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March 10, 2025

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Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance

The language for the proposed California bill to implement “Step 2” of the West-Wide Governance Pathways Initiative became public late Feb. 20, revealing the conditions under which CAISO and Golden State utilities can participate in energy markets governed by an independent regional organization (RO) if lawmakers vote to approve the legislation.

Introduced by Sens. Josh Becker and Henry Stern, SB 540 — or the Pathways bill — seeks to amend sections of the California Public Utilities Code to enable California entities to join an energy marketplace governed by an independent RO. Ultimately, the RO would take over governance of CAISO’s Western energy markets to make CAISO markets more attractive for entities outside of California and allow stakeholders to tap into a broader market of electricity resources.

Before CAISO can hand over the reins, the bill requires the RO to fulfill 12 requirements. The bill’s text focuses on ensuring the RO’s independence and maintaining the authority of each state with a power entity in the market “to set its own procurement, environmental, reliability and other public interest policies.”

For example, the RO must engage with states, local power authorities and federal power marketing administrations before filing tariff changes with FERC. The RO’s governing board also must seek input from a body of state regulators “to receive the views of state regulators,” according to the bill.

The legislation also requires the RO to ensure public interest protections, including making funding available for a consumer advocate organization and maintaining an office of public participation.

The bill is the result of the Pathways Initiative, which aims to expand CAISO’s Western Energy Imbalance Market (WEIM) and the soon-to-be-implemented Extended Day-Ahead Market (EDAM) by shifting governance of the markets from the ISO to the proposed independent RO.

Previous efforts to expand markets in the West have failed, partly due to non-Californian entities expressing concerns about a market governed by CAISO, whose Board of Governors is appointed by the California governor. The Pathways bill strives to solve this issue.

Lincoln Davies, professor of law and executive director of energy, resource and environment programs at the University of Utah S.J. Quinney College of Law, told RTO Insider the bill “marks a monumental moment for California and all of the West.”

“It is an important departure from prior efforts, each of which failed,” Davies said. “Rather than islanding California from other states, the bill advances core Western values that were absent in past efforts — collaboration among stakeholders, respect for each state’s right to self-govern, and imagination and innovation. This new market would look different from any other market in the U.S., and that’s exactly how it should be. The West is unique. Its markets should be, too.”

The Northwest Energy Coalition (NWEC) said a West-wide energy market is the most efficient way to meet energy needs, ensure affordability and tackle extreme weather events.

“That is why we have committed so many resources to the Pathways Initiative to help create an independent regional organization to run the combined Extended Day-Ahead and Western Energy Imbalance Market,” NWEC stated. “This bill would pave the way for shared governance across all Western states in this region-wide energy market. We hope this bill passes quickly so that all utilities in the West join the EDAM energy market.”

The effort comes as the region prepares for the launch of EDAM and some entities already have committed to the market. But SPP’s Markets+ also has gained significant traction by positioning itself as offering independent governance from the get-go.

A study by The Brattle Group suggests California ratepayers could save $790 million a year under an EDAM that includes nearly every Western balancing authority except for Western Area Power Administration entities already engaged with SPP markets, Public Service Co. of Colorado (PSCo) and the Imperial Irrigation District.

But California likely would see significantly lower benefits than the top end — $182 million — in what will be the most likely outcome in the West — the “Split Market” case, where Markets+ consists of Powerex, the Bonneville Power Administration and most Washington utilities, NorthWestern Energy, PSCo, Arizona’s utilities and El Paso Electric, according to the Brattle study.

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ERCOT Plans on Mobile Generators in San Antonio

ERCOT staff Feb. 20 said they plan to gain permission from their Board of Directors to use 15 mobile generators as an alternative to relying on two 1960s-era gas units to resolve reliability needs in the San Antonio area.

Nathan Bigbee, ERCOT’s chief regulatory counsel, told the Texas Public Utility Commission that the generators, which are capable of a combined 480 MW of capacity, are more “cost effective” than extending reliability-must-run contracts with Braunig Units 1 and 2, owned by San Antonio’s municipal utility, CPS Energy. The aging units together have a maximum summer rating of 392 MW.

“Our calculation suggests there’s a 15% greater cost-benefit [ratio for] the [mobile] units over the Braunig units based on the fact that they have a shorter start-up time, a slightly better shift factor, and shorter up and down times. We see those as being a net reliability benefit for the grid,” Bigbee told commissioners.

The generators in question, along with several smaller ones, were leased from LifeCycle Power in 2021 by Houston’s CenterPoint Energy for $800 million. However, the larger units have sat unused, despite outages after Hurricane Beryl that lasted more than a week.

The board is holding a special meeting Feb. 25 to consider the mobile generators’ use and a preliminary exit strategy. (See “Staff Still Looking at Braunig,” ERCOT Board of Directors Briefs: Feb. 3-4, 2025.)

Bigbee said CenterPoint has agreed to make the generators available for ERCOT’s use. The grid operator will not compensate CenterPoint but will cover LifeCycle’s costs to move the generators to San Antonio.

LifeCycle has estimated it will cost $26 million to move the generators, while CPS has projected costs of $27 million to connect them to substations. ERCOT says the cost estimates are subject to change.

The latest estimate from CPS to prepare Braunig Units 1 and 2 for continued operation is $54 million. It projects all-in costs, which include an incentive factor and fuel expenses, will run $60 million.

Bigbee said the generators are a “lower-risk solution” compared to extending RMRs for Units 1 and 2. The units would need to go through an inspection before continuing operations. That could reveal additional repairs that need to be made, he said.

“There’s a lot of cost upside risk there that we would have to deal with and potential outage delay risk that could further exacerbate the reliability issues, and so, we see the LifeCycle option as being a win-win in that respect,” Bigbee said.

The municipality told the grid operator in 2024 that it planned to retire the Braunig units in March 2025. However, ERCOT said the plant’s units were needed to address transmission constraints and congestion in the San Antonio area until several transmission projects can be completed. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)

ERCOT has extended an RMR contract through 2027 to CPS for Braunig Unit 3, which has a 412-MW summer rating.

The grid operator also is working with CPS, AEP Texas and South Texas Electric Cooperative on accelerating the transmission projects south of San Antonio intended to resolve the region’s congestion issues. A rebuild of a second 345-kV circuit is scheduled to be completed in May 2029, but Bigbee said preliminary discussions have indicated the work could be pushed up to January 2027.

“That could resolve some significant reliability issues in the future,” he said. “The earlier we can get those lines in service, the better we believe that the cost-benefit analysis will show that that’s easily a cost-beneficial move.”

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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; Army Corps of Engineers also Faces Massive Cutbacks

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 Thorny Issues Involving Data Center Co-location

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/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/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/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 policymakers’ 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 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, 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.