primarily focused on generator interconnection requests.”
SPP could also “better incorporate” merchant developers into its planning, ACEG said.
The JTIQ process has identified 400 miles of projects on the seams valued at over $1 billion in investments, but their cost allocation has yet to be approved. SPP also has almost 700 miles of new lines planned or in development within its near-term and long-range transmission plans, representing a roughly $2 billion investment.
Texas/ERCOT
ERCOT, which delivers about 90% of the state’s electricity to 26 million Texas customers, was given one of the report’s lower scores, a “D+.”
ACEG awarded ERCOT high marks on interconnection but said it needs to address congestion soon.
ERCOT’s Independent Market Monitor’s 2022 State of the Market report said real-time congestion costs in ERCOT rose 37% last year to $2.8 billion.
Texas’ interconnection process uses a “connect and manage” approach to integrated interconnection and transmission planning, the report said. New generators only pay for their connection to the grid, as opposed to the “broader systems or affected interregional system costs that generators in other regions have to pay.” The generators don’t receive firm transmission rights and grid operators curtail them more quickly, ACEG said.
“However, easy interconnection without proactive planning can lead to congestion and curtailment as significant amounts of generation are added, filling up existing transmission capacity,” the report said.
Lawrence Berkeley National Laboratory’s 2022 Interconnection Queue report found Texas has the highest project completion rate of any region — 28% of capacity-weighted projects were commercialized — and one of the lowest wait times at 18 months. ERCOT’s queue has 902 projects and 250 GW under study, according to the ACEG report.
The report calls for ERCOT to adopt more “proactive, scenario-based, multivalue transmission planning.”
ERCOT’s latest regional transmission plan only identified new lines required for reliability upgrades over a six-year horizon, ACEG said. While Texas did build 2,400 miles of new transmission as part of the 2010-13 competitive renewable energy zones project, those projects are fully subscribed, the report said.
ACEG also said there is a “major need” for interregional transmission in Texas, as was made clear during the deadly 2021 winter storm. In dire need for energy to save a grid that couldn’t meet demand, the state was limited in what it could import from its neighbors.
As an islanded interconnection, Texas maintains its jurisdictional freedom from FERC by not mixing its electrons with those of its neighbors.
Legislation following the deadly 2021 winter storm has strengthened the Texas Public Utility Commission’s oversight of ERCOT’s transmission process. The PUC can direct ERCOT to build certain transmission facilities and a new law has cut the time to approve transmission certifications from 360 days to 180.
New England/ISO-NE
ISO-NE’s lack of proactive planning methods led to a low overall score, ACEG said, but the RTO received an “A” on the congestion metric.
ACEG found that transmission planning in New England “has traditionally focused on reliability and been reactive, rather than proactive,” noting that a significant buildout of transmission in the early 2000s cut down on congestion, but new resources in remote areas remain constrained. The report also said that ISO-NE would benefit from increased interregional planning.
“New England has done very little to coordinate with New York despite a rapidly growing amount of offshore wind hoping to interconnect close to the seam of both regions,” the report said.
In response, an ISO-NE representative highlighted the region’s history of making significant transmission investments, including almost $12 billion in grid upgrades since 2002.
“We have and will continue to work collaboratively with the New England states and energy stakeholders to determine how the region can build upon past success as the states look to meet their aggressive climate goals,” ISO-NE said.
In June, the New England states, New York and New Jersey, sent a letter to the US Department of Energy asking for federal assistance to establish a Northeast States Collaborative on Interregional Transmission, while ISO-NE, NYISO, and PJM supported the proposal in a separate letter.
The Collaborative would enable the states to “work in partnership to explore opportunities for increased interconnectivity, including for offshore wind, between our regions.”
Mid-Atlantic/PJM
PJM scored poorly in the report, which gave it low rankings for all categories except on its stakeholder process and governance. Its total planning grade was 65%, a letter grade of “D.”
ACEG faulted PJM for not considering if transmission proposals could be better addressed through regional projects, not conducting proactive generation and load forecasting and not modeling expected retirements in its 15-year planning period.
While there has been some use of the MISO-PJM Targeted Market Efficiency Process (TMEP), ACEG said interregional planning remains minimal, despite potential benefits related to offshore wind development coordination with the New York and New England regions. Coordination with MISO remains largely limited to operational reliability or short lead-time projects.
The report states that merchant developer proposals are studied through PJM’s backlogged interconnection process, which has resulted in FERC complaints about delays.
PJM spokesperson Jeff Shields responded to the report by pointing to the Summer Reliability Assessment released by NERC in May, which found much of the country outside of PJM is at an elevated reliability risk. He said work is already underway on expanding its planning methods as outlined in its Grid of the Future Paper released last year.
He said PJM’s queue overhaul, approved by the commission in December, will go into effect this month.
“The reforms will speed up and streamline generation interconnection requests, improve project cost certainty, and significantly improve the process by which new and upgraded generation resources are introduced onto the electrical grid,” he said.
Though he argued that PJM has made strides in improving the turnaround for interconnection requests, Shields said many projects that the RTO has completed studies on have yet to be built due to factors beyond its control.
“Today there are 44,000 MW of mostly renewable generation resources that have cleared the PJM study process but have yet to be built. The developers of these projects have everything they need from PJM to move forward with construction, but they are not building. We continue to hear that there are a number of factors unrelated to PJM that are causing delays, including supply chain, siting, regulatory issues or financing,” he said.
Northwest/Southwest
In the non-CAISO West, the Northwest/NorthernGrid planning region received a “D” grade, and the Southwest/WestConnect region earned a “D-.” Both are Order 1000 regional planning entities ostensibly responsible for grid planning across most of the Western Interconnection.
“NorthernGrid and WestConnect have not conducted proactive planning,” ACEG said. “The work of individual utilities or states in the region is much of why the regions managed a ‘D’ grade.”
Both regions received an “F” for planning methods and a “D” for congestion but significantly better grades for transmission capacity for new resources (B-minuses) and transmission lines planned and miles built (“B-” for Southwest/“C” for Northwest.)
“In the Northwest, individual utilities advance much of the significant high-voltage transmission buildout,” it said. “PacifiCorp and NV Energy are leading this effort. PacifiCorp’s planned transmission lines, known as the Gateway Projects … are an $8 billion investment and over 2,300 miles of new transmission lines.”
“NV Energy also has almost 600 miles of new transmission lines known as the Greenlink projects, which are just over $2 billion in investments,” it said. “However, NorthernGrid’s 2020-2021 transmission plan did not include any interregional or nonincumbent transmission lines.”
In the Southwest, WestConnect “did not identify any regional needs in its previous transmission plan,” the report said. “States, utilities, and merchant developers are driving most of the transmission planning and development in the region.
“For example, in Colorado, Xcel has planned the Colorado Power Pathway projects, an approximately $2 billion investment in almost 600 miles of high voltage lines that will help Colorado meet its goals by interconnecting 5.5 GW of resources.”
“In New Mexico, the [Renewable Energy Transmission Authority] has approximately 1,200 miles of new high voltage transmission under development that will interconnect almost 9 GW of new generation and represents over $5 billion in investments,” it said.
Southeast
The Southeast/SERTP, SCRTP and FRCC region came in last with an “F.”
“The region makes little information available to the public, has limited opportunities for stakeholders to engage meaningfully and has built and planned minimal regional transmission,” the report said.
The region failed under both the planning methods/best practices and transmission lines planned and built criteria. It got a “D” for congestion but came in second in the rankings with an “A-“ for transmission capacity available for new resources after scoring 100% for the time that projects spend in its interconnection queue.
In 2021, it took only 18 months from the time an interconnection request was made to the signing of an interconnection agreement in the Southeast. That compared to 51 months in SPP, the longest wait time in the nation.
Lawrence Berkeley’s Interconnection Queue report “showed that the Southeast had a queue size similar to NYISO or SPP, with over 800 project requests and around 100 GW of capacity,” ACEG said. “For our metrics, the Southeast scored well on completion rates for projects with 16% of projects reaching commercial operation.
“In addition, the Southeast scored well on time projects spent in the interconnection queue,” it said. “However, regions without an RTO rely on individual utilities to interconnect resources, and very little aggregated data or transparency exists on those project costs.”
‘Grades Can Change’
Even the lowest scorers can move up in the rankings, ACEG said in its concluding remarks.
“As with many students that grow over time, these grades can change as regions evolve their planning processes and transmission build out,” the report said. “This progress does not strictly depend on compliance with potential new rules from FERC, but on the initiative of the regions and their participants in enhancing their planning processes and building much-needed high-capacity regional transmission.”
“Future report cards will watch closely for improvement and look forward to regions moving to the head of the class,” it said.
Overall grade and summary of grades for each metric | ACEG
The New Jersey Board of Public Utilities (BPU) on Thursday approved an additional $150 million of expenses for the state’s $1.07 billion transmission project to connect offshore wind farms to the grid, saying the extra cost would not undercut the project’s financial benefits for ratepayers.
The 14% increase follows by eight months the board’s approval of the project in what the agency said was the first use in PJM of FERC’s state agreement approach (SAA), which allows a state or group of states to initiate a project to fulfill state policy requirements as long as they foot the bill for associated costs in the RTO’s transmission plan.
The cost rise comes amid growing scrutiny of New Jersey’s ambitious clean energy commitments, especially the plan to develop 11 GW of offshore wind capacity, with some Republicans and business groups demanding an estimate of the cost to ratepayers and questioning whether the investment is worthwhile.
As the BPU acted, state lawmakers in a last-minute vote before the summer recess backed a bill that would enable Danish developer Ørsted to receive federal tax credits to help meet cost increases in its Ocean Wind 1 project, rather than the state receiving the benefits of the credits. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)
“We have to keep moving forward,” BPU President Joseph L. Fiordaliso said before the board’s 5-0 approval of the order outlining the increase. “There are unfortunately many unforeseen developments that have occurred over the past couple of years prior to the pandemic and after the pandemic as far as the economy is concerned, where we see increases that were never anticipated.”
The BPU endorsed additional expenses of $40.76 million for several changes — described as “interconnection work” — in the scope of work, or additional elements of construction that were not part of the original bids approved in the solicitation. Part of that expense will pay for the engineering, procurement and construction of cables and connection points that would tie the offshore projects to the grid.
The interconnection cost increases also included Jersey Central Power & Light’s replacement of 115- and 230-kV transmission lines to make way for larger lines, and the replacement of certain equipment.
The board also approved $109.5 million in “scope-related cost estimate adjustments,” cost increases resulting from a closer analysis of the developer’s work and estimates. That included $27.1 million for the “reconductor of a small section” of a 230-kV line as a result of “updated communication between the developer and PJM,” which is a partner to the BPU in the SAA project. An additional $71.9 million stemmed from the “additional refinement” of the developer’s “cost estimates for their awarded scope,” which the BPU expected at the time the offshore wind project was awarded, the order states.
The $109.5 million estimate was reduced from the previously released revised estimate of $127.34 million, which was first reported at a May 9 meeting of the PJM Transmission Expansion Advisory Committee. (See NJ BPU Pulls Offshore Tx Project Mod from Agenda After Complaint.)
Ratepayer Benefits of Offshore Wind
Andrea Hart, BPU’s senior program manager for offshore wind, told the board the changes would not affect the agency’s estimation that the selected SAA solutions would save ratepayers more than $900 million, a figure calculated by looking at the “cost of the transmission facilities that would be necessary to achieve New Jersey’s offshore wind goals in the absence of an SAA solution.”
That’s because, according to The Brattle Group, a consultant working on the project, the cost increases would have been incurred anyway had the agency opted to tie in the offshore projects to the grid using a non-SAA agreement approach.
“Clearly, price increases are not uncommon,” said Commissioner Zenon Christodoulou. “But as a consumer, they’re never welcomed. So although we accept this and we appreciate all the efforts, I think that additional changes might not be as welcome.”
Brian Lipman, director of the New Jersey Division of Rate Counsel, who first raised concerns about the hikes in June, said he was “skeptical that these increases result in no change to the amount of benefit to be seen by ratepayers.”
“We still question whether the scope changes are in fact prudent increases,” he said in an email to NetZero Insider. “It is unclear to Rate Counsel why some of these issues were not identified in the initial bid. While we understand that some changes may be necessary (equipment not available or has been updated) these changes appear to be due to a failure to fully understand the project when bid.
“These increases are not due to changes in economics or increases in materials,” he wrote. “These changes are coming about because as the developers take a closer look at the work they bid to do, they realize that changes need to be made.”
Anticipated Future Hikes
The BPU awarded the main part of the SAA project — costing $504 million — to Mid-Atlantic Offshore Development (MAOD) and JCP&L to build a new substation called the Larrabee Tri-Collector Solution next to an existing JCP&L substation through which offshore wind projects would tie into the grid. The agency also awarded contracts totaling $575 million to seven smaller projects to upgrade existing onshore transmission identified by PJM as necessary.
The agency’s awards focused only on infrastructure on land, leaving the offshore infrastructure to be completed later by offshore project developers. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The order approved by the BPU last week said the original project selection anticipated that additional interconnection work would be needed but did not define whether it would be done by the SAA project developer MAOD or an offshore wind developer. Documents for the BPU’s third offshore wind project solicitation, released in March, outlined the winning developer’s responsibility for “prebuild infrastructure” that would build the necessary duct banks and access cable vaults to be used by all offshore wind projects to the new Larrabee substation.
The solicitation documents did not specify whether MAOD or the winner of the third solicitation would build certain parts of the infrastructure, and the BPU and its consultants recently concluded that the work would be best done by MAOD, adding to its costs, the order said. Pursuing that option would allow the work to be completed faster than waiting for the third solicitation process to be completed, would be safer and would yield various technical benefits, the order said.
The work included the engineering, procurement and construction of infrastructure to “accommodate” four HVDC lines and the work needed to design and build the trenches and collector lines for three alternating current lines, the order said.
“As transmission projects develop, it is common, if not expected, for cost estimate adjustments to occur,” the order states. “As such, additional cost estimate adjustments, in addition to the cost estimate adjustments noted herein, may be anticipated in the future.”
MANCHESTER, Vt. — ISO-NE is considering moving to a prompt and seasonal capacity market, the organization told stakeholders at its Participants Committee (PC) summer meeting last week.
The RTO has emphasized the need to address the seasonal variance of resource reliability in its capacity market, especially as it expects to transition from a summer peaking to a winter peaking system. The organization outlined potential options for transitioning to such a market, while also accounting for the implementation of Resource Capacity Accreditation (RCA) updates, which likely would affect the scheduling of future capacity auctions.
The RCA project has been an extended effort by the RTO to better assess the reliability of various resource types, which ISO-NE was hoping to implement for Forward Capacity Auction (FCA) 19, which would procure capacity for the 2028-29 capacity commitment period (CCP).
However, ISO-NE announced in June that it had found an error in the software used in the RCA project, which caused an underestimation of the amount of LNG available to generators when assessing winter risk. The RTO has said this error affected several months’ worth of work on the project and will affect its implementation schedule.
In a memo written prior to the PC meeting, ISO-NE Chief Operating Officer Vamsi Chadalavada asked for stakeholder feedback on the best way to incorporate the RCA project into the forward capacity auctions. ISO-NE also highlighted the potential of moving away from the current forward capacity market structure and holding auctions seasonally and just a few months ahead of the CCP.
ISO-NE wrote in the memo that moving to a prompt capacity market would buy time for the RTO to implement the market changes.
“In transitioning from a three-year forward to a prompt capacity market construct, there will be up to a three-year period between conducting the final forward capacity auction and conducting the first prompt capacity auction,” Chadalavada wrote.
David Patton of Potomac Economics, which serves as ISO-NE’s external market monitor, recommended transitioning to prompt and seasonal market as soon as feasible and said a seasonal market would do a better job accounting for the differences in seasonal reliability between resources.
Patton said the current process has a “a dubious track record of facilitating entry of new resources,” and that procuring capacity three years ahead “inhibits resources with fast development timeframes from receiving revenues as soon as they are able to support reliability.”
He noted that the existing FCA structure introduces uncertainty into the expected load and resource mix and added that the current market can also lead to premature retirement of older existing resources.
“Retirement of older units is often prompted by unforeseen equipment failure that is not economic to repair,” Patton said. “Such units must accept a capacity obligation that ends more than four years after the FCA, which creates substantial risk for the supplier.”
Presenting a cross-market comparison between ISO-NE and other RTOs, Patton found New England had the highest all-in costs in 2022, largely consistent with previous years. Patton said that higher gas prices in the region drive the higher overall costs but added that New England also has the highest capacity charges, largely due to “over-forecasted demand ahead of the FCAs, which are slow to correct.”
Comparison of RTO all-in prices | Potomac Economics
ISO-NE laid out four potential pathways for implementing the RCA updates as well as a prompt and seasonal capacity auction, including the possibilities of delaying FCA 19, delaying the RCA implementation and/or implementing a prompt and seasonal market along with the RCA changes for either the 19th or 20th auction cycle. The RTO noted that the removal of the Minimum Offer Price Rule will proceed for the 2028-29 CCP as scheduled.
Aleks Mitreski of Brookfield Renewables expressed his opposition to delaying FCA 19 due to the uncertainty this could introduce.
“ISO-NE has a great track record of never delaying an auction, so having FCA 19 run as scheduled will avoid market uncertainty and any regulatory uncertainty if the delay is challenged at FERC,” Mitreski said in a statement to RTO Insider. “By pushing the RCA implementation for FCA 20, this will give the stakeholders time to evaluate the RCA changes, as well as the benefits and tradeoffs for implementing a seasonal and/or prompt capacity market.”
Mitreski added that a move to a prompt and seasonal market would introduce several tradeoffs, and that stakeholders will need time to evaluate the merits of such a change.
“While it will help with the fuel qualification processes for RCA, a prompt market does not enable new entry in the market to address any retirements or transmission issues,” Mitreski said. “The only fix for those reliability issues would be expensive out-of-market reliability-must-run agreements like we have seen in NYISO in the past, something that the New England region wants to avoid.”
Budget Increase
ISO-NE also told the Participants Committee that it expects a significant year-over-year increase for its 2024 budget in its presentation on its preliminary budget for the coming year, equaling a 21.5% increase in the total revenue requirement for 2024.
This increase is driven by increased costs related to preparing for the clean energy transition, effects of inflation on labor and information technology costs, and the net-change from the annual revenue true-up, the RTO said. The largest single portion of the increase is associated with adjustments to employee salaries.
ISO-NE preliminary 2024 budget | ISO-NE
“The 2024 budget represents a ramping-up of organizational capacity to carry out the organization’s mission of planning the transmission system, administering the region’s wholesale markets, and operating the power system to ensure reliable and competitively priced wholesale electricity; as well as developing new capabilities that will be necessary for supporting the grid of the future,” ISO-NE CFO Robert Ludlow said.
Ludlow said that the RTO needs to increase staffing to meet clean energy planning needs, noting that the changing resource mix and the overall increase in generating assets will increase the organization’s workload. For 2024, the RTO proposed the addition of 40 new full-time employees, 34 of whom would be focused on supporting the clean energy transition.
“In order to keep pace with the needs of the transition to cleaner generating resources, the ISO must begin ramping up its capabilities and operational capacity now,” Ludlow said.
FERC on Friday accepted NYISO’s proposed tariff revisions that it said will prevent generators not using their capacity resource interconnection service (CRIS) rights from retaining them and allow for more efficient transferring (ER23-1824).
The revisions are intended to make it easier for deactivated facilities to adjust their unexpired CRIS rights while also increasing capacity deliverability headroom and potentially lowering the cost of market entry for future facilities by lessening the need for deliverability upgrades.
CRIS is required to participate in NYISO’s capacity market and can only be obtained either through a transfer from a facility with existing rights or from ISO deliverability studies.
“NYISO’s proposal adds greater clarity and flexibility regarding the rules applicable to CRIS transfers and bolsters the existing CRIS retention and termination rules,” FERC said. “We agree with NYISO that these revisions will help facilitate the full and efficient utilization of existing interconnection capacity by mitigating the retention of CRIS by suppliers who are not fully utilizing or who are unable to fully utilize their CRIS, and by enabling the more efficient transfer of CRIS between facilities.”
The Long Island Power Authority and energy storage development company Elevate Renewables F7 did not oppose NYISO’s proposal, but they suggested several changes to address concerns they had with it. As they did not lodge any protests against the filing, FERC did not address their concerns, ruling their suggestions outside the scope of the proceeding.
A group of North Carolina businesses urged the state’s legislature and governor to support studying “wholesale market competition options,” including an RTO, saying they were “concerned over limited access to cost-competitive, clean energy.”
In a letter sent Thursday to the General Assembly and Gov. Roy Cooper (D), the businesses endorsed North Carolina House Bill 503, introduced in March. The bill would direct the North Carolina Collaboratory — a clearinghouse established among the state’s public universities to provide useful research data to state and local governments — to “evaluate reform of the [state’s] regulatory wholesale electricity market.”
Studies undertaken under the bill would have to include an evaluation of designated market structures — an RTO within either North and South Carolina or the entire Southeast U.S.; an energy imbalance market within the same areas; or participation in the Southeast Energy Exchange Market (SEEM) — along with “any other market reforms the Collaboratory [deems] appropriate.”
In May, the South Carolina Legislature received a report that said participating in an RTO could provide the state benefits of up to $362 million per year. (See Brattle Report Sees Benefits for SC RTO Membership.)
Signers of the letter include hotel chain Marriott, food and beverage brands Sierra Nevada and Nestle, solar power developer Carolina Solar Energy, and Unilever, along with advocacy groups such as the Carolina Utilities Customer Association and the Clean Energy Buyers Association (CEBA).
In a statement on CEBA’s website, Reese Rogers, the organization’s Southeastern market and policy innovation manager, said “expanding [the state’s] market options … would help drive innovation and cost savings for all energy customers and improve grid reliability and resilience.”
“House Bill 503 would open a path for North Carolina to move toward greater options for customer choice and grid reliability,” Rogers added.
Despite the legislation’s nod toward SEEM, CEBA has been an active opponent of the market since it was proposed. It is party to a lawsuit in the D.C. Circuit Court of Appeals seeking to overturn SEEM’s approval by FERC in 2021. (See Environmental Groups Appeal SEEM in DC Circuit.)
Topics to be examined under the legislation include the costs, benefits and risks to a range of stakeholders from both the state’s current electric system and potential market changes in terms of generation capacity adequacy and diversity, customer service and rates, environmental quality, and other factors. The Collaboratory would also be tasked with identifying any laws, regulations and policies that may need to be changed to implement reforms, their impact to disadvantaged populations and communities, and any challenges associated with nuclear plants within the state.
While the proposed studies do not specifically mention reliability, the topic is prominent in the bill’s introduction, which says “North Carolina must be prepared for future weather events,” such as the 2022 holiday storms that led Duke Energy to implement rotating outages that left about 500,000 customers without power. (See North Carolina Regulators Face Questions on Holiday Outages.)
The introduction links the topics of reliability and market reform by noting that the state’s electricity is predominantly “provided by vertically integrated … distribution and transmission” utilities, and citing previous legislation requiring utilities to “diversify the resources used to reliably meet … energy needs.”
The businesses’ letter also referred to the winter storm blackouts, saying they “highlight the urgent need for sufficient reliable and affordable electricity in North Carolina.” The businesses added that the “ability to source clean, competitively priced [reliable] electricity … is a core factor in where we decide to make or maintain investments” and warned that “limited access to cost-competitive, clean energy” might discourage companies from doing business in the state.
The Texas Public Utility Commission on Thursday unanimously approved ERCOT’srequest to nearly double compensation for its independent directors, the board’s first increase since 2012.
The order increases the eight directors’ annual compensation from $87,000 to $160,000, an 83.9% increase. It also raises the supplementary compensation for the board chair from $12,800 to $35,000 and from $7,500 to $15,000 for the vice chair. Committee chairs also will now receive an additional $25,000, up from $5,600. (54444).
“There have been a lot of changes and a lot has happened at ERCOT over the last decade and we should compensate appropriately,” PUC interim Chair Kathleen Jackson said during the open meeting.
Commissioner Will McAdams noted that until 2021 legislation removed market participant representatives from the board in favor of independent directors, ERCOT was able to compensate its board at lower levels. Under the new rules, the grid operator’s directors are required not to have fiduciary duty or assets in the ISO’s market and must divest themselves of energy-related investments.
“That makes this a fairly restrictive framework around finding qualified people who can serve,” McAdams said. “In principle, I want a system managed by individuals who can dedicate the time and focus to a grid that is in the midst of [a] most significant energy transition. I believe this will allow us to recruit and retain a dedicated governing body for the system, independent of the industry, which was the legislature’s intent and to be able to execute the reforms that we are required to implement along the timetables that we are required to implement them by.”
Commissioner Jimmy Glotfelty said he struggled with compensation increases for grid operator executives and their board members, saying comparing their salaries to those of publicly traded companies is not a “correct comparison.”
“We have to protect ratepayers … I just hope that in time, we set this and we leave it. We can’t let this be a spiraling issue where costs go unchecked for the consumers of this state,” he said before voting in favor of the increase.
Commissioners Lori Cobos and Peter Lake were both absent from the meeting for personal reasons. Lake’s term expired Friday.
The ERCOT board and its Human Resources and Governance (HR&G) Committee both approved the increase in June following its annual review of director compensation.
The board hired executive compensation consulting firm Meridian Compensation Partners to perform a benchmarking analysis that analyzed compensation at other ISOs and RTOs, comparably sized general industry companies, ERCOT market participants and other public companies.
ERCOT said the firm consulted with HR&G in making its recommendation, which was based on considerations that included the directors’ high volume and complexity of work, recruitment considerations and external optics and standards.
The compensation became effective July 1.
The ISO’s eight independent directors are appointed by the state’s three-person ERCOT Board Selection Committee, which is comprised of appointees from the governor, lieutenant governor and the Texas House of Representatives’ speaker.
The board’s non-voting ex officio members — the ERCOT CEO, PUC chair and the Office of Public Utility Counsel’s CEO — are not covered by the order.
Recent legislation will increase the board to 12 members in September when a second PUC commissioner becomes an ex officio member.
ERCOT staff said last week that it faces a tight timeline to add a new ancillary service by Dec. 1, 2024, as required by a recently enacted Texas law.
Texas lawmakers passed a sunset bill (House Bill 1500) that includes a directive to ERCOT to develop an uncertainty product called dispatchable reliability reserve service (DRRS). Based on historical variations in availability for each season, the DRRS’ criteria require participants to be online and dispatchable for less than two hours after being deployed and to run for at least four hours at their high sustained limit.
Kenan Ögelman, ERCOT vice president of commercial operations, told the Technical Advisory Committee on June 27 that staff are still working through its options, but that the date is “very, very limiting in terms of what we can do.”
“The only real chance we have to meet that statutory deadline is to use an existing service, but we are hopeful that maybe stakeholders will have some brilliant idea that we didn’t think of,” Ögelman said.
The DRRS’ objective is to reduce ERCOT’s reliance on reliability unit commitments (RUCs), which have soared under the grid operator’s conservative operations posture during the last two years. The legislation requires that RUCs be reduced by the amount of DRRS that is procured and that the product be provided by offline resources.
ERCOT’s Kenan Ögelman explains the obstacles facing the new ancillary service. | ERCOT
Because ERCOT also uses RUCs for local reliability needs, as required by NERC, Ögelman said RUC reductions can only be achieved when they are not needed to cover load and reserve obligations. He also warned that DRRS’ deployment will have implications on prices as its reliance on offline resources means there will be less energy available for dispatch.
“I do think there are going to be things that impact both forward positions and contracts and so forth,” Ögelman said.
Given the time constraints, members discussed repurposing other ancillary services, including its first new product in more than 20 years, ERCOT contingency reserve service (ECRS), as well as non-spin reserve service. ECRS provides the system with additional capacity that can ramp in 10 minutes to respond to short-term net load ramps, and non-spin offers capacity that can be available in 30 minutes to cover forecast errors or to replace deployed reserves. (See “New Ancillary Service Deployed,” ERCOT Board of Directors Briefs: June 19-20, 2023.)
Carrie Bivens, who leads ERCOT’s Independent Market Monitor, said she was “disheartened” by the discussion of procuring more ECRS and called for a holistic review of ancillary services.
“I like the idea of repurposing non-spin … so adding more is going to have unintended consequences,” she said. “A big portion of the non-spin that gets procured is for six-hour load-forecast uncertainty, and I don’t know why you need a 10-minute online product to handle that. I think we have too many megawatts behind the house right now.”
Staff plan to schedule workshops in July to solicit broader stakeholder input and continue to evaluate the pros and cons of other alternatives. Discussions with the Public Utility Commission and stakeholders will continue into August, when staff will also begin to develop the protocols. Ögelman said he hopes to bring a recommendation to the Board of Directors in October and secure the PUC’s approval in November, giving staff a year to translate the protocols into requirements, develop the software and deploy the product.
“None of this is set in stone,” Ögelman said.
Eric Goff, who represents residential consumers, said the uncertainty over the ancillary services market makes it difficult for retailers to determine their charges to consumers.
“The sooner we can resolve this, the better,” he said. “The uncertainty could cause problems. This also ties into the importance of the ancillary services methodology.”
Real-time Co-optimization Is Back
ERCOT’s Matt Mereness told the committee that staff will “blow the dust off everything” in resuming work this week on the real-time co-optimization (RTC) project.
The market mechanism would expand ERCOT’s real-time market by clearing energy and ancillary services every five minutes, as most other grid operators already do. However, it has been on hold since the February 2021 winter storm. ERCOT leadership has said RTC’s reliability benefits in addressing future operational challenges make the tool a strategic priority.
“The key delivery areas that we have is heads down on [writing] the business requirements [and] getting the band back together,” Mereness said. “We’re off and running with this program.”
Staff and market participants drafted and received approval for eight nodal protocol revision requests (NPRRs) related to RTC before the project was halted. However, a battery task force was unable to complete its work on state-of-charge modeling when dispatching batteries. With batteries expected to be capable of providing 14 GW of energy by 2025 and RTC touching almost every major system, Mereness said, staff and stakeholders will also have to address battery functionality as part of the project’s effort.
An updated ERCOT impact analysis has reduced the project’s costs down to about $50 million to deploy in 2026, thanks to some hardware savings and “right-sizing” some of staff’s efforts.
The RTC’s development will begin in April 2024, Mereness said, with the primary risk being maintaining staff availability without interruption during the 3.5-year effort.
“We know this is a squeeze play,” he said. “RTC doesn’t come in and take over everything; it has to fit in with everything else. But the executive team said, ‘Let’s do this and keep the foot on the pedal where we can to keep this thing moving forward.’”
7 Revision Requests Pass
TAC unanimously approved a combination ballot that included two NPRRs, two revisions to the nodal operating guide (NOGRRs), an other binding document request (OBDRR), and single changes to the load-profiling (LPGRR) and planning guides (PGRR). If approved by the board, these changes would:
NPRR1150: require qualified scheduling entities (QSEs) that represent resource entities, emergency response service resources or other QSEs, and that receive or transmit wide area network (WAN) data to maintain connections to the ERCOT WAN and a secure private network.
NPRR1163 and LPGRR070: discontinue the process of evaluating interval data recorder meters to determine whether any are weather-sensitive.
NOGRR230: ensure the WAN data transmission’s integrity by requiring data be shared in a manner that prevents denial of service and distributed denial-of-service attacks.
NOGRR251: add cold weather conditions to the template used for developing emergency operations plans to align with NERC Reliability Standard EOP-011-2 (Emergency Preparedness and Operations).
OBDRR045: edit the demand response data definitions and technical specifications, including modifications to the electric service identifiers list provided to retail electric providers.
PGRR103: require interconnecting entities to complete all conditions for commercial operation of a generation resource or energy storage resource within 180 days of receiving ERCOT’s approval for initial synchronization.
FERC on Thursday issued Order 898, its final rule updating its Uniform System of Accounts (USofA) to account for rapid changes in technology and the resource mix in the power industry (RM21-11).
The changes adopted in the final rule will add functional detail to the USofA to provide uniformity, consistency and transparency in accounting and reporting for investments in renewables and other newer technologies.
The rule creates new subfunctions and accounts for wind, solar and other renewable generating assets. It establishes a new functional class and accounts for energy storage assets. It also creates new accounts and codifies accounting treatment for environmental credits and creates new accounts for computer hardware, software and communication equipment within existing functions that do not already include them.
The new rules also created new accounts and codified the accounting treatment of renewable energy credits.
“By adding functional detail to the USofA, these reforms will provide uniformity, consistency and transparency in accounting and reporting for investments into these assets and assist the commission in fulfilling its responsibilities under the FPA to ensure that rates remain just and reasonable,” the order said.
Given the rapid expansion and development of renewable generation, FERC concluded that its accounting system must be changed to better deal with the technologies.
FERC first proposed the changes in a Notice of Proposed Rulemaking last year and said it largely adopted the proposal with some changes to better reflect its intent, to address the needs of stakeholders and to facilitate solutions to potential technical challenges. (See FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables.)
The USofA goes back to when FERC was called the Federal Power Commission and was meant to facilitate its ratemaking responsibilities and uniformly capture financial and operational information for utilities, and then natural gas pipelines. It has been updated previously to reflect changes in the industry and law, including after the 1990 Clean Air Amendments to account for its creation of sulfur dioxide emissions allowances.
It was also updated 10 years ago in Order 784, which dealt with energy storage technologies, but those changes underestimated the additional burden that functional reporting, along with frequent reclassification of plant assets and associated depreciation, imposes on utilities. The new rules around storage are meant to simplify and improve the recording and reporting of energy storage assets and related expenses.
The USofA already included discrete production accounts for steam, nuclear, hydraulic and other resources, but it did not contain accounts designated for solar, wind or other nonhydro renewable generating assets. Regulated firms used to put their renewable generation in the “other production” accounts, and FERC noted before it issued the NOPR that parties disagreed on whether new accounts would be useful.
But none of the old categories clearly described solar panels, photovoltaic inverters, wind generation towers, or the computer hardware and software required to operate such generators. Related operations and maintenance accounts also failed to uniquely accommodate costs to maintain wind and solar facilities.
The USofA also did not explicitly address the purchase, generation or use of RECs, which are similar to the sulfur dioxide emission allowances from the Clean Air Act and previously were included in those accounts.
FERC last week rejected four separate rehearing requests related to SPP’s revenue credits under Attachment Z of its tariff, reaching the same conclusion it did in a November order last year while also offering clarifications.
Oklahoma Gas & Electric (EL19-77), Western Farmers Electric Cooperative (EL19-93), Cimarron Windpower (EL19-96) and four renewable developers (EL19-75) asked for a rehearing of FERC’s previous ruling. The commission’s order partially granted complaints over SPP’s revenue-crediting process but rejected OG&E’s complaint. (See FERC Partially Grants Z2 Protests Against SPP.)
Citing the 2020 Allegheny Defense Project v. FERC decision that ruled the commission could no longer grant rehearing requests “for the limited purpose of further consideration,” FERC on Tuesday denied each of the requests “by operation of law.”
The commission modified its discussion in the OG&E docket and set the order aside, in part. The utility had argued that requiring it to refund revenue credits related to the use of its transmission facilities would violate Attachment Z2 and a sponsored upgrade agreement with SPP dating back to 2008.
Under Attachment Z2, SPP transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrades. SPP had been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)
FERC agreed with OG&E’s contention that SPP had violated Attachment Z2 during the historical period and that the commission erred in finding the utility had not raised this argument. It also found that, consistent with its findings in the other three proceedings, SPP violated the attachments, sponsored upgrade agreement and the filed rate doctrine.
The commission said even if SPP acted in good faith in implementing and administering Attachment Z2, the tariff violation may result in an outcome that is unjust and unreasonable and/or unduly discriminatory or preferential. It granted OG&E’s complaint in part “insofar as OG&E alleged” the violations.
However, FERC again denied OG&E’s requested remedy — that SPP refund Z2 revenue credits. It said the grid operator lacked revenue credits to provide as restitution and that those funds lie instead with the transmission customers that SPP’s tariff “excuses from credit payment obligations.”
BHE Renewables, Marshall Wind Energy and Grand Prairie Wind filed a limited request for clarification or a rehearing. The commission responded by explaining that it granted several parties’ late motions to intervene in the dockets, although it did not list them. It said it granted their interventions “given their interest … as demonstrated in their motions to intervene and the absence of undue prejudice or delay.”
“Because we grant intervenors’ request for clarification, we dismiss as moot their alternative request for rehearing,” FERC said.
