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February 22, 2025

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Pathways ‘Step 2’ Bill Introduced in Calif. Legislature

California state lawmakers on Feb. 20 introduced a much-anticipated bill to implement “Step 2” of the West-Wide Governance Pathways Initiative, marking a significant step toward the creation of a new independent “regional organization” (RO) to oversee governance of CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market.

California Democratic Sens. Henry Stern and Josh Becker introduced SB 540, also known as the Pathways Initiative, saying in a news release that the bill “establishes an innovative framework for regional energy cooperation while preserving California’s authority over key aspects of its electricity system and climate goals.”

The bill language will become public Feb. 21.

“As we move toward achieving California’s 100% clean energy goals, we must look at all possible solutions to reduce costs, improve reliability and cut emissions,” Becker said in the news release. “Pathways strikes that balance by unlocking the benefits of a regional energy market while safeguarding California’s critical public policy priorities. It offers a win-win scenario for California — achieving cleaner energy, more reliable power and real savings for ratepayers.”

The Pathways bill would allow CAISO and California utilities to enter energy markets governed by a new RO if the RO meets certain criteria. CAISO would maintain its role as a California-governed balancing authority “so that California and CAISO retain control over procurement, environmental, reliability and other public policies,” according to a fact sheet.

The bill aims to expand CAISO’s Western energy markets and allow stakeholders to tap into a wider market of electricity resources while ensuring California does not have influence over participating states’ public policies. It strives to solve governance issues that have hampered similar market initiatives in the past.

“SB 540 will ensure that we reach our climate goals in the most cost effective and reliable manner possible by tapping into a much wider set of Western resources — lowering energy bills, improving grid reliability and reducing pollution in front-line communities, while also retaining control of our procurement, environmental, reliability and other public policies,” the fact sheet stated.

The Pathways news release included comments from several backers of the bill who expressed their support.

“Enhanced coordination among Western states will bring benefits to Californians and increase the amount of clean, affordable electricity for the region,” Victoria Rome, California government affairs director at the Natural Resources Defense Council, said. “SB 540 takes the next important step toward a more resilient and reliable clean energy future for all westerners.”

Leah Rubin Shen, managing director for the West at Advanced Energy United, said in a separate statement that the bill “lays out a forward-thinking strategy for regional energy collaboration that will help contain costs for California ratepayers while keeping the lights on. The Pathways Launch Committee has worked hard to ensure that all stakeholders have a seat at the table, state interests are preserved, and the reliability and cost-saving benefits of sharing resources across the West can be fully leveraged.”

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FERC Denies LS Power’s Bid for SWIP-N Incentives

FERC on Feb. 20 denied without prejudice LS Power’s two petitions to recover costs in case it must abandon development of a 285-mile transmission line designed to deliver Idaho wind power to California, saying the developer failed to adequately show the project’s benefits. 

The commission’s order covers the Southwest Intertie Project-North (SWIP-North), a 285-mile, 500-kV line being developed by LS Power subsidiary Great Basin Transmission at an estimated cost of $1 billion. 

In July, Great Basin petitioned FERC for authorization to recover 100% of the costs if the project is abandoned due to events beyond its control. The developer also asked for an order allowing it to create a regulatory asset to defer recovery of pre-commercial costs “in which it will book costs for the project, incurred to date and going forward, that cannot be capitalized and would otherwise be expensed,” according to the FERC order. 

However, the commission denied the request for declaratory order, finding Great Basin failed to meet the necessary criteria under FERC Order 679, which requires transmission incentive applicants to demonstrate that a project will ensure reliability or reduce costs associated with transmission congestion. 

“We find that, based on the record in this proceeding, Great Basin has not demonstrated that the project qualifies for the rebuttable presumption at this time because the project cannot be said to have ‘result[ed] from a fair and open regional planning process that considers and evaluates projects for reliability and/or congestion,”’ the order stated. 

FERC approved a development agreement for the line between CAISO and LS Power on Jan. 21. The project, which will be jointly funded by CAISO and Idaho Power, will span northern Nevada and southern Idaho and link up with NV Energy’s One Nevada (ON) line to the south, providing 2,070 MW of transfer capacity southbound and 1,920 MW northbound. (See FERC Approves CAISO’s SWIP-North Development Agreement.) 

Great Basin argued in its petition that it qualifies for the incentives under Order 679 because CAISO properly evaluated the benefits of the project in the ISO’s 2022/23 transmission planning process and the subsequent 2022/23 transmission plan. 

FERC disagreed, saying that although CAISO discussed “potential benefits” of SWIP-North, the ISO did not “make any definitive findings and instead only recommended continuing its initial assessments,” according to the order. 

“[T]here is insufficient basis in the record to demonstrate that CAISO fully considered and evaluated Great Basin’s Project for reliability and/or congestion relief through a fair and open regional transmission planning process leading to any of those conditional approvals,” FERC stated. 

The commission denied the request without prejudice, giving Great Basin another chance to demonstrate the project fulfills FERC’s requirements for transmission incentives. 

CAISO has agreed to fund about 77% of the project, equal to Great Basin’s ownership share, in exchange for operational control of the company’s entitlements on the line, which will equate to 1,117.5 MW of southbound capacity and 1,072.5 MW of northbound capacity, with the balance in both directions being allocated to NV Energy. (See CAISO Board Approves Moving Forward with SWIP-N Tx Line.) 

In addition to facilitating transfers into California, the line offers Idaho wind power resources access to wholesale electricity markets in the Desert Southwest through the Desert Link line connected to the southern end of the ON line. 

CAISO’s Board of Governors approved the development agreement during an October 2024 meeting despite opposition from some Idaho residents concerned about the path of the line. 

In its filing with FERC, CAISO said it needed to pursue SWIP-North to support the California Public Utilities Commission’s resource planning portfolio calling for California load-serving entities to procure 1,000 MW of wind generation from Idaho. The ISO noted the proposed line is the only active project that would help fulfill that objective, making it the most timely and cost-effective option. The project is expected to commence operation in 2028. 

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2 Top BPA Execs to Depart Following Trump Resignation Offer

Two top Bonneville Power Administration executives — including COO Joel Cook — are among the approximately 200 agency staff who accepted the Trump administration’s “deferred resignation” offer made to the entire federal workforce last month, BPA confirmed to RTO Insider Feb. 20.

The resignations of Cook and Senior Vice President of Transmission Richard Shaheen are the latest in a series of unsettling developments at the federal power agency and — now — its sister agency in Northwest hydroelectric dam operations, the U.S. Army Corps of Engineers (USACE).

BPA is responsible for operating about 75% of the transmission in the Northwest and marketing output from the region’s extensive network of federally owned hydro projects, most of which are managed and maintained by USACE.

During a quarterly business review call Feb. 13, BPA Administrator John Hairston said about 200 agency employees — or 6% of the workforce — had accepted the administration’s buyout offer, while 90 job offers had been rescinded following a federal hiring freeze announced Jan. 20. (See BPA Committed to Trump’s Energy Goals, Hairston Says.)

Scott Simms, executive director of the Public Power Council, told RTO Insider that he estimates BPA faces a loss of about 400 staff, which includes resignations and the firing of “probationary” employees. (Under federal hiring rules, “probationary” status applies to both recent hires and those who have transferred into new positions within the past year, including those receiving a promotion.)

But Simms also pointed to a parallel development at USACE, which some industry stakeholders thought might be protected from Trump’s cutbacks because of its association with the military. He said “multiple informed sources” have told him the agency has about 2,000 probationary employees nationwide, including 500 to 600 workers in the Northwest who hold jobs that require extensive technical training — such as dam operator.

“We’re still gathering data,” Simms said.

Impact Uncertain

BPA could not confirm a timeline for the departure of the two executives or of other staffers who accepted the resignation offer. The departures come just weeks before the agency is expected to release a draft decision on whether to join SPP’s Markets+ or CAISO’s Extended Day-Ahead Market.

Cook was appointed COO in April 2021 after having served as BPA’s senior vice president of power services since 2017. Cook previously held executive and management roles at Talen Energy, PPL EnergyPlus and Montana Power, according to his LinkedIn profile.

“As the head of power services, Joel has been on the front lines of our cost-control efforts,” Hairston said in a statement announcing Cook’s appointment in 2021. “His leadership and experience will serve the agency and our utility customers well as we explore new energy markets and look for opportunities to maximize the value of the federal power and transmission systems.”

Shaheen has served in his current role since 2014, after joining BPA in 2013 as vice president of engineering and technical services. According to his LinkedIn profile, he previously worked in various positions at Florida Power and Light for 25 years.

Shaheen has overseen BPA’s increasingly overburdened transmission planning processes, with the agency now confronting more than 65 GW in transmission service requests, up from 5.9 GW in 2021. He recently told stakeholders the agency had to pause certain planning processes because they had been “crippled” by the volume of interconnection requests. (See BPA Halts Some Tx Planning Processes Amid Surge of Service Requests.)

Shaheen also has managed BPA’s Evolving Grid Project, which the agency launched in April 2023 to address Oregon and Washington clean energy targets, renewable resource additions and the increased electrification of transportation, industry and buildings — as well as the growing need to harden the grid in the face of extreme weather events. (See Stakeholders Seek More Details on BPA’s ‘Evolving Grid’ Projects.)

In a letter dated Feb. 14, Oregon’s Democratic U.S. Sens. Jeff Merkley and Ron Wyden warned President Donald Trump that moves by his unofficial Department of Government Efficiency, led by billionaire Elon Musk, could result in the “imminent departure” of 20% of BPA’s workforce. The senators said the development poses “a direct and immediate threat to the reliability of the electrical grid that serves millions of American families and businesses” in the Northwest. (See Ore. Senators Ask Trump to Justify ‘Reckless’ Job Cuts at BPA.)

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FERC Launches Rulemaking on Data Center Co-location in PJM

FERC voted unanimously at its open meeting Feb. 20 to launch a review of data center co-location issues in PJM that will look into whether the RTO’s tariff needs to be revised to ensure grid reliability and fair costs to customers (EL25-49, AD24-11). 

The commission’s order focuses on PJM because it has seen a larger number of proceedings on the issue, as it is home to the largest data center market in the world and a large number of nuclear power plants interested in such contracts. 

“Co-location arrangements are a fairly new phenomenon that entail huge ramifications for grid reliability and consumer costs,” FERC Chair Mark Christie said in a statement. “Given these ramifications, the commission truly needs to ‘get it right’ when it comes to evaluating co-location issues.” 

The order comes after FERC in November rejected a proposed expansion of a co-location deal between an Amazon Web Services data center and Talen Energy’s Susquehanna nuclear plant in Pennsylvania. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.) 

It had received several, dueling sets of filings from both sides of the argument, and it held a technical conference on the subject earlier that month with witnesses from other markets. (See FERC Dives into Data Center Co-location Debate at Technical Conference.) 

FERC gave PJM and its transmission owners just 30 days to determine whether the RTO’s tariff needs updates to accommodate co-location arrangements. The commission found the tariff may be unjust or unreasonable because it does not have such rules. 

The commission is taking comments on the broader issues, and it will incorporate the record from the technical conference and related complaints. Parties have 30 days to file comments and another 30 to file replies. 

Without a common understanding of entities’ responsibilities, FERC is concerned that the arrangements could be developed in a way that is not fair for other customers. 

“We are especially concerned that the absence of tariff provisions creates the potential that participants in a co-location arrangement may not be required to pay for wholesale services that they receive,” FERC said. 

The issues with co-location fall under both FERC and state jurisdiction, with the commission having to ensure that rates for the wholesale sale of transmission of electricity, as well as practices directly affecting such sales, are just and reasonable and not unduly discriminatory or preferential. States have the oversight of retail sales not in interstate commerce, as well as facilities used for the generation and distribution of electricity. 

“The boundaries between federal and state jurisdiction are not hermetically sealed,” FERC said. “The application of these principles to the issue of co-location will often depend heavily on the specific facts and circumstances presented in particular situations.” 

With co-location, some basic principles on that split will apply across all the contracts. States will keep exclusive jurisdiction over retail sales, which means they decide which entities are legally permitted to provide electricity to retail customers and how the costs of providing wholesale power are recovered from retail customers. 

FERC has exclusive authority over the rates, terms and conditions for the sales from generating resources used to serve co-located loads, as well as practices directly affecting such sales. FERC also has jurisdiction over any transmission service used to serve co-location arrangements. 

The commission seeks comments on jurisdictional issues, including when large loads are interconnected to the transmission system in interstate commerce and what evidence FERC should use to determine that. 

Another issue FERC wants commenters to address is how such co-location arrangements have raised concerns around reliability and resource adequacy. NERC testified that 1,550 MW of voltage-sensitive load (data centers) disconnected from the system in a recent fault. 

If the co-location arrangements proliferate, it could have major impacts on PJM’s grid, which was often designed around nuclear plants, as the RTO’s Independent Market Monitor testified. Taking the capacity out of the markets could also cause prices to spike for other customers, as the IMM and the Illinois Attorney General’s Office testified. 

“That being said, we recognize, as does PJM, that these concerns are not necessarily unique to co-location arrangements and that significant load growth more generally may raise many of the same concerns,” FERC said. 

Exelon Co-location Tariff Rejected

In a related order, FERC rejected a series of filings made by Exelon’s utilities, all PJM members, that tried to set up rules for any co-locations in its territory (ER24-2888, et al.). Exelon in 2022 spun off Constellation Energy, which now owns the largest nuclear fleet in the country, but most of that is connected to transmission lines the original company owns. 

FERC found that the tariff revisions fall outside any individual utility’s tariff because they impermissibly alter the definition of load in PJM’s tariff. 

The order drew a concurrence from Commissioner Willie Phillips, who as chair voted to approve the Susquehanna proposal. The majority in that order had not wanted to set policy by precedent, but Phillips felt that approval would not have limited FERC’s flexibility going forward. 

This time, while he sided with the majority to reject Exelon’s filings, he noted that they raise real issues, including ensuring that co-located loads pay their fair share of costs, but they will be examined in the rulemaking proceeding, he noted. 

A bipartisan consensus has emerged that data centers and the artificial intelligence applications they enable are national interest resources with profound implications for both national security and economic growth, Phillips said. 

“I believe that this commission, in cooperation with our federal, state and local partners, should take all reasonable steps within our authority to support their development,” he added. “I view today’s orders as a down payment on this important national investment.” 

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Strong Southeast Economy Bolstered Southern Co. Growth in 2024

Speaking during Southern Co.’s quarterly earnings call Feb. 20, CEO Chris Womack called 2024 “an outstanding year … both operationally and financially” that left the company “incredibly well positioned” to maintain reliable service for its customers.

The company reported net income of $534 million ($0.49/share) in the fourth quarter of 2024 and full-year net income of $4.4 billion ($4.02/share). This represents a drop from the $855 million reported in the final quarter of 2023, but a significant rise in terms of full-year net income from 2023, when the company reported $4 billion.

Operating revenue for the fourth quarter came to $6.3 billion, up from $6 billion for the same period the year before. For the full year, operating revenue grew from $25.3 billion in 2023 to $26.7 billion for 2024.

Southern’s full-year earnings were “at the very top of our EPS guidance range,” Womack said, citing the target of $3.95 to $4.05 set in last year’s fourth-quarter earnings report. (See Southern Looks Beyond Vogtle After Challenging 2023.)

The primary drivers of the year-over-year growth came from the performance of the company’s electric utilities, with Southern noting that retail electricity sales grew 1% — although this figure was adjusted to account for the impact of Hurricane Helene in September 2024.

The company added 57,000 residential customers in 2024, the highest annual addition on record and more than a quarter of the 200,000 added in the region since 2020. Despite the growth in customers, residential electricity sales fell over the 12-month period by 0.5%; the difference was made up, however, by growth on the commercial and industrial side, with sales in each category rising by 2.2% and 0.7% respectively.

The commercial sales growth was supported by continuing rising demand by data centers and other large loads, with data center electric usage up 17% over the prior year. This represents a continued trend: Southern’s leaders reported strong growth among data center customers in the first quarter of 2024. (See Southern Credits Strong Southeast Economy for Earnings Growth.)

“Our objective is to serve as much of this growing electric load as we can sustainably serve,” Womack said. “The vertically integrated, state-regulated service territories that we are privileged to serve are proving well suited to attracting these large-load customers, and thanks to integrated resource plans and the other orderly processes inherent in our regulated frameworks, our market is also perhaps proven to be better suited than the unregulated markets at effectively deploying new resources to serve them.”

CFO Dan Tucker said Southern expected “strong fundamentals … to support our long-term growth,” setting adjusted EPS guidance for 2025 of between $4.20 and $4.30. At the same time, he acknowledged that the likelihood of higher interest rates could “be a partially offsetting factor.”

Tucker and Womack also highlighted the company’s plans to invest $63 billion in its businesses over the next four years; $50.3 billion of this figure is slated for the company’s regulated electric utilities, with $9.2 billion aimed at the regulated gas utilities and $3.3 billion for interstate gas pipelines, solar construction and maintenance on existing assets.

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Con Edison Planning Significant Infrastructure Investment

Consolidated Edison claimed solid progress and reported solid results as it released its 2024 financials Feb. 20. It also said it’s gearing up for $38 billion in capital investments through 2029. 

Clean energy progress was noted for 2024, with more than 352,000 customers assisted via energy-efficiency programs; 27,237 customers enrolled in the residential management EV charging program; and 14,868 heat pump installations supported. 

Reliability in a system that largely is underground was outstanding, with the average number of service interruptions per customer in 2024 almost 90% lower than the state and national averages. 

And Con Edison said it maintained a lower-than-average cost for its electric customers as compared with its peer average, both in total cost and percentage of median household income. 

Con Edison serves New York City and adjoining Westchester County. Its subsidiary Orange & Rockland Utilities serves parts of two nearby counties in New York and a small area in northern New Jersey. 

For 2024, Con Edison reported GAAP net income of $1.82 billion, or $5.26 per share. This compares with $2.52 billion and $7.25 in 2023. 

But 2023 earnings were inflated by the $6.8 billion sale of Con Edison Clean Energy Businesses. 

Adjusted (non-GAAP) earnings were $1.87 billion or $5.40 per share in 2024, compared with $1.76 billion and $5.07 in 2023. 

The company expects adjusted earnings per share of $5.50 to $5.70 per share in 2025. 

Con Edison declared itself a “Dividend Aristocrat and King” in its earnings presentation, noting that 2024 was its 51st consecutive year of dividend increases, with a compound annual growth rate of 5.59% thanks to its focus on long-term shareholder value. 

Statements and numbers such as these seem likely to increase friction between the utility and the public officials and advocates representing ratepayers. 

Con Edison on Jan. 31 proposed a rate case to the New York Public Service Commission that would entail average bill increases of 11.4% for electric customers and 13.3% for gas customers. 

Gov. Kathy Hochul (D) on Feb. 11 called for the PSC to reject the proposed rate hikes and directed it to perform an audit of management compensation at Con Edison and other utilities statewide. 

In another PSC filing, Con Edison reported that it ended 2024 with 496,007 residential customers in arrears more than 60 days for a total of $948.4 million, plus $539.1 million for 68,513 non-residential customers. 

The 2024 presentation indicates that 466,000 customers of Con Edison and its subsidiary Orange & Rockland — about 14% of the total customer base — receive public assistance and about 14% of Con Edison’s customers are enrolled in the Energy Affordability Program. 

CEO Tim Cawley said in a news release: 

“We are optimistic about growth and are well positioned to continue to meet demand to power the electrification of buildings and transportation throughout our service territory with increased capital investments in grid infrastructure. This was underpinned by big wins last year, such as breaking ground and progressing construction of key substations and advancing a pair of new transmission lines under our Reliable Clean City program. We anticipate demand for electrification to grow steadily in 2025, driven by an increase in new construction downstate combined with policymaker’s requirements for clean heat in new commercial and residential buildings.” 

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FERC Approves IBR, Extreme Weather Reliability Standards

FERC on Feb. 20 approved three proposed reliability standards addressing multiple aspects of inverter-based resource performance (RD25-1, et al.), along with another standard relating to entities’ planning for extreme hot or cold weather events (RD25-4).

NERC submitted the three IBR standards PRC-028-1 (Disturbance monitoring and reporting requirements for IBRs), PRC-002-5 (Disturbance monitoring and reporting requirements) and PRC-030-1 (Unexpected IBR event mitigation) in November. (See NERC Submits IBR Standards to FERC.) The ERO also submitted a proposed definition of IBRs, along with two other IBR-related standards, which were not included in FERC’s order; the commission is seeking comment from industry stakeholders on those standards.

PRC-028-1 applies to all generator owners that own NERC-registered IBRs, along with owners of IBRs that will be required to register under the registration criteria proposed by the ERO last June. (See FERC Accepts NERC ROP Changes, Drops Assessment Proposal.) The standard will require entities to install disturbance monitoring equipment on their IBRs in order to collect sequence-of-event recording, fault recording and dynamic disturbance recording data.

This information will be used to evaluate IBR ride-through performance during system disturbances and provide data for IBR model validation, NERC said in its proposal. GOs also will be required to fix any failures in disturbance monitoring capabilities.

PRC-002-5 updates PRC-002-4 to clarify its applicability to non-IBR grid elements, while also adding data collection and sharing requirements similar to those in PRC-028-1.

PRC-030-1 requires entities to develop a process for identifying “complete facility loss of output or certain changes of real power output” and to implement corrective plans to address performance issues when necessary.

The implementation plan for PRC-030-1 states that the standard will become effective on the first day of the first calendar quarter that is 12 months after either its approval or that of PRC-029-1 (Frequency and voltage ride-through requirements for IBRs), whichever is later. PRC-029-1 is one of the standards awaiting industry comment.

For PRC-002-5 and PRC-028-1, NERC requested the standards become effective on the first day of the first calendar quarter following their approval.

Standard Mandates Extreme Weather Planning

The final standard approved at FERC’s open meeting was TPL-008-1 (Transmission system planning performance requirements for extreme temperature event), which NERC submitted Dec. 17, 2024, following approval by the ERO’s trustees at their December meeting. (See “Standards Approved for FERC Submission,” NERC Board of Trustees Briefs: Dec. 10, 2024.)

NERC developed the standard in response to FERC’s Order 896, which directed the ERO to develop a standard to require entities to plan for extreme hot and cold weather.

TPL-008-1 will mandate that “planning entities in defined zones” work with each other to develop extreme temperature assessments at least once every five years. When such assessments identify instances where performance requirements would not be met during periods of extreme heat or cold, entities would need to develop and share corrective plans to address the problem.

Compliance dates for the standard will be phased over five years, a plan that NERC said would balance “the urgency in the need to implement the proposed [standard] against the reasonableness of the time allowed for those who must comply to develop the necessary processes and capabilities to perform these new wide-area extreme temperature studies.”

FERC approved the standards at its first monthly open meeting under Chair Mark Christie. Commissioner Judy Chang said she was “very pleased” with the cold weather standard, calling it “an incremental step, but … a step in the right direction.” Commissioner David Rosner agreed while pointing out that further work is needed to address the growing issue of extreme weather.

“While we’ve had really good progress so far on the cold weather front, the job is not done,” Rosner said. “Both FERC and NERC have repeatedly acknowledged the risk that extreme weather events pose to grid reliability, and NERC, at the end of last year, [released] an Interregional Transfer Capability Study that found that the [grid] is vulnerable to extreme weather. … I look forward to comments on that study and working with my colleagues here to make sure that we fulfill our duty … which is to ensure a reliable grid for American consumers.”

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New England Generators Remain in Limbo on Interconnection Reform

More than six months after the proposed August 2024 effective date for ISO-NE’s compliance with FERC Order 2023, generators seeking to interconnect in the region remain in limbo, and some stakeholders are concerned further delays could have detrimental effects on upcoming capacity auctions.

While FERC’s delayed response to the proposal already has affected certain aspects of ISO-NE’s compliance timeline, some stakeholders specifically pointed to an “inflection point” at the end of March 2025, and have expressed concern about increased complications if the delay extends beyond this date — especially if the order requires another substantial compliance filing.

FERC Orders 2023 and 2023-A require grid operators to adopt procedures for studying interconnection requests in coordinated cluster studies, instead of ISO-NE’s current process of studying projects sequentially. ISO-NE filed its compliance with the orders in May 2024 with unanimous support from the NEPOOL Participants Committee, after an extensive process of stakeholder feedback and amendments (ER24-2007, ER24-2009).

“Throughout this process and right up to the final vote, there was extremely robust stakeholder engagement in the compliance proceeding,” wrote a coalition of clean energy advocacy groups in comments to FERC supporting the filing. “ISO-NE’s Order No. 2023 reforms will mark an important first step in improving existing processes.”

However, FERC’s delay has compromised ISO-NE’s proposed timelines for the transitional cluster study and transitional Capacity Network Resource (CNR) group study (see New England Clean Energy Developers Struggle with Order 2023 Uncertainty.)

The cluster study is open to projects with valid interconnection requests, while the CNR study would include projects that have completed system impact studies but need capacity interconnection rights or capacity network resource capability (CNRC).

For the subset of projects that just need CNRC, the delayed response is complicated by ISO-NE’s multiyear delay of its upcoming capacity auction, which is intended to facilitate a series of major reforms to the format and timing of the RTO’s capacity auctions.

Under existing rules, resources achieve CNRC by receiving a capacity supply obligation in the forward capacity auction (FCA), or in a reconfiguration auction for a previously held FCA. However, under ISO-NE’s Order 2023 compliance proposal, resources will receive CNRC through the cluster study process instead of the FCA qualification process.

The transitional CNR group study, which would begin before the transitional cluster study and take about six months, would enable eligible projects to receive CNRC without having to go through the full cluster study, which is proposed to last for about a year.

While the delayed response has prevented ISO-NE from aligning the CNR group study with the 2024 reconfiguration auction (RA) qualification process, ISO-NE has expressed interest in aligning the CNR study with the 2025 RA qualification, which is set to begin in April.

This would mean that “the entire transition schedule in the compliance proposal would need to shift by roughly one year,” ISO-NE noted in December.

In a FERC filing submitted Feb. 5, Flatiron Energy Development urged the commission to rule on ISO-NE’s compliance proposal “in no event later than March 2025,” arguing that a ruling after this date “greatly complicates the path to aligning the transitional CNR group study with the 2025 interim reconfiguration auction qualification process.”

Flatiron, which develops energy storage resources, expressed concern that delaying the CNR group study past the qualification for the 2025 RA could jeopardize the ability of participating resources to come online in time for the 2028/29 capacity commitment period (CCP 19). Delays to the transitional cluster study would mean an even tighter window for projects that are waiting on the results of this study to reach financial close and begin construction.

The company wrote that its storage projects in ISO-NE take about 18-30 months to come online after receiving final interconnection approval. Under this timeline, starting the transitional CNR study in April would enable resources to come online between 2027 and early 2028, just in time for CCP 19, which starts in June 2028.

“Each additional month of delay adds risk for projects planning to participate in ISO-NE’s proposed transition processes and decreases the likelihood that they will be able to offer capacity into [CCP 19],” Flatiron wrote. “Q1 of 2025 is an inflection point, where if a decision is not issued by then, the risk that many projects will not be able to complete the necessary processes in time to deliver their capacity through this auction substantially increases.”

The company estimated that up to 3 GW of capacity is eligible to participate in the CNR group study. It stressed that preventing a substantial amount of capacity in the interconnection queue from participating in CCP 19 could lead to more expensive capacity prices, reliability risks, and higher emissions.

Alex Lawton of Advanced Energy United agreed the region appears to be “approaching a juncture” for its Order 2023 timeline.

“It seems pretty clear now that the [transitional cluster study] and CNR group study are linked to the interim RA [qualification] process, which begins with a SOI [show of interest] window mid-April, so I think it’s a legitimate concern about whether the one-year implementation delay approach will still work if FERC misses the SOI,” Lawton noted.

ISO-NE spokesperson Randall Burlingame said the RTO’s ability to align the CNR group study with RA qualification “would be difficult if we don’t receive an order this quarter,” adding that the substance of the order, and the extent to which additional compliance word will be needed, also will affect the RTO’s ability to align its compliance with external processes.

Delays to the interconnection process in New England would almost entirely affect renewable and storage resources; of the more than 39 GW of potential new generation tracked by ISO-NE, wind and battery storage each make up about 43% and solar accounts for about 13%. Natural gas, oil, and fuel cell generation account for less than 1%.

The states also have expressed concern about an extended delay to Order 2023 implementation. In a letter to FERC in late November, the New England States Committee on Electricity (NESCOE) wrote that the delay “has resulted in ambiguity for generators as to when and by which process their projects will be interconnected and has left ISO-NE unsure as to how best to posture ISO-NE staffing and other internal resources.”

NESCOE noted that the uncertainty also affects distribution-level affected system operator studies, which will need to coordinate with ISO-NE cluster studies.

“This uncertainty undermines one of the principal tenets of Order 2023 around which there is general agreement — the efficient and timely interconnection of new resources,” NESCOE added.

In a filing submitted Feb. 19, the New Hampshire Office of the Consumer Advocate wrote that it agrees with Flatiron’s concern that a delay beyond the first quarter of 2025 could lead to a “very significant difference” in capacity prices for upcoming auctions.

“Should cost-competitive capacity not be able to efficiently interconnect, there will likely be both cost and reliability impacts to the region, including to the residential utility customers of New Hampshire,” the office wrote.

In the meantime, ISO-NE continues to process interconnection requests under the existing sequential rules, which may help some projects in the late stages of their interconnection studies avoid needing to participate in the transitional cluster study.

The RTO’s interconnection queue remains closed to new interconnection requests and would not reopen to new requests until fall 2026 if the entire process is simply pushed back by one year.

“Depending on the content of an order on the Compliance Proposal, the ISO is open to evaluating whether it is possible to shift the Order No. 2023 established eligibility date to allow for a limited reopening of the ISO Interconnection Queue,” ISO-NE said in December.

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Batteries, Solar Help ERCOT Meet Record Winter Peak

ERCOT set a new winter demand peak Feb. 20 with its first-ever mark above 80 GW, a number once reserved for summer months. 

Demand peaked at 80.63 GW at 7:25 a.m. Feb. 20 as a late-winter Arctic blast sent temperatures plunging below freezing in much of the state and as far south as Houston. ERCOT had projected demand to reach 83.7 GW but overshot the mark. The grid operator had a healthy margin of nearly 7 GW of operating reserves during the peak. 

The new mark broke an instantaneous peak of 79 set at 11:25 a.m. Feb. 19. Demand averaged 78.72 GW during the hour interval ending at noon. 

The peaks are not official until ERCOT completes the settlement process for the operating days. The current winter demand mark is 78.35 GW, set in January 2024. The grid operator set an all-time peak demand record of 85.46 GW in August 2023. 

Renewable energy, particularly solar and batteries, has played a key role in meeting that demand. Renewables provided 35% of the need during the Feb. 19 peak, and energy storage set a record (4,587 MW) during the Feb. 20 record. Solar resources produced 22.92 GW of energy Feb. 20, second only to the record 24.31 GW set Feb. 16. 

During a Feb. 18 press conference, ERCOT CEO Pablo Vegas said there was enough supply to meet demand. He pointed out that the ISO has added more than 13 GW of new supply since last winter. 

“That supply is going to continue to be helpful in these cold events. A lot of it is solar and batteries, both of which are going to help us when the sun comes up on a cold day,” Vegas said. “The batteries help us as a bridge in the morning. That’s what helps us keep the reliability high as we get through this event.” 

With the exception of five, 15-minute intervals that exceeded $1,000 in the Lower Colorado River Authority load zone, real-time prices have been relatively stable, briefly reaching a high of $457 Feb. 19-20. 

ERCOT declared a weather watch Feb. 17 for Feb. 19-21 because of the forecast extreme cold weather, higher demand and potential for lower reserves. It expected grid conditions to be normal. 

Temperatures in Houston, which is near the Gulf of Mexico, still have highs forecast in the 40s through Feb. 22, before the normal warmth returns. 

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Beacon Wind Withdraws Export Cable Request

Beacon Wind has paused its efforts to build an underwater transmission line into New York City. 

Its Feb. 19 filing with the New York state Public Service Commission (Case 22-T-0294) withdraws the application for a certificate of environmental compatibility and public need for the 320-kV HVDC line it proposed in May 2022. 

The line was to run 115 nautical miles through Long Island Sound to the Astoria Gateway for Renewable Energy, a point of interconnection (POI) at the northwest tip of Long Island where a gas-fired power plant once stood. 

In a Jan. 31 PSC filing, Beacon Wind LLC indicated it was considering alternative POIs as the project evolves, in part due to feedback it received during the NYISO interconnection process. 

In the same filing, it indicated a pause would be useful “given the uncertainty with respect to federal permitting for offshore wind.” 

Just 11 days earlier, President Donald Trump in an executive order halted awards of new offshore wind leases and cast uncertainty over existing leases and projects. 

Beacon Wind is being developed by oil supermajor bp, which has scaled back its investment in renewables in the past year. The U.S. public relations staff for bp told NetZero Insider via email:

“On Feb 19, Beacon Wind withdrew its New York Article VII application — the state’s transmission interconnection application — and NYISO offshore wind queue position. This decision was made to allow for more time in the evaluation of the project’s design and configuration. Since the project submitted its application and queue position, New York’s approach to offshore wind project interconnection has evolved in the direction of coordinated offshore transmission. We support the Public Policy Transmission Need project approach sponsored by NYISO which is designed to help reduce the cost of electricity delivery from offshore wind projects to the New York grid.”

Beacon Wind has had some challenges. 

Bp was pursuing Empire Wind and Beacon Wind as a joint venture with fellow oil and gas producer Equinor. The two also proposed the Astoria Gateway and a large port facility in Brooklyn. 

They won New York offtake contracts for Empire 1 and 2 and for Beacon 1, but not Beacon 2. 

Then the U.S. offshore wind industry stumbled, just as it was starting to build real momentum in the third year of the Biden administration, thanks to soaring costs, supply chain constraints and insufficient infrastructure. Most developers holding offtake contracts along the Northeast coast canceled them, including Equinor/bp. 

The two companies also dissolved their partnership, with Equinor taking full ownership of Empire and the port and bp taking Beacon and the Astoria Gateway. (See Offshore Wind Reset Complete in New York.) 

Equinor since has won a new state offtake contract for the 816-MW Empire Wind 1 and has begun construction of the port. The PSC on Feb. 13 gave final approval for construction of the portion of Empire Wind 1’s transmission line in state waters (Case 21-T-0366). 

Empire Wind 2, on the other hand, is on indefinite hold. On Sept. 12, after more than two years in the works, Equinor withdrew its request for the Certificate of Environmental Compatibility and Public Need that would allow it to construct an export cable. (See Equinor Yanks Request for Empire Wind 2 Export Cable.) 

In June 2024, after reports that bp was refocusing toward fossil fuels and away from offshore wind, a U.S.-based spokesperson told NetZero Insider the developer was taking the time to fully evaluate the Beacon Wind project and had not come to a decision. (See Bp Says It is Still Evaluating Beacon Wind.) 

That was four months before Trump was elected president and seven months before he followed through on a campaign pledge and moved to thwart offshore wind development in U.S. waters. 

In December 2024, bp and Japan’s largest power generation firm, JERA, announced they would form JERA Nex bp, an offshore wind joint venture. They said they expected to finalize the deal before October and would pursue “highly disciplined, capital efficient growth.” 

The assets listed by JERA and bp total 13 GW of potential generating capacity. Beacon — at 2,580 MW, the largest facility on the list, and the only one in U.S. waters — was listed not as a development project but as a secured lease.  

The new partners said they expected to concentrate on existing projects in Europe, Australia and Japan and to continue to pursue longer-term opportunities.