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February 23, 2025

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Mass. DPU Proposes Major Shift in Gas Line Extension Policies

The Massachusetts Department of Public Utilities has proposed requiring customers who request new gas service to cover the full cost of any needed line extensions, which effectively would end the gas utilities’ practice of spreading these costs across their rate base.

The proposal is the latest step in the department’s docket focused on aligning gas regulations with the state’s statutory decarbonization requirements (DPU 20-80).

Under the current rules, the utilities are not allowed to subsidize new gas connections through the existing rate base. However, a utility may charge the connection costs to the rate base if it expects to recover the costs from the additional revenues received from the new customer.

In late 2023, the DPU issued a major order setting the regulatory framework for the state’s transition away from natural gas, which announced the department’s plans to reform the “standards for investments to serve new customers.” (See Massachusetts Moves to Limit New Gas Infrastructure.)

The DPU directed the local distribution companies (LDCs) to review their tariffs, policies and practices regarding line extensions, specifically inquiring about “de facto free extension allowances” and “whether existing state policies are inconsistent with current practices by incentivizing new customers to join the gas distribution system.”

The utilities filed testimony in 2024 detailing their line extension procedures, providing some insight into their extension policies and the scope of the demand for new gas service.

Data from Eversource and National Grid’s testimonies indicate the companies continue to add thousands of gas hookups each year, although the annual number of new connections generally has decreased over the past 10 years.

The gas companies testified their expansion policies are consistent with state climate policy, while climate advocacy groups — along with the state Attorney General’s Office and Department of Energy Resources — argued the policies undermine state programs to reduce gas use.

In testimony submitted to the DPU, a representative of National Grid said the “addition of new customers must be viewed in conjunction with the elimination of leak prone pipe and other gas infrastructure work which may reduce GHG emissions to determine if the company is meeting its emission reduction targets.”

They added that the “the implications of connections policy for GHG targets must also consider interactions and dependencies across sectors and fuels.”

Pushing back on the utilities’ claims, the research firm Groundwork Data, with funding from the Conservation Law Foundation, Environmental Defense Fund and Sierra Club, made the case that utilities’ extension procedures “are inconsistent across LDCs, increasingly inconsistent with the principle that existing customers should not subsidize new customers, and inconsistent with state climate policy.”

“Since 2018, approximately 80% of new service-only connections have been provided at no cost,” Groundwork Data wrote. “The average cost of adding new customers was $9,000 in 2023, totaling over $160 million across the Massachusetts LDCs.”

‘Pretty Big Deal’

The DPU appeared to side with the environmental groups and government agencies in its draft policy, which directs the utilities to “require a customer seeking an extension for new gas service to pay for the entire cost of connecting to the distribution system,” unless the customer can qualify for an exception.

To qualify for an exception, the utility would need to show the extension would drive a “demonstrable reduction” in emissions, be consistent with the state’s climate limits, and that the customer has “no feasible alternatives” to natural gas.

Keeping with the current rules, the utilities also would have to ensure the cost of adding the connection does not exceed the added revenues they expect to receive from the new customer, “so that existing customers do not subsidize the cost of the extension of service,” the DPU wrote.

Ben Butterworth, of the Acadia Center, called the draft policy “a pretty big deal,” adding that it likely will result in “a significant reduction in terms of the growth of the system.”

“Obviously those three variables are open to interpretation by the commission, but my interpretation is the vast majority of projects would have an extremely hard time meeting those criteria,” Butterworth said.

National Grid and Eversource declined to comment on the draft policy. The DPU set a March 13 deadline for comments.

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BPA Committed to Trump’s Energy Goals, Hairston Says

Bonneville Power Administration CEO John Hairston said during the agency’s quarterly business review Feb. 13 that BPA is committed to President Donald Trump’s goal to “unleash American energy dominance,” while also revealing that approximately 200 BPA federal employees have accepted the president’s deferred resignation offer. 

About 6% of BPA’s federal workforce have opted into the Office of Personnel Management’s (OPM) deferred resignation program, and the agency has rescinded 90 job offers following a hiring freeze on federal employees imposed by Trump on Jan. 20, staff said during the quarterly business review.  

About 2.3 million federal employees received the buyout offer in a Jan. 28 message titled “Fork in the Road.” Employees who accepted the offer would receive a severance package of eight months’ pay and benefits through Sept. 30, the end of the federal fiscal year. Employees were directed to respond by Feb. 6. 

The offer is one of many actions, including a flurry of executive orders, that Trump has taken since regaining the presidency on Jan. 20, which have directly impacted BPA. Another example is the order on Unleashing American Energy. 

BPA Administrator Hairston acknowledged there is “a lot of interest in BPA implementation of President Trump’s executive orders, and how those orders are expected to impact our business.”  

“We see great opportunity in supporting and advancing the administration goals to unleash American energy dominance, and indeed, Bonneville will play a key role in our region as we continue to execute our mission by delivering safe, reliable transmission services,” Hairston said. 

BPA has taken other actions in light of recent executive orders, including shutting down a culture office under the agency’s Diversity, Equity and Inclusion program and requiring workers to return to the office full-time. BPA also is updating its strategic plan to align with the Trump administration’s direction, Hairston said. 

Veronica Wittig, acting chief financial officer at BPA, said the agency works closely with the Department of Energy to carry out Trump’s directives. BPA forecasts negative net revenues of $44 million in the first quarter of 2025, compared with BPA’s target of positive $70 million, Wittig said. 

“The Q1 forecast was developed based on information at the end of December 2024 and does not reflect the impact of executive order on BPA’s financial forecasts,” Wittig said. 

Additionally, Wittig noted, “there is significant uncertainty at this time of the year with respect to water conditions and market prices, so net revenues picture may change significantly, which may also impact some of our other financial [key performance indicators].” 

The call also touched on other BPA initiatives, including the agency’s work to offer new long-term power contracts under its provider-of-choice program. BPA hopes to have final contract templates by June with signed contracts by December, according to Hairston. 

Hairston noted the pause on several transmission planning processes spurred by 65 GW of transmission requests.

The agency also is on track to release its day-ahead market draft policy in March, followed by a final policy and record of decision in May, Hairston said, referring to BPA’s upcoming choice of whether to join SPP’s Markets+ or CAISO’s Extended Day-Ahead Market. 

Additionally, on Jan. 30, BPA broke ground on a new control center located in Vancouver, Wash., which will be fully integrated into BPA’s system by 2031, Hairston said.  

“It will begin a new era of grid visibility and control for BPA,” Hairston said. “The new facility has been intelligently designed to address evolving technology, continuity, safety and security needs. Its design will support the evolution of the bulk power grid over the next 50 years, while providing flexibility for growth and market opportunities.” 

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NERC Leaders Highlight Canada-US Collaboration

MIAMI — Addressing NERC’s Member Representatives Committee and Board of Trustees, CEO Jim Robb said “the recent kerfuffle” over trade tariffs between the U.S. and Canada should not affect the ERO’s ability to work on electric reliability issues on both sides of the border.

Robb acknowledged that President Donald Trump’s proposed tariffs on trade with Canada have created “turbulent waters” between the two countries since the board’s last meeting, as did outgoing Chair Ken DeFontes in his opening remarks. Trump announced a 10% tariff on energy imports from Canada on Feb. 1, only to pause its implementation for 30 days Feb. 3 after promises from Prime Minister Justin Trudeau regarding drug interdiction and immigration.

Derek Olmstead, CEO of Alberta’s Market Surveillance Administrator and representative of Canada’s Energy and Utility Regulators, observed that while the proposed tariffs could lead to difficulty with supply chains, that did not erase the fact that the countries “have common interests that are very much aligned.”

Robb agreed, calling NERC “a great model of international collaboration.”

NERC holds one of its four board meetings in Canada each year; the upcoming August meeting is planned for Calgary, Alberta.

Keenan Steps up to Board Chair

Several of NERC’s leadership positions changed hands at the board meeting. Most notably, DeFontes handed over leadership of the board to Suzanne Keenan, who was elected to succeed him in February 2024. (See NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024.)

Trustee George Hawkins has stepped up to take Keenan’s place as vice chair, a position he previously held until Keenan replaced him in that role last February.

DeFontes will remain with NERC as a trustee, having been reelected to another three-year term at the meeting of the MRC that preceded the board meeting.

Trustees Jane Allen and Colleen Sidford also will return for a new term; however, the seat left by departing Trustee Bob Clarke — who is not eligible for renomination because he already has served for 12 years — will remain vacant. Larry Irving, chair of NERC’s Nominating Committee, explained the group elected to defer the search for a new trustee to allow more time to find the best candidate to handle “the current speed of change” in the grid and the technology, security and policy landscape.

MRC Chair Jennifer Flandermeyer also handed off her position to Vice Chair John Haarlow, CEO of Snohomish County Public Utility District. Matt Fischesser of ACES Power will take over as vice chair.

The board passed resolutions honoring both DeFontes and Clarke for their service to the ERO, along with Stan Hoptroff, who is retiring after 10 years as NERC’s vice president of business technology. Hoptroff announced his retirement last year along with Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center; Robb told attendees that Cancel has agreed to defer his retirement until a suitable replacement is found.

Task Force to Examine Standards Process

Having twice exercised their authority to accelerate standards development in order to avoid a pressing deadline, trustees voted at the meeting to take the first steps toward updating NERC’s standards development process.

The board voted unanimously to create the Modernize Standard Processes and Procedures Task Force, originally suggested at the MRC’s November meeting. Greg Ford, CEO of Georgia System Operations Corp., will serve as chair and Todd Lucas of Southern Co. will serve as vice chair. Trustees Sue Kelly and Rob Manning will join as well, with ERO staff, NERC committee chairs, industry representatives and subject matter experts filling the remaining seats.

The task force will conduct a strategic review of the development process and submit recommendations in 12 months for “a modernized standard development process that … ensures that time [from] risk identification and prioritization to reliability standards development can be completed [in] a much more efficient and effective manner.”

NERC Chief Engineer Mark Lauby told trustees the effort is intended to make the standards process more responsive to the growing pace of change in the risk environment, which has made it increasingly difficult for NERC’s consensus-based approach to keep up with new threats to grid reliability.

This challenge was put on display twice since August, as the board was forced to invoke Section 321 of NERC’s Rules of Procedure when the normal process looked unlikely to result in a suitable standard to meet deadlines set by FERC. Trustees turned to Section 321 first in August to break an impasse over ride-through requirements for inverter-based resources, and again in January to authorize the Standards Committee to take over development of a cold-weather standard. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.)

Keenan urged Ford and Lucas to look at every aspect of the standards development process to find any opportunities for improvement but also reminded them that “the process needs to remain stakeholder-based, with reasonable notice, opportunity for public comment, due process [and] openness.”

Soo Jin Kim, NERC’s vice president of engineering and standards, also provided an update for the board on the status of Project 2024-03 (Revisions to EOP-012-2), the subject of the second use of Section 321. Kim told trustees the Standards Committee has posted the proposed cold weather standard, EOP-012-3 (Extreme cold weather preparedness and operations), for a public comment period that will end March 12.

When the comment period has concluded, the committee will submit the standard to the board along with a complete record of its development, including comments. A special board meeting to vote on the standard has been scheduled for March 25, Kim said.

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DTE Energy Ups 5-Year Plan to $30B

DTE Energy has announced it will expand its five-year capital expenditure plan to $30 billion, a $5 billion increase in investment. 

During a Feb. 13 year-end earnings call, CEO Jerry Norcia said the increase will help the utility improve reliability and transition to a cleaner fleet in accordance with Michigan’s 100% clean energy mandate by 2040. Norcia said the plan has the potential for incremental investment above $30 billion depending on “data center opportunities.” 

“This $5 billion increase is a significant increase to our capital plan and is driven by the need to build out renewables to meet the increased demand from the success of our My Green Power voluntary renewable program and to support Michigan’s clean energy legislation, as well as the need to continue to invest to improve reliability for our customers as we continue our efforts to update and modernize our electric grid,” Norcia said. 

Norcia told shareholders that DTE has “a solid, long-term development pipeline in place, providing clear line of sight on panels, land positions and permitting.” 

“We have panels secured through mid-2027, land positions that should take us into the 2030s and beyond, and permits secured for the majority of our projects through 2027,” COO Joi Harris added. 

Norcia said the updated plan includes an additional $3 billion in clean energy investment and $1 billion for improved distribution infrastructure to cut outage rates further. 

Harris said DTE was able to reduce outage durations by 70% over 2024. She said the utility over the next five years expects to further reduce power outages by 30% and halve outage time. 

In 2022 the Michigan Public Service Commission ordered an audit of DTE and Consumers Energy after ratepayer frustration with a “pattern of widespread, lengthy outages from increasingly severe storms.” 

Norcia said the company’s electric arm remains focused on potential demand growth from data centers in its service area. DTE recently signed a nonbinding preliminary agreement with an unnamed company, Norcia said, and if it comes to fruition, it could bring the company’s potential new data center load growth to 2.1 GW. DTE already has signed agreements for an artificial intelligence research facility at the University of Michigan and a 1.4-GW Switch data center complex using some of DTE’s land.

“We are also in discussions with multiple parties for additional opportunities beyond those that I just described,” Norcia said, adding that DTE is supportive of Michigan’s new law offering tax breaks to large data centers. 

Norcia said that while DTE is sitting on some excess capacity to serve new data center load, the company likely must build new capacity in the near term. He said plans for baseload generation to support the growth would come in the utility’s 2026 integrated resource plan. 

DTE earned $1.4 billion ($6.83/share) over 2024 despite the warmest winter in more than 60 years, according to the utility. Over 2023, the company brought in $1.2 billion ($5.73/share) in operating earnings. It released an earnings per share guidance range of $7.09 to $7.23 over 2025. 

Norcia said 2025 performance will be bolstered by the Michigan PSC granting a $217.4 million increase in electric rates in January. The new rates went into effect Feb. 6. The hike in rates was less than half of the $456.4 million that DTE first requested in early 2024. 

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CAISO EDAM Pioneers Share Implementation Details

With go-live dates for its first two participants looming in May and October of next year, implementation activities for CAISO’s Extended Day-Ahead Market are ramping up. 

Representatives of PacifiCorp, Portland General Electric and CAISO gave updates on EDAM preparations during a Feb. 12 joint meeting of the CAISO Board of Governors and the Western Energy Markets (WEM) Governing Body. 

For PacifiCorp, which has an EDAM go-live date of May 1, 2026, much of the recent focus has been on its Open Access Transmission Tariff filing with FERC. 

The company initially filed the tariff in November but decided to withdraw it and submit a new filing Jan. 16. 

The new OATT incorporates a different methodology for congestion revenue allocation — a subject that gave stakeholders “some serious concerns,” according to Robert Eckenrod, PacifiCorp assistant general counsel. 

For example, Western Power Trading Forum questioned the tariff’s measured-demand approach to allocation and planned to file a FERC protest in January, a representative said in December. (See CAISO Leaders Look Ahead to 2025 with Confidence.) 

PacifiCorp was able to work around some limits of the methodology from the initial filing, Eckenrod said, and the new methodology is “more granular and more advantageous.” 

Other than the changes to congestion revenue allocation methodology, the OATT filing is the same as the initial filing. It requested a Feb. 18 due date for comments and a May 16, 2025, decision date. 

PGE Activity

Portland General Electric, which has an EDAM go-live date of Oct. 1, 2026, is planning to file its OATT with FERC by the end of March, said Tiffany Emerson, PGE’s senior manager of strategy and planning. PGE is working with PacifiCorp to align their tariffs, she said. 

As a participant in CAISO’s Western Energy Imbalance Market (WEIM), PGE plans to enhance existing systems and frameworks rather than starting from scratch, Emerson said. Testing of system enhancements will begin in December and continue into 2026. 

Another focus for PGE is settlements.  

“The sheer volume of the transactions that we’re going to settle with … CAISO in the post-go-live EDAM world is just an order of magnitude greater than what we currently do as an EIM participant,” Emerson said. 

WEM Governing Body member Andrew Campbell said he was encouraged to hear that PGE was working with PacifiCorp on EDAM implementation. 

“That’s certainly key to success in this process,” Campbell said. “The entities as they join are helping the ones who are joining after them.” 

In addition to PacifiCorp and PGE, the Balancing Authority of Northern California signed an EDAM implementation agreement with CAISO in November; the Los Angeles Department of Water and Power formally committed to joining in December. (See BANC Signs Agreement to Join EDAM; LADWP Gets Board’s OK to Join CAISO’s EDAM.) 

BANC and LADWP are scheduled to go live with EDAM on May 1, 2027. 

CAISO has been conducting EDAM training with PacifiCorp and EDAM and also has publicly posted training material on the WEM website. Computer-based training for EDAM entities is planned for April, according to Heather Kelley, executive director of CAISO’s project management office. 

CAISO plans to begin integration testing with PacifiCorp this summer.  

“We will be revving up our systems, and they’re going to be connecting to them, and we’ll start to get the market running,” Kelley said. 

Customer Outreach

Kerstin Rock, managing director of Western market policy and analytics at PacifiCorp, noted that some deadlines for EDAM participation are now merely weeks away. For example, the company plans to complete connectivity testing by June 1. 

PacifiCorp also is launching an engagement process for its transmission customers, with a series of workshops starting Feb. 27. Videos of the workshops will be posted on the company’s Open Access Same-time Information System (OASIS). 

CAISO Board of Governors Chair Severin Borenstein thanked PacifiCorp for doing the work that will “smooth the pathway” for other EDAM participants. 

“It’s all becoming real,” Borenstein said. 

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Duke Spending Big to Meet Increasing Load Growth in the Late 2020s

Duke Energy’s leadership changed the guard during its first-quarter earnings call Feb. 13 as retiring CEO Lynn Good and her replacement, Harry Sideris, split the presentation. 

Good announced her retirement effective April 1 early in 2025. (See Duke Names Harry Sideris as Company’s Next CEO.) 

Last year was defined largely by Hurricanes Helene and Milton, which hit Duke’s territory. Good thanked the communities it serves for their support and understanding as the utility restored service after the storms. Duke plans to spend $83 billion in the next five years to meet the growing needs of its utilities. 

“This capital represents infrastructure spending driven by growing jurisdictions and underpinned by robust regulatory processes such as integrated resource plans and approved grid investment spending,” Good said. “With the continuation of our 5 to 7% [earnings per share] growth rate through 2029, with the potential to earn higher in the range as the years progress, Duke Energy enters the back part of this decade in a position of strength, and we’re excited about the future.” 

Good said Sideris and the incoming chair of the board of directors, Ted Craver (formerly Edison International’s CEO), are up to the task of leading the utility. 

“I assume this new role at a pivotal point for our company and industry,” Sideris said. “We share the new administration’s commitment to ensuring the availability of reliable and affordable energy to meet our country’s aspirations for technology leadership and economic growth. These priorities align with our business strategy, and we look forward to working with President Trump, both parties in Congress and our states to build, operate and protect the critical infrastructure needed to deliver on these goals.” 

The needs to meet growing demand and replace aging infrastructure mean the firm plans to invest billions of dollars in new generation and the grid, with Sideris saying the firm had a “decade of record infrastructure build.” 

A key source of the new demand for Duke’s utilities is going to be data centers. Sideris said that while Chinese artificial intelligence company DeepSeek’s efficient model might have made headlines and cut into chipmaker Nvidia’s stock, the hyperscale data center developers the utility has worked with already expected efficiency advances. 

“They’re full-speed ahead,” Sideris said. “They’re looking at the fact that these efficiencies may actually increase the demand for AI. So, we have not seen any pullback in anything they’re planning on. In fact, we’ve seen a lot more discussions with accelerating some of their work.” 

Many of the near-term data centers being built in Duke’s territory are not for AI but rather the growth in demand for cloud services, Good said. 

“Then as we move later into the plan, that’s where some of the generative AI data centers are coming in, and that’s when we see the larger load growth,” Sideris said. 

This year and next, Duke expects 1.5 to 2% load growth across all of its utilities, jumping to 3 to 4% in 2027 and staying there through 2029. Its core market of the Carolinas should experience slightly higher growth, with 2% this year and next heading to 4 to 5% for the rest of the 2020s. 

Duke plans to build about 5 GW of new natural gas-fired generation by the end of 2029, mostly in North Carolina, with just one of five plants located in Indiana. The firm plans to start procuring 1.5 GW of solar per year in North Carolina and an additional 900 MW of solar in Florida by 2027. 

The utility also will add storage in the coming years, and it could add small modular reactors by the mid-2030s. Of the $83 billion, Duke plans to spend $37 billion on its transmission and distribution systems. 

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AEP to Increase Investment in Face of Data Center Growth

American Electric Power told financial analysts during its fourth-quarter earnings conference call Feb. 13 that the company is evaluating $10 billion of potential incremental investment because of increasing interest from data centers and other large loads looking to build in its 11-state service territory.

“The tech companies are fast movers, and AEP will be there to support them with whatever technology solution they want to deploy, but we need to ensure that we are protected and compensated,” CEO Bill Fehrman told analysts.

The Columbus, Ohio-based company announced a record $54 billion capital plan in the fall that will last through 2029. Fehrman said AEP expects 20 GW of new load by the end of the decade, much of it in Ohio and Texas.

The utility added 450 MW in its home state in December. It expects an additional 4.7 GW of data center load to come online by year-end.

“We are investing in tailored solutions for new individual large loads to meet their requirements and timelines while mitigating rate impacts to existing customers,” Fehrman said.

AEP already has filed for approval of 2.3 GW of natural gas generation in its Public Service Co. of Oklahoma (PSO) and Southwestern Electric Power Co. service territories. It also has active requests for new generation proposals in Appalachian Power, Indiana Michigan Power and PSO to meet demand.

The company is waiting on a ruling from the Public Utilities Commission of Ohio over proposed tariffs for new large-scale data centers that would require them to pay 85% of their projected energy use each month to cover the cost of infrastructure. AEP filed a settlement agreement with PUCO in October.

“Clearly, we’re going to make sure that this doesn’t fall on the shoulders of our existing customers, and make sure that the appropriate parties who are driving the incremental cost will pay for the incremental cost,” Fehrman said.

AEP reported year-end earnings of $2.97 billion ($5.60/share), an increase from 2023’s performance of $2.21 billion ($4.26/share). For the quarter, earnings were $664 million ($1.25/share), compared to last year’s fourth quarter of $336 million ($0.64/share).

The company’s share price closed at $100.99 on Feb. 13, off $1.36 from its previous close.

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FERC Approves PJM’s One-time Fast-track Interconnection Process

FERC on Feb. 11 approved two PJM proposals aimed at allowing some generation projects to speed through its backlogged interconnection queue. 

The Reliability Resource Initiative (RRI) is a one-time measure to add up to 50 new projects to a cluster of projects to be studied beginning in April (ER25-712), while an expansion of surplus interconnection service (SIS) makes more projects eligible to use underutilized injection capability (ER25-778). 

FERC noted that the proposals are part of a wider effort at PJM to address a capacity shortfall the RTO has identified toward the end of the decade by allowing new resources that either would contribute to grid reliability or require minimal transmission upgrades to advance through the interconnection process in an expedited manner.  

In its “4R” report, PJM said it could be short 10 GW of capacity in the 2030/31 delivery year because of rising load growth, generation retirements and slow new entry; in a June 2024 study, that resource adequacy deficiency was moved up by one year. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.)  

For the RRI, that takes the form of a special application window for Transition Cycle 2 (TC2), created in 2023 as part of PJM’s transition to a first-ready, first-served clustered generator interconnection process. (See FERC Approves PJM Plan to Speed Interconnection Queue.) 

PJM will allow up to 50 projects to be added to TC2, which otherwise is open only to “legacy” projects that had been sorted into queue windows AG2 and AH1, the latter of which closed in September 2021. If more than 50 applications are received, PJM will use weighted scoring to determine which will proceed: 

    • 35 points based on the project’s unforced capacity (UCAP); 
    • 20 points for resources with high effective load-carrying capability (ELCC) ratings; 
    • 10 points for projects sited in the Dominion or BGE zones; 
    • 10 points for being able to achieve commercial operation between 2028 and 2031; 
    • 10 points for evidence of permits, siting and equipment procurement supporting a project’s in-service date; 
    • 10 points to projects that are uprates of existing generation or planned projects; and 
    • 5 points for projects that take advantage of existing transmission headroom.

“This one-time initiative should provide a much-needed on-ramp to the reliability of the PJM system in the short term as we continue to move existing queued projects through our transition cycles,” PJM General Counsel Chris O’Hara said in a statement. “We now hope to see suppliers take advantage of this unique opportunity.” 

In a Feb. 12 message to members, PJM said the application window for RRI projects will be open between Feb. 28 and March 14. 

‘Close Call’

The RRI was approved 3-1, with Commissioner Judy Chang in dissent and Commissioner Lindsay See not participating. 

Chang said that while she agreed with PJM’s assessment that it has a looming resource adequacy problem, “its proposed solution primarily prioritizes the size of the new interconnecting resources over speed and thus is poorly designed to address those very real challenges.” 

She said the proposal should have been rejected without prejudice, allowing PJM to file a similar proposal but with more focus on the viability of commercial in-service dates, which she said should have received the greatest weight of all criteria. She also said that granting only 5 points for transmission headroom availability undersells the value that requiring minimal network upgrades can have on being able to quickly progress. 

“By expediting projects that are unlikely to directly address PJM’s reliability risks in the 2026-2030 time frame, PJM’s filing also presents a risk of the worst of both worlds: It compromises the commission’s open-access principles with no guarantee it will resolve PJM’s reliability issue,” Chang wrote. 

Commissioners David Rosner and Willie Phillips filed a joint concurrence in which they expressed some reluctance but found that the “one-time, extraordinary measure … is only needed because of the equally extraordinary circumstances PJM finds itself in today.” 

The two commissioners said the RRI would not upset the settled expectations of existing projects already in the queue but also criticized PJM’s weighting that favors large projects possibly coming at the cost of rapid construction. 

This made their approval “a close call,” they wrote. “We would have fewer reservations about PJM’s RRI proposal had the commercial operation date viability criteria been stronger. We are concerned that PJM’s proposal may not enable sufficient ‘shovel-ready’ resources to interconnect and enter commercial operation in time to prevent the resource adequacy crisis that motivated PJM to develop this proposal in the first place. 

“In particular, the proposal does not outright require RRI resources to achieve commercial operation by a date certain (e.g., in service prior to 2030) and assigns only 35 out of 100 points to commercial operation viability criteria.” 

Response to Protests

Comments on the RRI remained as divided as stakeholders were when PJM broached it with its membership last year. Many renewable energy developers and clean energy associations were opposed, arguing it would allow queue-jumping, mainly to the benefit of large thermal generators, and possibly increase the network upgrade costs for projects that have been in the queue for years.  

Other generation developers argued it would allow uprates and projects that would be built quickly to enter the queue, a perspective shared by consumer advocates and the Organization of PJM States Inc. (OPSI). (See PJM Stakeholders Wary of Expedited Interconnection Proposal.) 

Invenergy argued that PJM has a track record of discriminating against certain resource classes, which would be continued by the proposal carrying an effective categorical exclusion of wind and solar by prohibiting projects smaller than 10 MW and through the UCAP and ELCC weighting. The Natural Resources Defense Council argued that because UCAP already takes into account resources’ ELCC ratings, breaking the latter out into a second component that disadvantages renewables and storage. 

Constellation said that splitting ELCC and UCAP into two criteria allows for more diversity in the scoring, making it easier for small, high-impact resources like storage to be included. 

Rather than using weighted scores, the Independent Market Monitor said PJM should prohibit projects that don’t meet three thresholds: whether a project would be in the correct location to address a reliability issue, possesses the operating characteristics needed to meet that need and would be capable of entering service in time. Rather than using a static number of projects, the Monitor also advocated for a capacity limit for how many projects can be accepted. 

“Protesters assert that the RRI proposal allows PJM to put a ‘thumb on the scale’ in favor of certain resources in a manner that intrudes upon states’ jurisdiction over the resource mix within their boundaries. We disagree,” FERC said. “The proposal neither mandates nor prohibits the development of any particular generating facility, and it neither authorizes nor requires the adoption of a specific mix of generation resources.” 

In a statement, Jon Gordon, director of Advanced Energy United, said he agrees bold action is needed to address a possible capacity shortfall, but the RRI would not move that ball forward. 

“Unfortunately, the Reliability Resource Initiative is a distraction from the task at hand: restoring confidence in PJM’s interconnection process by fully implementing reforms already underway and prioritizing further improvements — such as the surplus interconnection service reforms also approved by FERC,” Gordon said. “RRI is a misguided proposal that will disrupt the existing queue process with no guarantee of meeting PJM’s identified reliability shortfall. United continues to implore PJM to employ an ‘everything all at once’ strategy to bring clean energy resources stuck in the interconnection queue online as quickly as possible and ensure PJM resource reliability going forward.” 

Sierra Club staff attorney Megan Wachspress said PJM is resisting reforms that would allow more renewable projects to be built in its footprint. 

“It is deeply disappointing that, despite the problems identified by Commissioner Chang and acknowledged by Commissioners Phillips and Rosner, FERC would greenlight PJM’s misguided effort to improve its interconnection process, knowing that adding more toxic gas plants will cause long-term environmental and public health issues across the Mid-Atlantic region,” Wachspress said. “Additionally, there’s no reason to believe this proposal will even address PJM’s short-term capacity problem, since it does not require any of the chosen resources to be online by 2030 or even 2035.” 

Changes to Surplus Interconnection Service Widen Eligibility

FERC unanimously approved PJM’s SIS proposal, though again without Commissioner See’s participation. 

The changes eliminate a categorical restriction on battery storage taking advantage of SIS; allow the service to be used when the original resource is planned and still in development; and allow projects that consume transmission headroom but do not require network upgrades. It also allows projects that require upgrades to interconnection infrastructure to proceed, a change the commission said is warranted given that developers pay the entirety of those costs and therefore would not impact other interconnection customers. 

“PJM’s proposal will facilitate the use of existing surplus interconnection capacity by removing certain limitations in the PJM tariff and by making surplus interconnection capacity available sooner in the interconnection process,” FERC said. 

Aftab Khan, PJM executive vice president of operations, planning and security, said FERC’s approval of the proposal will allow it to better take advantage of existing interconnections. 

“By taking a less restrictive approach to SIS, PJM will be in a better position to utilize existing system capability and existing interconnections that do not require additional network upgrades,” Khan said. 

The proposal received broad support from developers, who argue the RTO has taken a restrictive approach to a process that is meant to allow projects sited at the same point of interconnection as an existing resource. 

In a joint filing, the American Clean Power Association, Advanced Energy United, MAREC Action and the Solar Energy Industries Association said the proposal would unlock dozens of gigawatts of capacity that could be deployed quickly to address resource adequacy concerns, while also potentially reducing strain on the interconnection study process. 

“Under the current process, most surplus interconnection service requests are deemed invalid, necessitating a new service request and placing the developer at the end of the interconnection queue,” the groups said. “PJM’s proposal eliminates this restriction.” 

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Dominion Sees Sharp Rise in Forecast for New Data Center Load

Dominion Energy has seen its forecast for new load from planned data centers in its territory increase by more than 88% over the past six months, the company said during its fourth-quarter earnings call Feb. 12.

Dominion has added about 19 GW of new data center load to its forecast since July, bringing the total to 40.2 GW. The new data centers have a “substation engineering letter of authorization” with the utility, which includes a detailed engineering plan paid for by developers.

Company executives also told analysts that the load was not included in PJM’s most recent forecasts.

“I think it’s just important for everyone to understand that the data center demand in Virginia, in northern Virginia and in Loudoun County continues to be very significant,” CEO Bob Blue said during the earnings call. “You see that in the numbers there.”

Dominion Energy Virginia (DEV) has recently completed two 500-kV lines to serve the state’s Data Center Alley, increasing available headroom by 6 GW, he added. While Loudoun County continues to see the most new data centers, Blue said they are now extending beyond there, especially down I-95 towards Richmond.

“Since we started tracking, we’ve connected approximately 450 data centers, representing nearly 9 GW of capacity,” Blue said. “Data center sales today represent about 26% of total sales for DEV.”

Data centers have wide policy support among political leaders in Virginia, and the Legislature is considering bills to address their rapid growth including Senate Bill 960, which focuses on ensuring that the cost of serving the facilities does not increase rates for other electric customers. The bill cleared the Senate. (See Virginia Legislators Introduce Bills to Deal with Data Center Growth.)

“These kinds of debates about one customer class subsidizing another customer class have been going on since the beginning of utility regulation, and there are ways always to address that in Virginia, particularly with biennial reviews,” Blue said.

Dominion will file its next biennial with Virginia’s State Corporation Commission in March, and Blue said he was sure the process would allow the utility to keep meeting new demand without unfairly burdening other customers.

Uncertainty Offshore

A key piece of infrastructure needed to meet the ever-higher demand from data centers is the utility’s Coastal Virginia Offshore Wind (CVOW) project, which is facing rising costs due to the need for more transmission infrastructure — in part the result of rising demand for materials. (See PJM Network Upgrades Boost Cost of Dominion OSW Project 9%.)

CVOW is 50% complete and on schedule for completion next year, and it is supported by Virginia law with the backing of all of the commonwealth’s bipartisan political leaders, Blue said. Offshore wind has faced opposition from the new Trump administration, but Blue said that should not impact the in-progress project.

“This project is consistent with the goal of securing American ‘energy dominance,’ and is part of a comprehensive ‘all-of the-above’ energy strategy to affordably meet growing energy needs,” Blue said, working in two Republican talking points on energy.

Completion of CVOW still requires about $2.5 billion in components made abroad, mostly in Europe, and it is unclear how much of that could be impacted by tariffs implemented by President Trump, who on Feb. 11 reinstated a 25% tariff on steel and increased tariffs on aluminum imports to 25%.

“With respect to potential steel and aluminum tariffs in particular … generally, these types of tariffs are not intended to apply to most finished products,” Blue said. “We would consider the CVOW components to be finished products. That said, we don’t have the annexes to accompany the executive order. We can’t know what if any of our remaining spend would be potentially subject to tariffs.”

Dominion owns the Millstone nuclear plant in Connecticut, which had a 92% capacity factor in 2024 and has most of its capacity under contract through 2029, Blue said. The plant has options for selling power long-term beyond that with Massachusetts legislation authorizing additional procurements of nuclear power — or possibly setting up a co-located data center.

“We feel strongly that any data center option needs to be pursued in a collaborative fashion with stakeholders in Connecticut,” Blue said. “At this point, we don’t have a timeline for potential announcements.”

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E-ISAC: Foreign Actors Continue to Target Grid

MIAMI — The world is becoming “a scary place” for those defending the electric grid against cyber and physical security threats, representatives of the Electricity Information Sharing and Analysis Center (E-ISAC) told the NERC Board of Trustees’ Technology and Security Committee at its meeting Feb. 12. 

Matt Duncan, the E-ISAC’s vice president for security operations and intelligence, said “the watch order for the E-ISAC going forward is ‘be ready’” in the face of continuing threats from international adversaries like China, Russia, Iran and North Korea. In particular, he noted that suspicious activity from China “has continued unabated” amid the country’s stated plans to have the capability to invade Taiwan by 2027, potentially sparking armed conflict with the U.S. 

“The naming and shaming defenses that we’ve put in have not stopped the persistent cyber espionage and possible prepositioning in critical infrastructure networks in North American and allied countries” by Chinese operatives, Duncan said. He mentioned the Salt Typhoon group, which was recently found to have breached the networks of multiple telecommunications firms, along with the Volt Typhoon group accused of infiltrating U.S. infrastructure organizations for at least five years. (See CISA Leader Reiterates China Cyber Warnings.) 

“While there is no credible, specific and imminent threat to the grid, this [malicious] activity is continuing, which suggests that preparedness and investment in our cyber defenses, as well as increased information sharing, [are] essential to keeping the lights on,” Duncan added. 

The cyber attackers targeting the grid tend to use similar tools and techniques, he said, with probes on identity access management, unpatched firewalls and open ports, and the use of social engineering tools supported by artificial intelligence to trick human grid operators. Duncan stressed that “the best defense is the training of the humans that are on the network,” rather than investments in technology. 

One tool for this training is the E-ISAC’s direct share program, Duncan observed, through which the organization researches cyber and physical security gaps on behalf of the industry and shares them proactively with members and partners from other industries. 

Last year the number of direct shares to electricity industry asset owner or operator member organizations grew by 2.3% to 748, Duncan said; conversely, the number of shares sent to independent partners of the E-ISAC — organizations in other critical industry sectors or the government — declined by 6.5% to 2,790. The E-ISAC attributed these shifts to “a renewed focus on the electricity and gas industries and their equipment, and improved email security.” 

Media Frenzy Fed Drone Sightings

Duncan also discussed the unusually high number of drone sightings reported in December. Numerous citizens on social media described seeing unexplained unmanned craft in the sky that month, and the FBI said it had received more than 5,000 reports of drone sightings through its tiplines.  

The Federal Aviation Administration temporarily restricted drone flights over 22 cities, though investigators later determined that there was nothing suspicious about the reports and that the sightings were all either of lawful drones from hobbyists and law enforcement, or planes, helicopters and stars mistaken for drones. 

Duncan acknowledged that the E-ISAC also received a large number of reports of drones flying near critical infrastructure equipment in December, which were described in accompanying material (page 29) as being equal to about half the number of reports normally received in a two-year period. However, he emphasized that the E-ISAC determined there was no threat to grid reliability. The uptick in reports was driven largely by the media attention given to drones in general, he said. 

Drones can be used to attack grid facilities, as in the case of a Tennessee man charged with planning to rig an unmanned aerial vehicle with explosives and fly it into an electric substation. (See Feds Accuse Tenn. Man of Substation Attack Plot.) While Duncan pointed out that drones do have legitimate uses for electric utilities, he said the E-ISAC must continue to work with partners to address their potential dangers. 

“The challenge, of course, [is that] there’s not a lot that can be done in the mitigation front yet, but we’re working with the [Federal Aviation Administration, the Cybersecurity and Infrastructure Security Agency] and industry to make them aware of the potential impact and request additional support,” Duncan said.