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December 18, 2025

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FERC Rejects MISO’s Interconnection Queue Fast Lane

FERC has refused MISO’s proposed special pathway in its interconnection queue for generation projects labeled necessary by state regulators.  

The commission said MISO’s proposal lacked direction to advance resource adequacy, and the fast lane ran the risk of becoming inundated with an unlimited number of generating facilities (ER25-1674). FERC said it rejected the proposal without prejudice, leaving MISO free to file for another express lane design in its queue.  

MISO filed in mid-March for the temporary measure to usher generation projects crucial to an adequate supply through its interconnection queue faster. MISO’s intention for a 90-day processing for “shovel-ready” projects with a stamp of approval from state regulators would have been far removed from the upward of three years that most interconnection customers must wait in the regular queue. 

New capacity seeking expedited treatment would have had to come equipped with a permission slip from its relevant regulator; a $100,000, nonrefundable deposit; a refundable milestone payment of $24,000/MW; a designated commercial operation no more than three years from its interconnection request; and proof of land rights.  

Opponents of the plan said it effectively would have allowed vertically integrated utilities’ gas plants to cut the interconnection line while hindering independent power producers’ proposals. They also raised concerns over how the proposal would include Illinois and Michigan’s retail choice areas. (See MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC.) 

Eight former FERC commissioners even warned sitting commissioners via a joint letter that greenlighting the plan would threaten FERC’s open access transmission tenet and would have provided an opportunity for self-dealing among utilities to advance their affiliated generation. 

The commission in its May 16 order said MISO’s decision not to place any limit on the number of projects or specify a megawatt maximum could culminate in an oversaturated process with lengthy processing times, eventually resembling MISO’s existing, beleaguered queue. The commission said MISO would be hard-pressed to meet resource adequacy and reliability targets with a bogged-down fast track. 

FERC said MISO itself acknowledged the “shortcoming” of unlimited projects by stating it “could not guarantee the timeline … if multiple requests are submitted in the same quarter in the same area of the grid due to the serial nature” of the specialized studies. 

The commission said MISO’s plans to open up to 14 quarterly submission windows across the handful of years the fast lane would be in operation opened the door for a “volume” of interconnection requests “untethered to reliability or resource adequacy needs.” It said it questioned whether MISO’s proposal could get critical resources interconnected on an expedited schedule and whether the design was “narrowly tailored to fix the problem.”  

Beyond that, FERC said MISO didn’t establish how the process would assemble and study only key interconnection requests for projects that would aid reliability.  

FERC said similar proposals like PJM’s Reliability Resource Initiative and CAISO’s Interconnection Process Enhancements were more custom-built to address resource adequacy in their regions. PJM proposed to study no more than 50 projects on a one-time basis with stipulations on location and deliverability, the commission said, while CAISO laid out system needs criteria to determine which projects advance to study zones that are capped.  

FERC said MISO failed to strike a similar balance that would have projects that improve resource adequacy and reliability processed in a timely manner.  

“MISO has not demonstrated that the proposed tariff language is tailored to ensure that only those resources capable of addressing identified near-term resource adequacy or reliability needs are eligible for expedited study,” FERC said.  

The commission said while it’s appropriate for regulatory authorities to size up their resource adequacy needs and throw support behind certain projects, MISO must ensure that its fast track respects FERC’s “open access principles in an objective and transparent manner in order to meet the [Federal Power Act’s] requirements that rates be just and reasonable and not unduly discriminatory or preferential.”  

“MISO has not done so with this proposal,” FERC wrote.  

Christie Willing to Trade Vagueness for Desperately Needed Megawatts

However, FERC Chair Mark Christie said he was ready to give MISO the benefit of the doubt in exchange for an uptick in resource adequacy.  

Christie said though he “fully” understood other commissioners’ qualms with a lack of detail and personalization in MISO’s proposal, he was willing to “extend to both the states and MISO a trust that they would implement the … proposal in a manner that would promote the construction of badly needed generation capacity that serves resource adequacy and reliability.”  

“One thing we know with no need for further proof: This country, including MISO, is heading for a reliability crisis caused by early retirements of dispatchable resources coupled with the failure to construct sufficient equivalent capacity, all while demand rises at an unprecedented pace largely driven by data center growth,” Christie warned in a dissent.  

Throughout the order, FERC invoked NERC’s 2024 Long-Term Reliability Assessment, which shows MISO could confront a 4.7-GW capacity shortfall by 2028 if resource generations go off as planned.  

Christie furthermore said he didn’t think FERC should “block the states” from designating priority generation plans to ensure resource adequacy within their borders. He noted that states “are sovereign entities with the inherent police power under our constitutional structure to regulate the utilities in their state.”  

Two commissioners, however, wrote separately to say that MISO’s omissions were too glaring to ignore.  

Commissioner David Rosner said while rejection wasn’t an “easy decision,” MISO’s expedited lane as described “risks replicating the same backlogs and delays plaguing MISO’s existing generation interconnection queue, which are what put MISO in its current situation in the first place.” He also said that MISO’s insufficient limits on study requests risked a court finding that the fast lane is unjust and discriminatory and striking it down, “leaving MISO worse off than taking no action.” 

“While MISO clearly intends to design a process that considers only ‘tens’ of interconnection requests per year, there is no guarantee that interest” will be limited, Rosner said.  

Rosner said he believed FERC’s order of rejection provided MISO enough direction to draft a second attempt.  

Commissioner Lindsay See likewise encouraged MISO to bring FERC a more workshopped proposal.  

See said she couldn’t overlook that MISO’s plan left out retail choice states Illinois and Michigan and would bestow undue preference on resources connecting in vertically integrated states.  

“Because the commission should remain evenhanded when it comes to our state partners, a proposal that discriminates among the states themselves gives me serious pause,” See said.  

See also said MISO should require the states to explain how they decided certain projects are essential for reliability or resource adequacy. See said although MISO promised its fast lane would be “‘open, competitive [and] technology/fuel agnostic and … not involve MISO favoring or selecting certain projects over others,’ nothing in the tariff explains how it will live up to those goals.”  

“Simply put, the commission cannot evaluate criteria that do not yet exist, that will vary state-by-state when they do and that MISO does not plan to police,” she wrote.  

MISO Prepped for Positive Outcome

Meanwhile, MISO had begun preparations to start project acceptance.  

MISO posted an informational guide on the fast track in anticipation of a favorable FERC order. Through an email to stakeholders, MISO said if the proposal was not accepted by the commission, it would remove the guide from its website.  

MISO planned to open an application window for the first quarterly fast-track study treatment through May 22. It planned to accept submissions for the first expedited cycle through an email dedicated to interconnection issues, and launch a submission portal this summer for upcoming cycles.  

MISO planned to process quarterly study classes until the end of 2028. The next application deadline would have come due in mid-August.  

During an Organization of MISO States’ Resource Adequacy Summit May 13, MISO CEO John Bear said the RTO didn’t yet have projects lined up for the fast lane and said he couldn’t offer an overview of the resource mix that would have become the first entrants in the express lane.  

“Fixing the queue is not a challenge. Clearing the queue is a challenge. You’ve got a 130-GW system with 350 GW in the queue. … You can’t even model that,” Bear said of the regular queue lineup. He predicted it would take MISO about three years to get a handle on its stockpile of proposals.  

In response to an audience question on whether some of the queue volume would drop off naturally, Bear said he didn’t want to guess how many generation projects might not be realized. He said developers have put a lot of money and planning behind their projects, and MISO’s newly higher fees, stricter land use requirements and stepped-up withdrawal penalties mean projects have been subjected to more scrutiny than in the past.  

Win for Clean Energy Groups

Clean energy organizations are likely to rejoice at the ruling.  

In a statement, Earthjustice said the proposal would “sideline generation projects that have been waiting years to connect and send everyday consumers the bill for fast-tracking projects hand-picked by special interests.” The group said the expedited process would discriminate illegally against competitive clean generation developers. It also said MISO risked backsliding into “inefficient, serial interconnection studies.” 

“FERC rightly rejected the proposal from MISO to fast-track connection of utility-owned methane gas projects over the queue of clean energy projects that have been waiting years to connect to the grid. FERC’s role as an independent agency is to protect consumers and ensure reliable affordable energy. The best way to do that is [to] let clean energy compete fairly and openly,” Earthjustice attorney Christine Powell said in a statement following the decision.  

Clean Grid Alliance similarly criticized the proposal in a blog post prior to FERC’s ruling: “The trouble with [the Expedited Resource Addition Study (ERAS)] is, in short, ERAS as currently proposed doesn’t play by the rules. At least not the rules everyone else must play by. There doesn’t seem to be any other reason to allow this process than to create a pathway for adding new natural gas and enable ‘queue jumping,’ which allows certain projects to bypass the current interconnection queue process and skip ahead of projects that have been waiting in the queue for years.”  

States outside of Michigan and Illinois, however, had urged FERC to approve the expedited queue lane. 

In similar, recent letters to FERC, Mississippi Gov. Tate Reeves (R) and Arkansas Gov. Sarah Huckabee Sanders (R) called the proposal “essential” and cited the risks posed by rising load.   

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Indiana Tries to Spur New Capacity, Delay Retirements with New Law

Indiana has a new law aimed at motivating new capacity in the state to serve rising load and restricting when utilities can shut down plants. 

The legislation expedites the Indiana Utility Regulatory Commission’s approval process on utilities’ generation plans to serve large-load customers like data centers. It also creates cost recovery processes for utilities to recover the projects to accommodate big-need customers and makes it more difficult for utilities to retire their existing generation.  

Finally, the law provides for a 20% state tax credit for in-state producers that manufacture small nuclear reactors.  

Gov. Mike Braun (R) signed the bill into law May 6. House Republicans advanced the bill April 22 in a 63-23 vote along party lines (HB 1007).  

The law defines a large-load customer as one requesting new electricity demand greater than 5% of the utility’s peak load or 150 MW.  

The law mandates customers requiring a big grid buildout to make “significant and meaningful financial assurances” for the projects they need, covering at least 80% of costs and shielding other customers from picking up the bill. 

It also compels public utilities to annually report to the IURC any generating units of at least 125 MW that they plan to retire. The IURC then would initiate an investigation into the withdrawing generation. If the commission finds that a utility cannot reliably meet demand without the unit or is unable to meet its planning reserve margin requirement, it would block the plant closure or direct the utility to acquire or build equivalent capacity. The law dictates that utilities must have replacement plans of “approximately the same accredited capacity” as the retiring unit within their RTO.   

Per Indiana’s existing law, any utility not meeting at least 85% of its peak load must provide the IURC with capacity projections for the next three years. 

A fiscal analysis from the legislature found that the SMR state tax credit could cost taxpayers about $280 million. It also found that the new retirement investigation provisions will increase the IURC workload. Indiana lawmakers are not dedicating more resources to the IURC to handle the added work.  

Indiana’s Republican representatives said the law is necessary to incentivize capacity additions. Democratic representatives voiced concerns the measures would keep coal plants online longer and have taxpayers spending too much to subsidize small modular reactors.  

The Sierra Club said the law would “increase electric bills and spew more pollution throughout the state.”  

Rep. Ed Soliday (R-Valparaiso), who authored the bill, told local news outlets that Indiana is in competition with other states to entice large-load customers.  

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MISO CEO: Slim Reserves Not Necessarily Bad

ROSEMONT, Ill. — MISO CEO John Bear put a positive spin on the grid operator making do with little cushion in its supply. 

During the Organization of MISO States’ annual Resource Adequacy Summit on May 13 in Chicagoland, Bear said it’s not necessarily a bad thing that MISO has only thin excesses on top of its margins. Other speakers posed ideas on how to beef up supply.  

Bear said even though NERC and the industry might say MISO is “on fire” in terms of resource adequacy, MISO is managing nicely while operating ever closer to its planning reserve margins.  

“Being glass half full, I’d say we’re pretty efficient,” Bear said.  

Bear said last year, the RTO and the Organization of MISO States’ joint resource adequacy survey “gave us some warning lights” and members reacted accordingly to avert a potential 2.7-GW capacity deficit the survey showed arriving as soon as summer 2025. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.)  

Nevertheless, Bear said MISO and the stakeholder community must get comfortable with enacting market and planning changes swiftly to continue to be resource sufficient.  

“Eighteen months to redo the futures is incredible. We’ve got to do it in six,” Bear said, referencing the several months MISO has set aside to update the set of 20-year scenarios it relies on to chart big-ticket transmission projects.  

MISO Vice President of System Planning Aubrey Johnson said MISO was inspired to add its supply-constrained fourth future to its existing trio of scenarios because staff noticed a few years ago that generation was not coming online as scheduled. (See MISO Forming 4th Tx Planning Scenario Based on Supply Chain Barriers.) Johnson said to finish the futures, MISO needs to “move,” meaning MISO gets its futures information in front of stakeholders and makes sure they understand and are mostly comfortable with them before finalizing them.  

“Those that are not quite there, we can’t let them hold up the pace of change,” Johnson said.  

Bear acknowledged that achieving the cooperation to move fast is “tough” across the country right now. But he added that MISO would be challenged even if load growth continued at a docile 1% per year and data center projections didn’t jump exponentially.  

“We’ve got a lot of old power plants that aren’t performing well. That’s changing, by the way, thankfully,” he said. “We’re going to have to get more energy on the system … even if the data centers don’t show up.”  

MISO CEO John Bear (left) interviewed by Minnesota Public Utilities Commissioner Joseph Sullivan | © RTO Insider 

Bear said MISO is poised to double its 13-GW solar fleet over the next two years. However, he cautioned that MISO must be thoughtful about balancing its inverter-based resources. He said the risk posed by inverter-based resources is very real, exemplified by the frequency issues that likely were the culprit behind the late April blackout in Portugal and Spain.  

MISO has noticed it increasingly encounters challenging operations in spring and fall on days when renewable energy output is high, Bear said. He said MISO is keeping tabs on its changing needs and will investigate adding frequency products or accrediting resources differently around frequency and inertia.  

Bear also said MISO’s proposed fast track in the queue for proposed generators deemed indispensable to resource adequacy by state authorities should get key projects online sooner. (See MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC.) 

Bear said MISO has devoted considerable time to planning transmission so wind and solar can be dispatched efficiently across the footprint. He pointed out MISO doesn’t need to track a significant number of curtailments, like the graph CAISO maintains.  

MISO Independent Market Monitor David Patton asked the audience if anyone was surprised by the capacity auction’s $666.50/MW-day clearing price for the upcoming summer. MISO’s capacity auction left all but 300 MW of offers unused. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.)  

He was met with silence.  

“If you haven’t been tuned in, capacity prices went up manyfold from past years,” Patton said.  

Patton said MISO buying 2% beyond the absolute summer minimum capacity standards is good for the health of the system. 

“It was a bargain to buy it. … It’s not a bad thing that we bought beyond the minimum requirement,” he said. Patton also said states were instrumental in getting the auction clearing on a sloped demand curve. 

“We saw how powerful I was, recommending this for 10 years,” Patton joked.  

However, Patton said the “full” signal to build generation won’t arrive until MISO institutes its new, availability-based capacity accreditation beginning in mid-2028. He said the accreditation will deliver a final puzzle piece and allow the footprint to better meet long-term resource adequacy objectives.  

Under the new accreditation, most resources’ capacity values are set to fall, as evidenced by MISO’s evaluation of this year’s supply had the accreditation been in place.  

“It’s going to change how people plan, it’s going to change how merchant generation is built, how [integrated resource plans] are made,” Patton said.  

IMM: Problem Remains with ‘Not Real’ DR

However, Patton said he remains deeply concerned about demand response gaming MISO’s markets. He said MISO’s recently filed suite of stricter rules should close some loopholes that allow DR to collect payments for doing nothing. (See Stakeholders Ask FERC to Soften MISO’s Proposed DR Accreditation.)  

He said MISO is right to “aggressively” confirm that DR resources are genuine. He said if MISO does that, DR should function more like MISO traditional generation, which responds when called upon. Patton said MISO carrying only authentic and responsive DR ultimately should reduce costs.  

Patton hinted at more referrals to FERC’s Office of Enforcement. He said an audit of MISO’s DR fleet turned up a retail customer that was registered under multiple market participants and a data center that has offered demand reductions and collected payments for about two years despite not yet being built.  

“If you look at the site, it’s a really pretty greenfield with weeds,” Patton said. “We cannot allow people to sell us something that’s not real.”  

Other Perspectives

Other speakers at the OMS meetup had plenty to say with resource adequacy risk at MISO’s doorstep. Alliant CEO Lisa Barton struck a decidedly graver tone in her keynote address.  

Barton said she was sure the audience “was glued to their phones on April 28,” tracking the Iberian outage as it unfolded. She said she was sure attendees are focused on “making sure what happened there doesn’t happen here.”  

Barton said industry players should be dedicated to at least holding up or bettering today’s levels of reliability and resiliency. She said “one of the unfortunate things” is people eventually forget grid disasters like Winter Storm Uri.   

“We need to remind ourselves that’s out there,” Barton said.  

Barton said there’s value in assessing events that “might not have happened in our backyard” and committing to learning from them. She said Spain and Portugal are dealing with a $1.7 billion fallout and a handful of deaths from just “one day of the lights not being on.”  

Barton said the event should reinforce the idea that resource adequacy takes all kinds of generation, with some types more consequential than others.  

Barton praised MISO for proposing an interconnection queue fast lane to get select generation online faster.  

“I know it’s not a universally popular decision, but it’s action,” Barton said, adding that “not acting is a far greater risk.  

“I remember saying to my daughters, ‘Not making a decision is a decision.’” 

Barton said it can’t be ignored the U.S. population is benefiting and living on grid investments made decades ago. She said no matter your politics, nearly all can agree the industry needs to expand generation to support American innovation.  

“What I think we can agree on is, we have to win the technology war,” she said. 

Barton said MISO members should be insistent on striking flexible load arrangements to handle incoming large loads. She warned that it “all can’t be fixed with transmission.”  

Finally, Barton said it’s not a good idea for data centers to strike out on their own and secure their own generation construction. She said data center developers likely would seek components that utilities also are vying for, likely exacerbating supply chain problems. Barton said independent generation construction is reminiscent of a pre-RTO world, where utilities planned in isolation and transmission and generation redundancies existed. It’s possible, Barton said, to work in protections for ratepayers while still offering attractive rates to data centers.  

Data Center DR?

Despite the IMM’s indication to expect more enforcement against DR double-dealing, some are bullish that data centers are a new frontier.  

Duke University fellow Tyler Norris said the idea that data centers are strictly inflexible and need firm service 24/7 isn’t true, as evidenced by a 2024 report from the Secretary of Energy’s Advisory Board. He said there could be some load flexibility found when the system needs it most.  

“Outside of the 15 to 20 hours across the year … during cold snaps or heat waves, there’s a lot of headroom” on the system, Norris said.  

He said Duke’s recent research found that if data centers could curtail load annually at just 0.25% of their potential maximum use, it could allow the existing grid to support about 76 GW of new load across the U.S., with 11.6 GW of that in MISO. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) Some in the industry are skeptical those figures can be achieved without co-located generation.  

Norris pointed out that the country’s grid is built around the “few hours per year of extreme demand” and outside of demand peaks, about half of generation capability can go unused. Norris said while regulators might think data centers are running at a 100% utilization rate, they’re more likely to be running in the order of 40 to 50%. He said some of the unrealized use stems from data centers’ tendency to overstate interconnection needs.  

“There’s a lot of potential there,” Norris said, but added that the flexibility from data centers will look different from traditional DR. He said grid operators will need to “get creative” to design different service tiers of DR to accommodate them.  

He also said flexibility tradeoffs are being hammered out between data center developers and power suppliers.  

“We know that those negotiations are happening, but on a purely bilateral basis, without a tariff,” Norris said. He said regulators might decide to outline some regulations for use agreements.  

Nevertheless, Norris acknowledged the industry is in a “real crunch for the next five to seven years” to get generation built. He said construction probably will be more difficult because of the Trump administration’s repeal of Biden-era tax credits.  

Surplus Interconnection Service and Batteries

GridLab’s Casey Baker said in MISO, there’s a possible “double-digit energy and capacity” solution in MISO in the form of using surplus interconnection across the sites of the RTO’s approximately 50 GW of renewable energy. He said members could build companion battery storage across those sites or, conversely, build wind or solar resources at some of MISO’s seldom-used and aging peaker plants to make the most of their little-used interconnection service. 

Baker said building to use more interconnection service wouldn’t require network upgrades or the intense study and permitting that greenfield construction would require.  

“We have this perception that the grid is tapped out, and that’s true in certain hours, but that’s not true in most hours,” Baker said.  

Baker called batteries the “Swiss Army knife” of resources and said they can bolster resource adequacy, work as a transmission asset and provide inertia and grid-forming services, if customers are willing to pay for those models.  

Mia Adams, of Ulteig Engineering and a MISO alum, added that MISO needs better participation rules for energy storage. She said though most believe that lithium-ion batteries have a four-hour limit, some can last up to 16 hours now.   

“If you have the need, there’s a solution if you’re willing to pay for it,” she said. However, she added that most storage projects “in MISO don’t pencil out because of the market design.”  

Adams said a 100-MW battery could be built within four months. Along with companion wind and solar generation, Adams said the footprint could host inexpensive, dependable new generation quickly.  

Adams asked the audience to embrace new technologies sooner. She warned that data centers aren’t the only ones lining up for load treatment, nothing that heavy industry like aluminum smelters and steam crackers are looking to electrify.  

And Adams said political instability in the form of will-they-won’t-they tariffs is upending plans for new generators.  

“It’s not just batteries that come from China. It’s a very intermingled supply chain,” she reminded the audience.   

Laura Schepis, an executive director at the National Electrical Manufacturers Association, agreed the volatility wrought by tariffs is anathema to planning and building resources.  

Electric Power Research Institute’s Director of Power Systems Aidan Tuohy agreed that data centers aren’t the only growth the industry is facing, invoking increasingly electrified transportation, electrification of heat and reshoring of manufacturing.  

From left: Wisconsin Public Service Commissioner Marcus Hawkins, Aidan Tuohy of EPRI and Tyler Norris of Duke University | © RTO Insider 

“We know we can’t necessarily build fast enough to meet that demand,” he said and offered demand flexibility and grid-enhancing solutions as ways to maximize the grid and get a breather on adding new generation.  

Sparkfund CEO Pier LaFarge said the industry is navigating a moment not seen since the Industrial Revolution, where the data center explosion is coinciding with geopolitical tensions.  

Xcel Energy Vice President of Supply Chain Murray Sanderford seconded the echoes of the Industrial Revolution.  

“In my career, I’ve never seen something so daunting from a supply chain standpoint,” Sanderford said. He said he and his peers estimate that just 60 to 70% of planned generation won’t get built due to lack of labor and lack of equipment.  

MISO’s Aubrey Johnson reminded attendees that about 30 GW of MISO’s 53 GW in generation projects that have signed generator interconnection agreements but have yet to come online are more than two years behind their commercial operation deadlines.  

Johnson also noted the industry is grappling with a growing shortage of technicians specializing in inverter-based relay systems, another obstacle to meeting demand and reliability targets simultaneously.  

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MISO IMM to State Regulators: Good Intentions Behind LRTP Criticism

ROSEMONT, Ill. — MISO Independent Market Monitor David Patton addressed the recent controversy surrounding his longstanding criticism of MISO’s latest, $22 billion long-range transmission portfolio at the Organization of MISO States’ Resource Adequacy Summit.  

Patton began a May 13 unscripted talk to regulators by joking that the “ominous” red light background on stage wasn’t doing him any favors. He told regulators that he was on their side despite some states being disappointed that he condemned many of the underpinnings of MISO’s second, $21.8 billion long-range transmission plan (LRTP) portfolio. 

Patton said he was only trying to “weaponize the markets” to spur the most reliable and economic dispatch decisions while respecting states’ policies.  

“By the way, I love transmission,” he joked. At another point, Patton teased that he “wasn’t allowed” to speak out on transmission planning, referring to MISO leadership asking FERC whether it’s appropriate for the IMM to analyze the value of proposed transmission portfolios in addition to markets. (See MISO Intent on Answers as to IMM Role in Tx Planning.)  

Patton’s comments come about a week after MISO petitioned for the declaratory order with FERC (EL25-80). The RTO’s stakeholders are split on whether the IMM should independently assess the value of transmission projects. Patton continues to take issue with several of MISO’s estimates of the second LRTP portfolio, including its underlying capacity expansion modeling and the value of resolved reliability benefits, the amount of new generation that can be avoided and environmental benefits through the new transmission.  

MISO anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the LTRP projects’ lives through reliability improvements, production cost savings, capacity that won’t have to be built and environmental benefits. The IMM has pinned the value of LRTP II closer to a 0.3:1 benefit-to-cost ratio and has advocated for a condensed portfolio.  

Patton said transmission planning and functioning markets are intrinsically linked and should be evaluated interdependently.  

“We have to understand that when we make bad planning decisions, we undermine the market,” Patton told attendees. He again said the 20-year future MISO relied on to recommend the portfolio of mostly 765-kV lines is impractical and doesn’t represent the resource mix that will be built.  

Patton said MISO is overbuilding the transmission system at the cost of the market incentivizing the construction of battery storage and developing other dispatchable technologies. It’s “very important” that MISO be realistic about the generation mix that’s on the horizon, Patton said, pointing out that many utilities remain committed to building new gas generation despite MISO allowing for very little in the future it used to plan the second LRTP.  

“If we plan for a fictional system … we’re going to either pay higher costs or have an unreliable system,” Patton said.  

In its filing, MISO asked FERC to “confirm” that the IMM’s “unsolicited transmission planning and monitoring activities are outside the scope” of its engagement rules with the IMM under its tariff and that it “has no obligation to reimburse Potomac [Economics] for such unsolicited transmission planning and monitoring activities at the expense of tariff customers.”  

MISO’s Board of Directors in mid-February directed RTO leadership to freeze all payments to the IMM for work related to transmission planning. 

MISO said its request did not preclude it from relying on an independent transmission monitor in the future. It also said it wasn’t seeking to “limit the activities of Potomac, such as participating in stakeholder processes, separate and apart from its role as the hired IMM for MISO.” Essentially, MISO said the IMM should size up transmission, pro bono and on the side as an interested stakeholder.  

MISO said it needed to “remove uncertainty” around the IMM’s authority and figure out which services its customers should be paying the IMM for. 

The grid operator ended by saying it plans to hire an independent, third party to assess the benefit estimates of future LRTP portfolios and the 20-year scenarios it devises to justify them.  

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Community Opposition Still a Hurdle for Storage in N.Y.

ALBANY, N.Y. — The annual New York energy storage conference came with excellent timing this year, as progress at the state level was matched by looming obstacles at the federal level.

As the 2025 edition of Capture the Energy Conference & Expo kicked off, the on-again-off-again global trade war had been paused, removing for now the threat of crushing tariffs on battery components.

But given the mercurial state of affairs, and the ongoing debate over tax credits, few people expect the picture for energy storage and the batteries it relies on to be settled.

“I think every analyst’s favorite word at the moment is ‘uncertainty,’” Iola Hughes, head of research at Rho Motion, said as she launched into a rapid-fire update on tariffs and their effects.

There is no immediate way around tariffs, she added: “Even by 2026, we’re only looking at around 20% of demand being met by domestic cells, based on the current pipeline of gigafactories being built out.”

The May 13-15 conference was the 15th and the largest yet for the New York Battery and Energy Storage Technology Consortium (NY-BEST).

As its name implies, NY-BEST supports the development and deployment of all storage technologies. But batteries account for the vast majority of storage capacity being added to the grid, so the conversation at Capture the Energy tends to be focused heavily on them.

Iola Hughes, Rho Motion | © RTO Insider 

“In 2024 we saw lithium-ion battery demand surpass 1 TWh for the first time,” Hughes said. “This was a milestone narrowly missed in 2023, and I think, really, that’s just a sign of how much this market has progressed over the last few years.”

Doreen Harris, president of the New York State Energy and Research Development Authority, delivered a keynote address assuring an audience of hundreds that the state remains wholly committed to energy storage deployment, as storage will be needed in the tens of gigawatts if New York is to accomplish its transition to a grid heavily reliant on intermittent renewables.

But Harris had to cut herself short so she could catch her flight to Washington and continue to lobby for saving the policies that will help make that sort of buildout possible.

Amid the federal uncertainty, New York continues its part, with orders from the Public Service Commission pushing the process forward and $200 million awarded to support construction so far.

“And now, rounding out this trifecta, just yesterday we issued a draft [request for proposals] for our bulk energy storage solicitation,” Harris said.

New York’s first energy storage target is 1.5 GW by the end of the year. It has doubled its 2030 goal to 6 GW of new storage.

In June 2024, the PSC approved the roadmap for reaching 6 GW (Case 18-E-0130). It approved the implementation plans for storage projects totaling 5 MW or less in February 2025 and for bulk storage (greater than 5 MW) in March 2025.

Just recently, the Department of Public Service issued a progress report showing the state of storage in New York as of the end of March: 509.2 MW deployed, and 893.3 MW awarded or contracted.

The average total installed project cost ranges from $524/kWh (for bulk projects serving wholesale markets and receiving incentives) to $1,198/kWh (for customer-sited standalone behind-the-meter projects used for peak load reduction).

Supply chain constraints, inflation and high demand for cells drove up costs, the report notes, and these high costs have been a continuing barrier to timely buildout of storage in New York.

But right up there with cost is public opposition.

Battery energy storage system (BESS) fires, while rare, leave a strong negative impression, amplified by the fact that most people know nothing about grid-scale batteries or the risks associated with them.

New York has a strong home-rule tradition, and that fear of the unknown has translated into numerous moratoria on BESS development.

John Zahurancik, Fluence | © RTO Insider 

John Zahurancik, president of the Americas for Fluence, said BESS fires have developed an outsized profile as a result of the unfamiliarity and insecurity public officials and their constituents have with these facilities.

“We don’t call a news conference when a transformer blows up, even a big transformer. We don’t close highways when transformers blow up,” he said. “But we’ve done some of those things with energy storage recently.”

There is uneven quality control by some manufacturers, Zahurancik added, and it is incumbent on developers to not just rectify that but to prepare for all contingencies in the event of a fire, right down to emergency phone numbers going missing or not being answered.

“Another one of our revelations was, people don’t always do what you expect them to do in a moment of crisis,” he said. “That may not seem like a very deep revelation, but there’s a lot of truth to it. And so you can’t really control all the actors, so you have to design systems that are overly safe against people, and you have to drill and constantly talk about, ‘What are you going to do in these events?’”

An entire panel discussion was devoted to winning over community support for BESS proposals.

“Our knee-jerk response as an industry has been to talk about facts, to bring in technical studies and peer-reviewed reports and know that the facts are on our side, and sort of flood the misinformation with the facts. And unfortunately, that’s not a great strategy,” said Lauren Glickman, vice president of policy and communications at Encore Renewable Energy. “It’s really important to build bridges by coming around and [connecting] with individuals and bringing empathy to a lot of these conversations and finding shared values.”

Lauren Glickman, Encore Renewable Energy | © RTO Insider 

Nadia Pabst, senior vice president of government and corporate affairs at Aypa Power, said she defines success as community members having a better understanding of what energy storage is and how it fits into the broader energy transition. “Ultimately, we’re all working towards a decrease in blackouts and brownouts across the country and increased grid reliability.”

Without a compelling narrative, Pabst added, it is hard to compete with the prevailing misinformation.

Sam Brill, vice president of strategic development at NineDot Energy, said developers should make local officials their first point of contact for a new proposal — because they will not appreciate learning about it through word of mouth but also because they can suggest who best to talk to in the community.

Glickman also stressed that community relations should not end when the project reaches commercial operation status. “Trust is something that’s earned, but it’s also something that can be lost. So if you earn it, but then disappear, you’re not going to be seeing it.”

Key Capture Energy provided speakers for the panel discussions during the conference and maintained a table at the expo portion of the event. Senior Director of Development Kolin Loveless told RTO Insider he sees two sources of community opposition: individual uncertainty and actively spread misinformation.

New Yorkers’ uncertainty about fire safety grew from three unrelated BESS fires in rapid succession in three widely separated parts of the state in 2023, as well as a horrifying spate of e-mobility battery fires in New York City that had nothing to do with BESS except that both types of batteries contained lithium.

Kolin Loveless, senior director of development at Key Capture Energy, stands at the company booth during NY-BEST’s Capture the Energy Conference & Expo in Albany, N.Y., on May 14. | © RTO Insider 

Loveless hopes the fire safety review panel the state convened after the 2023 fires will calm the uncertainty or fears. Until then, the permitting structures in New York will make the fears more impactful here than elsewhere.

“Part of that is home rule and the way that is structured, and a part of that has been [in] a lot of the other states where we are operating, they either don’t have major permitting regimes — Texas does not require permits in a significant way, and so there’s not that same question — [or there are] state-run processes for energy projects.”

KCE started in Albany nine years ago, and its headquarters is just down the hill from the event venue; its operational projects are all in New York and Texas, but its development pipeline stretches from Maine to California. So it is exposed to a wide range of public policies and popular sentiments.

Loveless made a point Zahurancik also made: Execution is important. A lot of the fires have been in first-generation BESS projects, and a lot can be learned from them.

“We’re already rolling out Gen 3, 4 and 5. And what we’ve done, actually, as an industry, pretty well, is learn from what happened before and implement those things into all the different codes that we follow. The next step is basically forcing the market to follow.”

An entire bucket of community opposition in the state has been hesitation more than opposition, he said, as some local officials await the results of the New York Inter-Agency Fire Safety Working Group’s efforts.

A key recommendation was that project permit applications undergo a peer review. That might ease the hesitation, but it might not.

“In a way you’re effectively asking every town in New York to be able to make its own assessment,” Loveless said. “The idea behind what the Fire Safety Working Group has worked out is a peer review process, so they don’t need that expertise. But I don’t know that jurisdictions are all fully comfortable. Some are, some are not. So that’s the challenge that we’re all working through. And unfortunately, for projects, that’s a binary outcome.”

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Calif. Looks for Ways to Spur Heat Pump Adoption

SACRAMENTO — California’s goal of deploying 6 million heat pumps in buildings by 2030 is being tackled from multiple angles, and the different strategies were the subject of a panel discussion during a recent conference. 

The California Energy Commission plans to launch in 2025 the Direct Install Program — a key piece of its Equitable Building Decarbonization program. Direct Install will provide no-cost home electrification retrofits and energy efficiency for low-income households in California. 

Another program is TECH Clean California, which offers rebates for heat pump appliances in single and multifamily homes across the state. The program just received another tranche of CEC funding, CEC Commissioner Andrew McAllister said May 6 during a panel at the California Energy Transition Summit hosted by Infocast. 

In addition, the Building Initiative for Low-Emissions Development (BUILD) program is providing incentives for construction of new, all-electric, single and multifamily homes, McAllister said. 

Panelist Jose Torres, with the Building Decarbonization Coalition, said Direct Install is geared toward older homes that are harder to electrify. The TECH Clean California program could help people living in newer homes who are interested in heat pump air conditioning, he said. 

“Both programs are beneficial; I do think both approaches are going to be necessary in order to grow the market,” Torres said.

Residential and commercial buildings are responsible for about 24% of California’s greenhouse gas emissions, according to state agencies. McAllister said about 80% of a non-electrified home’s emissions come from water and space heating. 

“Heat pumps have so many upsides,” McAllister said. “Eventually it will be a good sell, but we have to work through market barriers.” He said that’s something California has done before for solar and other technologies. 

Streamlining Installation

Other efforts to increase heat pump adoption are focused at the local level to make installations easier. 

“There’s not a lot of training and knowledge on how to safely install heat pumps compared to gas equipment,” said panelist Sam Fishman, with the San Francisco Bay Area Planning and Urban Research Association (SPUR). 

Fishman said cities often require applicants for a heat pump installation to complete the same steps as for a gas appliance installation, even though some steps may not be necessary. Heat pumps face additional planning checks, such as extra site plans and line diagrams, he said, and planning rules often restrict where heat pumps may be installed. 

SPUR also is working with the Panel Optimization Work and Electrical Reassessments (POWER) group, convened by Build It Green, to find ways around the need for electrical infrastructure upgrades for a heat pump installation. 

Solutions might include technology to avoid coincident load, such as a device to switch off an EV charger so it’s not running at the same time as a heat pump washer and dryer. 

Panelist Therese Peffer, a researcher at the University of California, Berkeley, gave an update on the Oakland Eco Block research project, which is using economies of scale to electrify an entire block of homes in Oakland rather than working on one home at a time. 

The project includes installation of electric appliances, efficiency upgrades such as insulation, and co-owned solar for the homes. The CEC largely has funded the project, which is wrapping up work on the homes and entering an analysis phase. 

The project did result in economies of scale, Peffer said. 

“Bulk purchases of appliances [were] a big deal,” she said. “Or even just getting a contractor to come out and bid on eight roofs instead of one was a big deal.” 

And if a contractor finished work on one home midday, they could get started on another home right away rather than sending workers home for the day. 

Another question was how much the “neighbor effect” would come into play, Peffer said, referring to observations that solar and EV adoption seem to be contagious in a neighborhood. The same seemed to be true in the Eco Block project for heat pump adoption, she said, even if the appliances are less visible. 

Blueprint Released

The building decarbonization discussion came just weeks after the California Heat Pump Partnership released a blueprint aimed at accelerating heat pump adoption in the state. 

The partnership, which launched in May 2024, is a public-private coalition consisting of state agencies, manufacturers, utilities and others. The group’s objective is to help the state meet Gov. Gavin Newsom’s goal of installing 6 million heat pumps by 2030. 

Among the strategies in the blueprint are improving heat pumps’ value proposition through stable incentives, expanded financing options and electrification-friendly rates. Workforce training opportunities should be expanded along with contractor support, the blueprint states. 

The blueprint also recommends a two-pronged marketing campaign focused on consumers and contractors and promotion of the electric appliances through a Heat Pump Week. 

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Ohio Governor Signs Utility Law Aimed at Enhancing Competitive Market

Ohio Gov. Mike DeWine signed House Bill 15 into law, eliminating the use of “electric security plans” (ESPs) for the state’s utilities and requiring them to rely on market forces to maintain adequate generation.

“EPSA applauds Ohio policymakers for enacting Substitute HB 15 — legislation that sends a clear message: Ohio is open for business,” Electric Power Supply Association CEO Todd Snitchler said in a statement May 15. “By shifting financial risk away from captive ratepayers and enhancing transparency, this bill further enhances a competitive energy market that benefits consumers and attracts investment.”

Competitive markets lower costs and emissions without sacrificing reliability, Snitchler argued. The law provides a strong model for other states to attract the needed investment to meet higher demand from artificial intelligence, data centers and advanced manufacturing.

“This shouldn’t be viewed as just an Ohio win; it’s a roadmap for energy policy across the country,” Snitchler said. “Ohio chose competition, accountability and innovation, without subsidies to specific types of resources.”

The law passed out of the Legislature on April 30 with unanimous approval by the state Senate and by a 94-2 vote in the House of Representatives.

Ohio law previously gave utilities two options to establish their standard service offer (SSO) rates: an ESP that covered several years, or a market rate offer (MRO). ESPs have been used widely since a 2008 law allowed them. In addition to EPSA, the Office of the Ohio Consumers’ Counsel supported their elimination.

“The legislation restores the General Assembly’s vision in 1999 to deregulate power plants to bring the benefits of electric competition to Ohio utility consumers,” Consumers’ Counsel Maureen Willis testified earlier this year as the law moved through committee. “That vision was impaired by the 2008 energy law, when so-called electric security plans were created with their increased involvement of government regulators.”

The ESP will be eliminated fully once currently effective plans expire. The law requires utilities to switch to the MRO to establish SSO rates for customers who do not shop for competitive suppliers.

About 40% of the state’s customers still get default service from the utilities under the SSO, but they represent less than 20% of the state’s load, according to statistics from the Public Utilities Commission of Ohio. The new law requires PUCO to ensure that any MRO does not have an adverse effect on large-scale governmental aggregation, which allows municipalities and counties to combine their residents’ power demand and purchase supply at bulk for them.

The law also bans utilities from creating competitive retailers of their own, which is something of a fait accompli, as regulated utilities in Ohio and beyond have spun off their competitive operations over the past decade. It also changes the definition of an electric delivery utility to specifically say they cannot own generation.

Another part of the law repeals utilities’ ability to recover costs associated with the Ohio Valley Electric Corp., which was set up as a joint venture in the early 1950s to own coal plants to supply a uranium enrichment facility that long since has shut down. That part of the legislation was championed by Rep. Sean Patrick Brennan (D), who said in a statement after it passed that it had been one of his goals since joining the House in 2023.

“The inclusion of my proposal that will save Ohioans hundreds of millions of dollars is an overwhelming accomplishment that many said would never get done,” Brennan said. “Protecting Ohio’s electric customers should be a goal of all public servants. To that end, I am happy about the bipartisan support for my proposal and the bill.”

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ACORE Panelists Call for ‘New Era’ in Energy Policy

A “new era of thinking” is needed to respond to the rising level of reliability risk facing grid operators, former FERC Chair Neil Chatterjee said in a webinar hosted by the American Council on Renewable Energy about the summer reliability landscape.

Chatterjee — now chief government affairs officer at climate technology developer Palmetto — was joined on the May 15 panel by Karen Onaran, CEO of the Electricity Consumers Resource Council; Devin Hartman, a senior fellow at R Street; and NERC Senior Engineer Stephen Coterillo, who shared details on the ERO’s recently released 2025 Summer Reliability Assessment. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.)

The SRA, published the day before the webinar, showed multiple regions at “elevated” risk of energy shortfalls, meaning operating reserves should be adequate for normal operations but could be insufficient in above-normal conditions. Areas of elevated risk followed a line down the center of the continent touching MRO-SaskPower, MISO, MRO-SPP and ERCOT, along with NPCC-New England and WECC-Mexico in Baja California.

Reacting to the assessment’s warnings about the difficulty of meeting rising demand with resources like wind and solar power that provide “less flexibility and more variability,” Chatterjee acknowledged the electric reliability environment has changed significantly since his time on the commission, a phenomenon with which grid stakeholders still are coming to terms.

“I was quite fortunate during my tenure [at FERC] that we had relatively flat demand,” Chatterjee said. “I think what these reports are showing [is] that we are entering a new period here. … We’ve got to figure out how we meet this coming surge in demand while maintaining reliability and affordability.”

One of the “unfortunate” consequences of the era of relatively flat demand, Chatterjee continued, was “that solutions on the energy side started to become politicized,” with the political left associated with renewable energy and the right connected to traditional fossil fuel generation. He said the changing reliability landscape could “upend” this viewpoint, forcing both left and right to drop ingrained attitudes and welcome “every available electron” to meet the rising energy needs of artificial intelligence, vehicle electrification and other advancing technologies.

Onaran agreed with Chatterjee on “the need to depoliticize energy.” She referred to the SRA as the latest in a long line of reliability assessments that showed “we’re on the razor’s edge” with regard to managing increasingly impactful extreme weather events.

While there are long-term solutions that Onaran said regulators should pursue to address these issues, such as streamlining the approval process for transmission projects and interconnection requests, she also urged utilities to look at more immediate steps.

“If everything goes great and we all have sunny, 70-degree days all summer, we’re golden. But we know that that’s not going to happen, and that doesn’t happen in all regions,” Onaran said. “So, what can we do in the short term to make sure that we’re meeting … these edge experiences where we’re seeing either higher demand, or the weather’s not cooperating?”

Drawing on her experience working with large industrial consumers, Onaran suggested one positive short-term change would be to improve load forecasts so customers can know more confidently how much demand to expect. This would prevent underbuilding, leading to energy shortfalls or requiring imports, and overbuilding, which could cause unnecessary expenses to ratepayers.

Responding to Onaran, Hartman acknowledged the urgency of the near future but emphasized that utilities and regulators must not take their minds off the long term.

“We in the industry always have these … seasonal discussions about [how] things are looking in the months ahead,” Hartman said. “The truth is, the way that this industry moves at the policy level and the way investment decisions or changes in the system are made, it typically takes years to get changes made, and then years before the affected industry can respond to [them]. So, it’s always important to be looking for the long-term reliability trends and getting the apparatus correctly calibrated to expected conditions down the road.”

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FERC Summer Assessment Shows Risks from Growing Demand, Extreme Weather

FERC’s annual Summer Assessment shows rising demand and shrinking reserve margins as new supply has been slow to come online. 

That situation has been well known for over a year, but this summer forecasters expect higher-than-normal temperatures, and it could be exacerbated by extreme weather, according to the assessment. 

“The increase in demand doubled from 2024 to what you’re projecting for this summer, and that is largely data center growth,” FERC Chair Mark Christie said May 15 at the commission’s open meeting, where the assessment was unveiled. “So, on the demand side, you’ve got increases. They’re pretty amazing, but we continue to lose dispatchable generation, predominantly coal and gas, and it’s being replaced with inverter-based resources, which don’t have the same characteristics.” 

The summer assessment is based partly on some of the same information that NERC used in its own reliability assessment released the same week, which identified ERCOT, ISO-NE, MISO and SPP as facing elevated risks of outages under extreme conditions. (See related story, NERC Warns Summer Shortfalls Possible in Multiple Regions.) 

Christie noted that PJM said it could have to resort to emergency conditions this summer if the region faces extreme heat that could lead to a new peak demand record there. He asked NERC why it did not also place it at an elevated level of risk. (See “Summer Outlook Finds Possible Reserve Shortage,” PJM OC Briefs: May 8, 2025.) 

“We agree that the risk under extreme conditions in PJM is present,” NERC Manager of Reliability Assessments Mark Olson said at the open meeting. “The criteria that we apply to elevated risk looks at the once-per-decade type of scenarios and low-risk scenarios. And what we noted is that PJM is preparing to call on demand response, which is part of our assessment as well.” 

It would take a combination of extreme weather and major resource outages to lead to shortages in PJM this summer, he added. 

Relying on DR seemed risky to Christie, who said at a press conference after the meeting that when PJM was hit by Winter Storm Elliott over Christmas in December 2022, just one-fourth of DR called on actually showed up. The resource can be critical when the fleet is running full and demand is high, but Christie argued it was not a replacement for generation. 

“You don’t plan a resource mix to say, ‘Well, let’s just plan on having an emergency and use emergency measures because of the reliability aspect to it,’” he added. 

Regardless of whether PJM needs to dip into DR to maintain reliability this summer, Christie noted the region faces long-term resource adequacy issues. Those have led to higher prices and significant criticism from many of its states’ political leaders. 

The RTO is seeing a changeover in its leadership, with CEO Manu Asthana set to leave at the end of the year and stakeholders recently voting out two board members, including the chair. (See related story, PJM Stakeholders Reaffirm Board Election Results.) 

“A lot of that criticism is misplaced,” Christie said. “A lot of the problems in the PJM zone are the result of state policies, and PJM is being blamed unfairly.” 

FERC cannot overrule stakeholders’ board elections, though Christie said PJM could have better governance that gives a more prominent role to states. He noted that FERC will cover PJM’s capacity market at a technical conference on resource adequacy in early June, but he also said the RTO’s leaders were doing “their best.” 

While PJM was a major topic of discussion at the open meeting, the assessment covers the entire country, and it said that broad swaths of the West as well as Texas and Oklahoma face elevated fire risk this year. 

“Long-range forecasts for above-average temperatures and below-average precipitation in much of the Western and Central United States may result in higher wildfire risks in the affected regions over the course of the summer,” it says. 

The elevated risk of fires could lead to public safety power shutoffs as utilities seek to avoid the massive liabilities associated with starting one. And if fires do start, they can lead to damaged transmission equipment and other outages. 

Drought conditions extend over 37% of the U.S., well beyond the areas at risk for fire, and that is expected to grow this summer when temperatures rise. Drought risks curtailing power plant operations, as they can be short of water for cooling, leading to derates or, more rarely, forced outages, the assessment says. 

The assessment came a week before the National Oceanic and Atmospheric Administration’s official hurricane outlook, but one from Colorado State University forecasts an active season with 17 named storms and nine hurricanes, four of which are expected to be major. That amounts to 25% more activity than a normal season, according to the assessment. 

“What struck me is the hotter temperatures, the limited water resources, the elevated risks of wildfire, hurricanes and other extreme weather events — they all show up in this report,” Commissioner Judy Chang said during the open meeting. “And these trends are only getting worse. … We keep using the word[s] ‘uncertainty’ and ‘increased uncertainty’ in these reports; I would say there’s actually an increase of certainty that this is actually the pattern that we’re seeing more and more.” 

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BPA Exempted from Federal Staffing Cuts, Hairston Says

The Bonneville Power Administration will not see further staffing cuts, CEO John Hairston said during the agency’s quarterly business review May 15, adding that he hopes to strengthen the workforce when the government lifts federal hiring freezes.

Hairston pointed to a House Appropriations subcommittee hearing on May 7 in which U.S. Department of Energy Secretary Chris Wright said BPA will not undergo more staffing cuts as part of President Trump’s quest to slim down the federal government. BPA’s federal workforce now stands at around 3,150 employees, according to Hairston. (See Wright Defends DOE Budget at House Appropriations Subcommittee.)

“BPA has been exempted from DOE’s reduction-in-force plans based on the key role BPA plays in public safety and in achieving the department’s vision for reliable, affordable and more abundant energy resources,” Hairston said. “For those same reasons, BPA’s workforce was not eligible for the latest deferred resignation program that DOE offered in April.”

Despite BPA’s status as a self-funding federal agency, its staff in January received a “deferred resignation” buyout offer from Trump’s unofficial Department of Government Efficiency, immediately setting off alarms in the electricity sector about the impact on the region’s grid reliability. (See BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms.)

About 200 agency employees — or 6% of the workforce — accepted the buyout offer, while 90 job offers had been rescinded following a federal hiring freeze announced Jan. 20, according to BPA.

The DOE later allowed BPA to reinstate 89 “probationary” employees.

“We are prioritizing our resources to address our most urgent priorities, and I’m hopeful that we’ll be able to strengthen our workforce when hiring restrictions are lifted,” Hairston said.

Despite workforce challenges, BPA energized two transmission projects in the second quarter: the Longhorn substation in north-central Oregon, which will enable approximately 2,500 MW of generator interconnections, and the 18-mile Midway-to-Ashe 230-kV transmission line in southeastern Washington.

Planning ‘Reforms’

Hairston also provided updates on the agency’s transmission planning changes. BPA issued a pause in February to consider new “reforms” in light of “exponential growth” of transmission service requests (TSRs). BPA’s 2025 transmission cluster study includes over 65 GW of TSRs, compared with 5.9 GW in the 2021 study. The requests exceed the total regional load projected for the Pacific Northwest in 2034, according to the agency.

“Our current processes were not designed to handle this volume, so we are seeking reforms that will allow us to move projects forward more quickly and strengthen the grid,” Hairston said. “Now I’ve asked our team to think creatively and innovate solutions, even if it means disrupting the status quo. A disruptive solution may be what’s needed to achieve my vision, which is to drastically reduce the time from transmission request to transmission service.”

Hairston said he wants to reduce the time from transmission request to service to five to six years, calling his goal “a big ask.”

“But I believe we have the right team for the job,” Hairston said. “They have my full confidence, and I’m going to do everything in my power to make sure they have the resources they need to get the job done.”

The agency is finalizing its provider-of-choice process. BPA aims to have contract offers ready beginning in late August and have them all signed by the end of 2025, Hairston said.

Hairston also commented on BPA’s day-ahead market policy issued May 9. In a much-anticipated decision, the agency selected SPP’s Markets+ as its day-ahead market choice. (See BPA Chooses Markets+ over EDAM.)

“There’s a lot more work to do before we can officially join Markets+, but we are on the right path to delivering more value for the region,” according to Hairston.

Improved Outlook

The agency’s new chief financial officer, Tom McDonald, also provided a financial update during the May 15 call.

BPA’s net revenue for the second quarter is $210 million compared with the agency’s target of $70 million. Net revenues have increased since the first quarter, McDonald said. (See BPA Committed to Trump’s Energy Goals, Hairston Says.)

McDonald said the forecast for the second quarter is based on information at the end of March 2025 and does not reflect the full impact of Trump’s executive orders on BPA.

“We’re certainly happy for the improved outlook but remain mindful that there is still the potential for significant volatility for the remainder of the year,” he added.