RTO Insider

January 29, 2026January 29, 2026

IESO Holds Firm on Hydro Exclusion, Reserve Price in Long Lead-time RFP

IESO officials held firm on excluding hydro redevelopment projects from the ISO’s Long Lead-Time (LLT) procurement despite objections from potential bidders at a Jan. 28 engagement session.

Officials also attempted to assuage concerns about the use of confidential reserve prices to control costs.

The ISO created the LLT procurement for resources that require longer planning cycles than the four-year lead times in the pending Long Term 2 (LT2) procurement. IESO plans to seek 600 to 800 MW of capacity from storage resources and up to 1 TWh of energy from hydro resources requiring at least five years of lead time. (See IESO Drops Termination Option for Long Lead-time RFP.)

The energy stream of the LLT request for proposals will be open to new-build hydroelectric facilities with a nameplate capacity of at least 1 MW that do not include pumped storage. The ISO said it will not permit bids from hydro redevelopment or expansion projects, despite proponents’ claims that such additions may also require longer design and construction cycles.

Stephane Boyer, of FirstLight Power, said he did not understand the ISO’s rationale for excluding hydro expansions, which he said would be unable to compete against wind and solar projects in IESO’s long-term procurements.

“Why not give the opportunity to bid in [and] get the most cost-competitive hydro you can get in the earlier window that is currently open?” he asked.

IESO officials said hydro expansions and redevelopments should seek 20-year contracts under the upcoming LT2 procurement because they can be developed in less than five years and don’t require the 40-year contracts in the LLT solicitation.

Boyer and Paul Norris, president of the Ontario Waterpower Association, said ratepayers would benefit from the longer contract terms. “We’re artificially eliminating … the participation of some hydro projects in the ISO procurements because they take longer than five years and they’re not greenfield,” Norris said.

John Wynsma, formerly of Peterborough Utilities, said that between 2008 and 2016, the company built one new hydro project while completing one expansion and one redevelopment, each of which took more than five years.

“The new-build was the cheapest of the three, and that’s because of logistics: It’s a clean site,” he said. “The redevelopment cost 40% more than the new-build. The expansion cost more than 50% more than the new-build.”

He suggested IESO allow redevelopments and expansions to submit prices for 20-, 30- and 40-year contracts in the LLT solicitation, with the ISO choosing any it finds attractive. “I think you’re missing an opportunity here,” he said.

IESO’s Ben Weir said ISO officials are still deciding how they will treat hydro redevelopments under LT2. “It’s a bigger piece of work that’s just not going to be done by the time that LLT has to launch,” he said.

“We do want to get a terawatt-hour worth of energy out of new-build hydro facilities in the province,” he continued. “I understand that the timelines for LT2 have not been made public yet, but we do expect to make those public at the end of an engagement in February.

“Whether or not those expansions are going to take five years is a site-specific question,” Weir added. “When we’re talking about upgrades and expansions to existing facility, it’s our position that a 40-year contract … shouldn’t be required in order to recover the investment that’s being made.”

On Jan. 29, IESO held an engagement on its Northern Hydro Program (NHP), which will allow existing hydro facilities of at least 10 MW to win new 20-year contracts. NHP will begin accepting applications on March 31.

Concern over Reserve Prices

Boyer also raised concerns over IESO’s plan to use reserve prices — a confidential price threshold — to ensure it doesn’t pay too much in the LLT solicitation. The ISO said the thresholds will be based in part on prices in the first window of the LT2 procurement and differences in the obligations of LT2 and LLT resources.

Boyer said LT2 “is for different technology with different attributes, which is very different from the baseload hydro that you’re looking at now to procure.”

The reserve price and limited guidance over interconnection timelines is requiring bidders to make “a lot of investment … with a lot of unknowns and uncertainties,” Boyer said.

Weir said the ISO will adjust the reserve price to acknowledge the differences between the LLT and LT2 procurements. “In no way, shape or form is it just the LT2 price,” he said.

‘Buy Local’ Provisions not Final

ISO officials said they hope to complete the LLT RFP and contract by the end of the first quarter — with the bidding commencing in the fourth quarter — but are still waiting for the Ministry of Energy and Mines’ directive on how to apply “buy local” requirements.

Bidders will be required to provide a “local supply plan” identifying their major goods, services and workforce suppliers, an attestation that the proponent plans to source at least 50% from Ontario or other Canadian provinces, and an explanation for what cannot be obtained domestically.

“The feedback that we’re seeking is whether proponents were already planning to source at least 50% of the project spend from Ontario or Canada,” Weir said. “If they weren’t planning on doing that — but could, because there are domestic sources of those good services and workforce — what the cost implications would be to bring that level up to 50%.”

Team Experience

The ISO also rejected requests that it allow proponents’ consultants to help them meet the RFP’s experience requirements.

All bidders will be required to have at least two team members with experience in planning, developing, financing, constructing and operating at least one “qualifying project” — an electric generation or storage facility that has reached commercial operation in the last 15 years in Canada or the U.S.

Proponents of Class II long-duration energy storage (LDES) technologies will be required to have at least two team members with experience on a project of the same technology (at least 1 MW) expected to reach commercial operation by the end of 2029.

IESO said consultants cannot count toward experience requirements because “they may not be enduring members of the project team” and could leave before the project reaches commercial operation.

Tariff Protections

Stakeholders also contended that the ISO should not have absolute discretion to cancel a contract if a developer seeks additional payments to compensate for tariff changes imposed after the deal is signed.

The ISO said developers should only submit tariff adjustment notices if the price change is “absolutely critical to maintain [the] viability” of the project “and should not be used … as a negotiating mechanism.”

Other Issues

In other developments, IESO said it is:

- updating resource eligibility rules for storage to require that the instantaneous maximum withdrawal capability of the facility be equal to or greater than the project’s nameplate capacity. For example, a 200-MW nameplate project must be able to withdraw 200 MW during its charging cycle.
- removing a requirement for obtaining municipal support confirmations by Aug. 21.
- seeking feedback on how to define hydro project sites to reflect impacts on adjacent properties, such as lands that may be flooded.
- adjusting its compensation formula to protect hydro suppliers’ revenues during droughts that reduce production. IESO’s Jasdeep Kahlon called it a “tradeoff” that will also reduce hydro projects’ revenue “upside.”

Stakeholder feedback on the Jan. 28 session is due Feb. 12.

January 29, 2026January 29, 2026

Grid Weathers Latest Winter Storm but Still Faces Gas Coordination Problems

The North American grid made it through the winter storm of Jan. 24-26 — dubbed “Fern” by The Weather Channel — relatively unscathed, but the cold weather gripping much of the U.S. and Canada continues, and cold snaps in the future will still stress the interconnected power and natural gas systems.

The industry mobilized ahead of the storm, sending out more than 65,000 workers from 44 states to start damage assessments and repairs as soon as possible, according to a news release from the American Public Power Association, Edison Electric Institute and the National Rural Electric Cooperative Association. As of 9 a.m. Jan. 29, 750,000 customers have had their power restored, but work continues, especially in areas that saw an inch or more of ice accumulation.

“This unified effort includes close coordination with federal, state and local officials who share the goal of safely restoring power as quickly as possible,” EEI CEO Drew Maloney said. “The massive mutual assistance mobilization has ensured we have enough workers in place, with crews shared across the region and reassigned to the next priority as soon as they wrap up work.”

The Electricity Subsector Coordinating Council has held three calls to coordinate the response between the industry and federal government.

“Thanks to the work of our industry partners, mutual assistance crews are restoring power as quickly and safely as possible across the country,” Deputy Energy Secretary James Danly said in a statement. “Since Winter Storm Fern began on Jan. 24, the department has issued eight emergency orders to stabilize the electric grid across impacted regions; the department is using all of the available tools at our disposal to mitigate power outages and save lives.”

While the industry wraps up work connecting customers who lost power because of distribution outages and faces some ongoing cold in the coming days, winter reliability will continue to be an issue for the foreseeable future, experts said during a webinar hosted by R Street Institute on Jan. 29.

The biggest risk to bulk power system reliability in the coming years is whether the industry can respond to growing demand from data centers and other sources, but recently retired ISO-NE CEO Gordon van Welie listed the gas-electric issue as a close second.

“The biggest secondary factor is this mismatch between planning and paying for the gas system and the electric system, and the mismatch between the reliability standards for these two systems and the lack of recognition that the gas and electric systems have become one interdependent energy system,” van Welie said. “And we’re still regulating these systems as if they exist in independent silos.”

Winter reliability depends on weatherizing equipment and ensuring adequate fuel during cold snaps, which require strong performance incentives in the wholesale markets, investment in the required fuel infrastructure and some way to recover those costs, he added.

After Winter Storm Uri in February 2021, FERC and NERC made significant improvements to the point where that is “largely solved,” van Welie said. The two industries have also worked to improve information sharing, but that has provided only incremental gains, he said.

The real need is for more infrastructure, van Welie argued. But while the two systems have become increasingly interdependent, they are regulated differently.

“The restructuring took different paths with different economic structures for cost recovery,” van Welie said. “And the consequence now, since they’ve become interdependent, is this total mismatch in terms of cost recovery for the underlying network, so I’m not talking about production here of gas, but the networks for delivering the gas.”

Inadequate gas infrastructure can lead to unreliable electricity supply, which compromises all aspects of the economy, including the ability to deliver gas to heat homes during cold snaps. After Uri, van Welie asked RTO staff to work with electric utilities and local distribution companies to estimate how the system in the Northeast would handle similar outages as seen in Texas.

“The biggest alarm bell came from the gas LDCs, who said, ‘There’s no way we can tolerate rotating feed outages, because what we’ll end up doing is a flameout,’” van Welie said. “‘We’ll end up with a flameout on the gas system. It’ll take us weeks to restore the gas system.’”

That nearly happened during the cold snap over the holidays in 2022 to Consolidated Edison’s LDC serving New York City. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.)

“I fear we’re going to need another 2003 event to really move the needle on this issue,” van Welie said.

The Northeast blackout in 2003 gave Congress the impetus to create a mandatory reliability system for the grid with the Energy Policy Act of 2005. Van Welie said the same kind of shock could force it to finally better align the gas and electric systems.

New England has been facing gas-electric coordination issues for more than two decades, but as Electric Power Supply Association CEO Todd Snitchler recalled on the webinar, it has been a focus at FERC since at least 2011.

“Well, that was 15 years ago, and we still haven’t solved it,” he added. “I do think we’ve made progress, and I’m happy to say that that’s been the case.”

The current cold snap is affecting a wide swath of the country, and so far, those improvements have borne fruit, with the two industries working well together, Snitchler said.

“I think the information sharing has improved dramatically,” he added. “I think the ability for the RTOs to interact with the gas system and with the power system and speak more common language has improved fairly significantly.”

Getting more infrastructure built would help, but Snitchler said cost recovery is an important issue.

“Markets treat cost recovery differently. Independent market monitors have different views about what’s eligible for cost recovery and what can be bid into the system,” he said. “And I think those questions are yet to be fully resolved in a way that helps to mitigate the volatility and stressful conditions but ensures, ultimately, that reliable system.”

Even outside of the issues in winter, the need to meet data center demand is going to require additional gas pipelines — and electric transmission lines, he added.

Uri hit Texas worse than anywhere else, as ERCOT suffered major outages exacerbated by gas-electric coordination issues, and led to hundreds of deaths. ERCOT’s former Independent Market Monitor and R Street Fellow Beth Garza noted that the gas-electric issues are different in Texas because of the lack of restructuring on the gas side.

“In Texas, the majority of natural gas-powered generation is supplied by intrastate pipelines [that] aren’t required to have the same kind of unbundling and restructuring that has happened in the rest of the country,” Garza said. “I would just point folks to the aftermath of Uri. Look at the profits that Energy Transfer; look at their profits of billions during that event, versus the loss of the largest generator in Texas, Vistra, which were also in the billions. And that, to me, tells a story.”

The oil and gas industry is politically powerful in Texas, and it has not been restructured at all, which is the opposite of what has happened in ERCOT’s electricity market, she added. The biggest thing aimed directly at winter reliability since Uri was that generators started getting paid to keep oil stored on-site at dual-fuel units, but Garza sees a bigger need for stored fuel.

“There needs to be an investment in gas storage,” she added. “It’s not just pipelines. It’s the ability to withstand, particularly in the wintertime, the production decreases that are going to happen because of the cold weather.”

One state that has done well with gas-electric coordination issues is Florida, which has the highest percentage of gas generation and is at the end of the pipeline network like New England, NERC Director of Reliability Assessments John Moura said.

“They build the gas pipeline for the generators,” Moura said. “They’re high-pressure contracts. They have a mandate to have oil backup because there’s a good amount of generation, 16,000 MW, that is south of any other pipeline options —kind of a single contingency there, so there’s dual fuel. So, they’ve done things, worked it into their integrated resource plans, not the markets. But I think there’s things to learn from the signals that they’re putting in them.”

January 29, 2026

Stakeholders Say MISO’s Nonpublic Extreme Events Study Merits Closer Look

Some MISO stakeholders said an extreme events analysis from the 2025 transmission planning cycle potentially raises a red flag and deserves more attention.

MISO found the possibility for cascading outages in all four of its planning regions in its annual extreme events analysis for its 2025 Transmission Expansion Plan (MTEP 25). The grid operator said its South region contains the most potential for cascading, extreme contingencies.

MISO completed the analysis in late 2025. The analysis contemplates several failures, including loss of large generators, transmission elements, load centers and failures brought on by hurricanes, wildfires, cyberattacks and other catastrophes.

However, there’s not much to glean beyond that. Results are shielded from the public in the confidential appendices of the annual MTEP report and protected by nondisclosure agreement requirements and a Critical Energy/Electric Infrastructure Information designation.

Sustainable FERC Project’s Natalie McIntire asked where stakeholders can go to view a list of transmission solution ideas or remedial action schemes that might be designed because of the findings.

Clean Grid Alliance’s David Sapper seconded the ask. He said 2025’s “concerning results” warrant more discussion, not simply an agenda item without a presentation from MISO staff.

MISO published the analysis results in a “post-only” format without dedicated discussion time at a Jan. 28 Planning Subcommittee meeting.

“‘It is what it is’ suggests too much indifference,” Sapper said at the meeting.

Minnesota Power’s Tom Butz asked if the extreme events analysis findings could be discussed in MISO’s Resource Adequacy Subcommittee.

Butz said the analysis seems to deserve a larger conversation on “system reliability, not just a localized version of reliability” for transmission owners.

“It seems like this is a source for this to come from,” Butz said of a discussion on how to tackle some cascading failures. He said MISO should “connect the dots between the two worlds,” meaning local planning versus regional preparation.

“We’d be more than willing to have more conversations,” MISO engineer Scott Goodwin said.

But Goodwin reminded stakeholders that loss of load is at times an acceptable form of mitigation, according to MISO’s planning standards.

Planning Subcommittee Chair Patrick Jehring, of GridLiance, said he understands the “difficulty” of trying to publish findings while working around privileged information.

“What we heard today is kind of lacking. … It doesn’t really help drive a conversation about ‘what do we do about this?’ What can you show to form a discussion about these extreme events?” Jehring asked MISO staff.

Senior Expansion Planning Engineer Amanda Schiro said she would evaluate what insights MISO might be able to share.

McIntire said MISO might consider sharing aggregated data or “themes of analysis.”

January 29, 2026

Almost 9 GW of Calif. Renewables Delayed by Slowed Transmission Buildout

California continues to add in-state renewable energy resources, but the transmission upgrades needed to bring those projects online have been lagging behind, according to the California Public Utilities Commission.

About 8.9 GW of renewable and storage resources are expected to be delayed due to transmission delays in the Pacific Gas and Electric (PG&E) and Southern California Edison (SCE) territories, Edmund Dale, CPUC senior regulatory analyst, said at CAISO’s Jan. 28 transmission development forum.

The 8.9 GW represents about 22% of the total 40.5 GW of new renewable generation and storage resources that have signed interconnection agreements in the PG&E and SCE areas.

For PG&E, about 2.5 GW of these resources are delayed due to “bundling dependencies,” which are chain reactions of transmission project delays, Dale said. PG&E said the interconnection customers are responsible for resolving the transmission delays, he said.

One critical delayed transmission project in PG&E’s territory is the Vaca-Dixon Substation 230-kV circuit breakers 442, 452 and 462 project. About 450 MW of new capacity is delayed due to this project’s lag, with an additional 900 MW at risk.

Material problems are a primary cause of transmission delays, with a supply chain issue resulting in an 11-month delay on PG&E’s Gates 230-kV Reactors Bus E-F transmission project, affecting 2 GW of resources. To address the delays, PG&E will shift material from another project to the Gates project, Dale said.

Financing and project redesign delays could also significantly affect renewable and storage resource projects in PG&E’s territory, Dale added.

In SCE’s territory, long lead-time materials, such as circuit breakers, transformers and specialized steel structures, are forecast to delay 4.5 GW of new resources, with an additional 2 GW of resources at risk of delay.

To alleviate some of these delays, participating transmission owners (PTOs) should consider allocating more time and other resources to determining more realistic in-service dates and project costs, Dale said.

CAISO is in frequent and close coordination with the CPUC and the transmission owners about transmission project delays, CAISO spokesperson Jayme Ackemann told RTO Insider.

“Delays do not typically result in changes to the transmission studies or approvals, per se, but such delays are considered in the generator interconnection and deliverability allocation processes,” she said.

The ISO does not anticipate impacts to available resources in EDAM, Ackemann added.

Transmission project delays are now tracked per the requirements of California Senate Bill 1174, passed in 2022. The law requires transmission facility owners to submit a report to the CPUC that shows changes to previously reported in-service dates of transmission and interconnection facilities that are necessary to provide transmission service to certain renewable or energy storage resources.

In November 2025, the CPUC detailed transmission delays in an annual report. It showed 449 delayed transmission projects with associated renewable generation or storage resources.

San Diego Gas & Electric (SDG&E) said it did not have any delayed transmission projects with associated renewable and storage projects.

CPUC staff reviewed SDG&E’s data and “determined it to be incomplete and inaccurate” and requested updated corrections to SB 1174 data from SDG&E, which SDG&E provided, the report says. However, CPUC staff determined that the updated data was “still not sufficient” because SDG&E did not provide data for its in-development transmission projects and provided incorrect original in-service dates, the report says.

January 28, 2026January 29, 2026

Senate Hearing Shows Support, Potential Pitfalls for Permitting Legislation

Bipartisan leaders of the Senate Environment and Public Works Committee want to pass energy infrastructure permitting legislation, but a Jan. 28 hearing on the subject showed how that might not happen during this Congress.

Senators, including EPW Ranking Member Sheldon Whitehouse (D-R.I.) and leaders from the Energy and Natural Resources Committee, have been working on potential legislation for the past year, but are trailing House colleagues who passed a bill late in 2025 that would alter the National Environmental Policy Act to speed up permitting. (See House Passes SPEED Act to Quicken Infrastructure Permitting.)

“I’d like to begin by thanking my colleagues who are here with me, and in particular, Ranking Member Whitehouse, for their drive to elevate problems in our current permitting regime and to work constructively together,” EPW Chair Shelley Moore Capito (R-W.Va.) said at the start of the hearing. “That’s what we need to do.”

“It’s the never-ending story on permitting, but we’re going to get into that story — I hope,” Moore Capito said.

Any bill needs to be bipartisan to be durable, she said before Whitehouse made his opening remarks, saying he shared that goal but thinks there is a “trust problem” with the Trump administration. He cited the president’s executive orders that temporarily stopped the Empire offshore wind project.

“This all stank, but I remained willing to work on a permitting bill,” Whitehouse said. “In August, stop-work Trump struck again against Revolution Wind off Rhode Island, a project over 80% complete with $4 billion invested, based on supposed national security concerns. That order was instantly thrown out in court as arbitrary and capricious, in part because the Trump administration had been making the opposite arguments about that same project in the same courthouse just weeks earlier.”

Other actions against clean energy continued through 2025.

“So, Sen. Heinrich [D-N.M.] and I have paused permitting reform negotiations,” Whitehouse said. “Let me be clear: We find no fault with Senate Republicans.”

The conflict is entirely between the legislative and executive branches of the government, according to Whitehouse, who said the Trump administration’s “lawless” attacks on clean energy loom over every other industry. The executive can resuscitate the bill’s prospects if it shows it will stop putting up roadblocks to clean energy, Whitehouse said.

To submit a commentary on this topic, email forum@rtoinsider.com.

‘Essential’

The Solar Energy Industries Association is not focused on reforming NEPA, which the SPEED Act and any Senate proposal from EPW would do, because the law is rarely used in litigation against solar projects, said SEIA CEO Abigail Ross Hopper, who said “permitting is essential.”

“SEIA strongly supports these bipartisan efforts to improve the process for energy and transmission projects,” she said. “Permitting reform must begin with this basic principle: Projects that enter the federal permitting process must be allowed to move through that process in good faith and without unfair treatment based on energy source. And once a project receives a permit, that permit should be honored.”

The solar and battery developers that SEIA represents have run into issues with the Trump administration since a July 2025 Department of the Interior memo created “68 new layers of red tape” for their projects, she added. By requiring secretarial approvals on many easy decisions, it effectively amounts to a moratorium on solar.

The bureaucratic roadblocks are endangering 70 GW of solar and 42 GW of battery storage on both federal and private land,” Ross Hopper said. Together they represent 43% of all planned new capacity in the U.S.

“We all know electricity demand is rising rapidly, and without this power and the grid infrastructure to deliver it, electricity prices will continue to rise,” she said.

Sen. Ed Markey (D-Mass.) noted that the tactics being used against solar now could be wielded against the oil and gas industry in the future by a Democratic president. He entered a memo into the record from Evergreen Action laying out how to get that done.

“This administration must be forced to end its punitive treatment through clear legislative text and vocal Republican opposition to any efforts to violate the law,” Markey said.

After Markey’s turn on the mic, Sen. Cynthia Lummis (R-Wyo.) responded that previous administrations from his party had done the same kind of thing against infrastructure they disliked.

“Mr. Markey, we feel your pain. We could take your statement and where you said left — we could put right,” Lummis said. “Where you said right, we could put left. Where you said Trump, we could put Biden.”

One of the first things former President Joe Biden did when taking office in 2021 was to stop construction on the Keystone XL pipeline, she added. Markey countered that Trump has taken more such actions before Chair Moore Capito reminded him it was Lummis’ time to speak.

January 28, 2026January 29, 2026

The Maryland 2026 Midterms Energy Trilemma Blues

The way Maryland Del. Lorig Charkoudian (D) sees it, working with other Mid-Atlantic states to study the costs and benefits of withdrawing from PJM is, at this point, the only responsible thing to do.

“PJM is frustratingly slow in changing, if changing at all [and] continues ─ even in a reliability crisis of their own making ─ to double down on their love affair with fossil fuels … at a really significant cost to our ratepayers. And so, you reach a point where it’s almost irresponsible not to say, ‘What are the other options?’”

Charkoudian was speaking during a recent legislative update call hosted by the Maryland Clean Energy Center (MCEC), where she previewed a package of bills she is sponsoring during the current legislative session, including H.B. 143, calling for the state to work with neighboring PJM states to study possible alternatives.

For example, the states ─ Maryland, Delaware, New Jersey, Pennsylvania and maybe Virginia ─ could start their own RTO or use PJM’s fixed resource requirement (FRR) “to pull ourselves out of the capacity auction,” she said.

Going the FRR route would require utilities in the states to procure their own capacity, rather than relying on PJM’s increasingly expensive capacity auctions, and H.B. 143 also would require Maryland utilities to study the costs and benefits of ensuring they could provide at least 80% of their capacity.

“The idea is to explore doing more capacity procurement through bilateral contracts and then use the PJM auction” as backup, Charkoudian said in an email to Livewire.

To submit a commentary on this topic, email forum@rtoinsider.com.

The Maryland General Assembly kicked off its 2026 session Jan. 14, and as far as energy policy is concerned, Charkoudian predicts “an adventurous year … [with] a lot of moving parts.”

Like Gov. Wes Moore’s Lower Cost and Local Power Act ─ announced Jan. 27 ─ which could actually tie the state more firmly to PJM by requiring all utilities to join the RTO. The bill has yet to be formally introduced, but a one-page summary argues that having all the state’s utilities in PJM ─ including small municipal utilities that generally have lower rates than investor-owned utilities ─ would lower electric bills.

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The state’s largest utilities ─ Baltimore Gas and Electric, Pepco Maryland and Delmarva Power, all IOUs owned by Exelon ─ already are members, as is the Southern Maryland Electric Cooperative. (See below for more details about the governor’s bill.)

So, the 90-day legislative session ahead is shaping up as a case study in how states facing explosive demand growth will attempt to build more clean energy, cut electric bills and reduce greenhouse gas emissions as PJM and the Trump administration resist any change that puts more solar, wind and storage online.

Maryland aims for 100% carbon-free power by 2035 but imports 40% of its electricity from the regional grid, making it particularly dependent on PJM’s mostly fossil-fueled power and vulnerable to any swings in the RTO’s market prices. The state’s consumers already are absorbing rate increases due to PJM’s price-spiking capacity auctions, and more pain is ahead with the December auction, for 2027/28, hitting yet another record high, $333.44/MW-day, up from $28.92/MW-day in 2023.

“It’s very easy to get caught up in all the drama around energy right now,” Charkoudian said during the MCEC call. “[But} we have, for the most part, all of the tools that we need, and we need to put them together in the right policy.”

Charkoudian vs. Moore

The politics of the upcoming midterm elections also are a key factor ─ Moore and all state lawmakers are running for re-election in November ─ affecting what new energy policies can be shepherded through the legislature and reach Moore’s desk.

Both the governor and Charkoudian want to get more clean energy online in Maryland, to help wean the state off its dependence on PJM and provide support for local installers, developers and consumers in the absence of federal incentives cut off by the Republicans’ One Big Beautiful Bill Act.

The 30% federal tax credit for residential solar was terminated Dec. 31, 2025. Commercial projects still can qualify for the credit if they start construction by July 4, 2026, and are online by the end of 2027.

The one-page summary of Moore’s bill says it will “create a process for clean energy projects to apply for financing for shovel-ready projects,” which, on the face of it, could primarily benefit utility-scale projects. (Residential and smaller commercial projects are rarely described as “shovel-ready.”)

In contrast, Charkoudian’s Affordable Solar Act (H.B. 345) lays out a detailed plan for Maryland to adopt incentives similar to New Jersey’s, providing different levels of financial support for different kinds of solar ─ utility-scale, commercial, community solar and residential.

Incentives for utility-scale projects would be determined through a competitive auction, with the lowest-cost projects receiving incentives, while the state’s Public Service Commission would set the price for solar renewable energy certificates (SRECs) for residential, community solar and commercial projects under 5 MW.

The PSC would review and adjust the SREC price every three years, or more frequently if warranted by market conditions. Right now, the SREC price in New Jersey has been set at $85/MWh. Maryland SRECs are priced around $50, according to Flett Exchange, an online SREC trading platform.

New Jersey’s utility-scale auctions got off to a rocky start, with the state’s Board of Public Utilities rejecting all the bids in the first solicitation in 2023, saying they were too high. A second auction in 2024 awarded incentives to eight utility-scale projects totaling 310 MW.

Charkoudian described her proposed incentives as the “best bang for the buck from a ratepayer side, from a Maryland side. … We’re going to provide as much subsidy as is needed, but not a penny more, to each different sector of the industry.”

The bill also would make plug-in “balcony solar” legal in Maryland ─ a significant win for cutting home electric bills ─ and ensure that ratepayer dollars intended for the state’s clean energy fund cannot be used to fill holes in the state budget. Moore wants to take $292 million from the fund ─ the Strategic Energy Investment Fund (SEIF) ─ to backfill a 2027 deficit estimated at close to $1.5 billion.

ATTs and Grid Expansion

Both Moore and Charkoudian are bullish on advanced transmission technologies, which can optimize and expand capacity on existing power lines, as a cheaper, faster alternative to building new transmission.

Moore’s bill calls on utilities “to prioritize [ATTs] to expand existing grid capacity and authorize the use of state and interstate highway corridors to co-locate these projects.”

Again, Charkoudian provides a more detailed approach in H.B. 40. Utilities or other transmission owners within the state would be required to identify areas where grid congestion has occurred in the past three years, as well as where congestion may be likely to occur over the next five years, and then develop plans for using ATTs as part of any grid upgrades or expansion.

Developers seeking a certificate of public convenience and necessity for transmission projects also would have to show they’ve considered ATTs as an alternative to building a new line.

Charkoudian acknowledged that implementing the law could be tricky due to the fine line between state and federal regulation of new transmission. But she sees ATTs providing both grid efficiency and affordability.

An additional problem here is the slipperiness of legislative language. Any effort to get utilities to prioritize or consider new technologies tends to lead to highly technical arguments about why said technologies are not appropriate or feasible for any one project or situation. Compensation is another potential roadblock since upgrading wires with ATTs may be considered a maintenance cost that cannot be passed on to a utility’s customers ─ that is, in many places, ATTs cannot be rate-based.

Moore’s bill acknowledges that ATTs must be part of a bigger grid expansion strategy. The governor wants the Department of Transportation to use $10 million from the SEIF “to identify opportunities for high-voltage transmission lines and battery storage projects along state and interstate highways.”

The focus on existing rights-of-ways could be a potential vote winner for the governor in the face of the well-organized and vehement local opposition to the Maryland Piedmont Reliability Project ─ a 70-mile transmission line approved by PJM, which could run through agricultural land in the central part of the state. The fact that the project is being built by an out-of-state utility, Public Service Enterprise Group of New Jersey, has intensified community outrage.

High Bills and Data Centers

Differences between Moore and Charkoudian are more pronounced when we get to the nitty-gritty of high electric bills and data centers.

Besides taking $292 million from the SEIF to balance the budget, Moore also wants to use $100 million for direct bill rebates to “Maryland families burdened by high energy costs” ─ yet another major vote winner. Both those withdrawals will leave the fund with a balance of about $164 million, according to an analysis by Inside Climate News.

What the governor doesn’t mention is that in 2025, more than $94 million in SEIF dollars went to state programs providing bill assistance to more than 70,000 low-income families, according to the Maryland Energy Administration’s 2025 report on the fund. Projected spending for bill assistance programs in 2026 is $150 million. Whether Moore’s rebates would go to upper-income households that really do not need them is unclear.

While Moore’s bill is mum on data centers, the governor signed onto President Donald Trump’s recent proposal that PJM hold a one-time emergency auction to deliver more long-term “baseload” power for data centers across its service territory ─ wording that assumes a traditional reliance on fossil fuels and nuclear.

Charkoudian tackles the data center dilemma in in her fourth bill, which proposes multiple strategies ─ and a preference for clean energy ─ to protect consumers from paying for any new generation or power lines needed to connect these megawatt-guzzling facilities to the grid.

The bill is being finalized, but according to a fact sheet from Charkoudian’s office, the core provisions include:

- Accelerated permitting and interconnection for new data centers or other large loads that supply 100% of their power.
- A voluntary demand response program for large load customers ─ defined as any facility with a demand of 25 MW or more.
- An inventory of surplus interconnection capacity in the state, conducted by the Maryland Energy Administration. The information gathered by MEA “will be shared with large load customers who can then use this surplus interconnection to build new battery storage or other zero-emission resources to avoid having to go through the PJM queue,” according to a fact sheet on the bill.
- A requirement for all new large load customers seeking interconnection in Maryland to cover the capacity for at least 25% of their power demand with either behind-the-meter resources, storage or carbon-free power.
- A community benefit fee of $1,000/MW to be paid by any large load project applying for interconnection in Maryland. The fee would cover the cost of interconnection studies and be used to provide consumers with assistance for high utility bills and energy-efficient home upgrades.

Both Moore and Charkoudian appear to be moving in the same direction, tackling critical challenges for the state ─ in this case, how to develop a reliable, affordable electric power system with growing amounts of clean energy, an optimized, flexible grid and various pathways for data centers and other large loads to get the power they need.

Charkoudian tends to go big, ambitious and strategic on the bills she introduces, while Moore is smart, but perhaps a bit more cautious, with an eye on the election and Maryland’s mix of liberal and more conservative voters. Pressure from the White House, PJM, utilities and hyperscalers will be intense.

The challenge ahead for both will be getting their bills through a legislature that, even with a large Democratic majority, leans toward consensus, watering down more liberal bills with cuts, rewrites and amendments ─ or letting them die in committee.

In other words, the fate of clean energy, data centers and utility bills in Maryland and other PJM states will depend on the difficult, frustrating but absolutely vital process of making laws in a democratic society, with a free, independent press looking on. Thank goodness, in Maryland, we still have both.

January 28, 2026

Dragos Blames Electrum Group for Poland Grid Cyberattack

Cybersecurity firm Dragos has blamed Electrum, a threat group linked to Russia’s intelligence service, for a Dec. 29 cyberattack against Poland’s power grid that it said could be a preview of future attempts to compromise critical infrastructure.

The attack occurred Dec. 29 and 30, according to a government statement published Jan. 15, and targeted a system for managing renewable energy sources as well as two combined heat and power plants. Polish Prime Minister Donald Tusk said that “at no point was critical infrastructure threatened,” and no outages occurred as a result of the attack. However, he said, the incident showed Poland’s energy system “requires further strengthening.”

In a report published Jan. 27, Dragos said it was called in by CERT Polska, Poland’s cyber incident response team, to analyze “one of the numerous incidents across the Polish system that are part of this attack.” The firm called the event “the first major coordinated attack targeting distributed energy resources at scale” and said it can “assess with moderate confidence that … Electrum is responsible.”

Electrum is associated with Unit 74455 of Russia’s Main Directorate of the General Staff of the Armed Forces (also known as GRU). Analysts have also dubbed the unit Sandworm and Voodoo Bear, though these may be separate groups within the unit. Unit 74455 is believed to have carried out attacks around the world, including against the Ukrainian grid in 2015 and 2017. (See Six Russians Charged for Ukraine Cyberattacks.)

In its 2024 Year in Review report, Dragos called Electrum one of three active threat groups capable of reaching Stage 2 of SANS Institute’s ICS Kill Chain, meaning “a capability that can meaningfully attack” a target’s industrial control systems. (See Dragos: Attacks on ICS Increased in 2024.)

The December cyberattack targeted systems managing communication and control between grid operators and DERs, meaning both CHP facilities and systems for dispatching renewable energy, Dragos wrote. Through these tactics, the attackers were able to “gain access to operational technology systems with direct connections to generation assets.”

“Taking over these devices requires capabilities beyond simply understanding their technical flaws. It requires knowledge of their specific implementation,” the firm wrote. “The adversaries demonstrated this by successfully compromising [remote terminal units] at multiple sites, suggesting they had mapped common configurations and operational patterns to exploit systematically.”

Although communication was lost, the default behavior of the affected devices was to remain on; this is why no outage occurred. Dragos wrote that because of limited logging of network communications and commands at the affected sites, investigators have not determined whether Electrum tried to issue operational commands to the generation assets.

The firm warned that the Poland attack could indicate a change in adversaries’ tactics to target DER monitoring and control systems. Attackers gained a “foothold that could enable operational impacts, particularly when similar access is achieved across larger numbers of sites simultaneously or if adversaries develop deeper knowledge of specific site configurations.”

Historically, cyberattacks against power grids have required targeting substations or centralized systems, Dragos wrote, citing the Ukraine grid attacks in 2015 and 2016, which involved “large, centralized control points that manage significant portions of the grid.” The global shift from large generation facilities to smaller distributed facilities has opened new attack vectors, leading the firm to warn that “as your DER portfolio grows, so does the attack surface.”

Grid operators don’t just have more points of vulnerability to worry about with DERs; renewable generation facilities also lack the inertia that traditional thermal plants provide, which helps stabilize grid frequency. More than 50% of Poland’s generation fleet is coal-fired plants, Dragos observed, with wind and solar accounting for about 25% of capacity.

The firm suggested the relatively high amount of inertial generation, coupled with strong AC interconnections to neighboring countries, made the attack “unlikely to cause a nationwide blackout in Poland.” But this built-in stability is not guaranteed, the firm warned, particularly in countries pursuing aggressive decarbonization strategies.

Dragos wrote that the Poland attack “represents both continuity and evolution.” Continuity comes from the technical similarities with previous Electrum operations, including the choice of targets and the malware used. The evolution is represented by the change to target “the distributed edge of the grid,” meaning communication systems that enable the compromise of “dozens of smaller generation sites.”

Based on the attackers’ behavior, the firm judged the incident to have been opportunistic rather than “precisely planned … with specific outcomes.” Dragos wrote that Electrum seems to have “exploited whatever opportunities their access provided.” This indicates that the attackers were rushed, but the firm could not determine why.

From direct evidence and public statements, Dragos is certain of at least 12 sites that were affected, and the firm believes the actual total may be at least twice this number, representing as much as 1.2 GW if they had been operating at full capacity. Poland reported record electric consumption of 30 GW on Jan. 17, meaning that if the affected sites had gone down simultaneously and without warning, it could have had a “noticeable impact on the system frequency [of the kind that] have caused cascading failures in other electrical systems.”

The firm recommended that generation owners and operators defend their systems using the SANS Five ICS Cybersecurity Critical Controls:

- Operational technology/ICS incident response: Organizations must have a plan to prioritize restoring connectivity across dozens of sites at once, performing forensics on corrupted systems and detecting the level of control that attackers achieved.
- Defensible architecture: Companies should work to prevent adversaries using common weaknesses to easily compromise multiple sites at once.
- OT/ICS network visibility and monitoring: Distributed generation operators must ensure they have constant visibility into their systems and the ability to detect abnormal activity.
- Secure remote access: Organizations must ensure remote access is protected through multifactor authentication, automatically expiring logins and other security measures.
- Risk-based vulnerability management: Companies should be aware of vulnerabilities in distributed generation assets and enable rapid patching across all remote sites.

January 28, 2026January 29, 2026

SPP Waits on FERC Order to Refund Z2 Credits

SPP staff say they still are waiting for an order from FERC before they can begin distributing millions of dollars in compensation to transmission upgrade sponsors from its beleaguered Attachment Z2 process and unwinding billions of dollars in settlements.

The numbers are huge.

The grid operator says it owes about $147 million in refunds, plus an additional $46 million or so in interest to transmission users that made payments under the Z2 process as far back as 18 years ago. It says it also will have to unwind and recalculate more than $20 billion in market settlements dating back to 2015 to resettle that Z2 activity.

Only about 1 to 2% of the latter resettlements are related to the Z2 process, staff told stakeholders during a Jan. 26 virtual meeting.

“This will impact both network and point-to-point activities, so if you’re a transmission customer or transmission owner, you will be impacted, most likely,” said Steve Davis, SPP’s settlements manager. “It’s a large mountain that we’re chiseling away to have a smaller impact.”

That mountain has grown to Everest proportions since 2008, when SPP received FERC’s approval for its tariff attachment that awards credits to sponsors from upgrade sponsors whose service could not be provided “but for” the upgrade. The attachment also required the RTO to invoice the charges monthly and to make any adjustments within one year.

However, software problems delayed Z2’s final implementation for eight years before 2016, during which the RTO did not invoice any upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 activity from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

SPP General Counsel Paul Suskie has called the Z2 resettlement headache “the most litigated, drawn-out process we’ve ever had.”

The RTO proposed a solution to unwind credit payment obligations assessed under Z2 and made an informational filing at FERC in 2024. In September, the commission ordered the grid operator to make a compliance filing for the proposal. (See FERC Requires Additional Z2 Filing from SPP.)

SPP answered with a filing in November (ER16-1341). It also issued updated refund balances with accrued interest to entities affected by FERC’s remand.

The commission has yet to respond to that filing.

To submit a commentary on this topic, email forum@rtoinsider.com.

Asked when SPP expects to see the commission’s order, Davis said, “I wish I knew, and that’s probably the best answer we could give. We would love it to be tomorrow, but honestly, I don’t know that we have any indication from FERC.”

SPP’s Charles Locke reminded stakeholders that FERC’s initial order in the proceeding indicated SPP was not to act on the Z2 refunds “until it was specifically authorized to do so by FERC.”

Davis said whenever a favorable order comes, “We plan on hitting the ground running.”

About a month after FERC’s order, SPP will issue final invoices for the refund period. Staff then will complete and deploy an interim Z2 resettlement system and calculate and administer the revised credit payment obligations.

When that process is complete — about eight to 12 months, SPP says — resettlement invoices will be issued for the 2015-2020 operating days. Staff said more than $580 million in Z2 credits have been applied since Sept. 1, 2015; undoing and refunding those historical settlements will require recalculating each operating day since, a process projected to take about two years.

“I keep calling it ‘reshaking of the snow globe,’” Davis said. “We have to recalculate inputs into the Z2 process as if the 2009 period through the September 2015 really never happened.”

Market participants facing big bills will be able to take advantage of a five-year payment plan, using FERC’s interest rate. The commission’s rate for the first quarter of 2026 is 7.20%.

At some point, SPP will transition to the current settlement system for production invoices. Additional resettlements will be run on that system monthly, with staff expecting to resettle three historical operating months each month. They expect to be in sync with normal monthly settlements in 2031.

Ironically, SPP no longer uses the Z2 process. Stakeholders recommended, and the grid operator approved, eliminating Z2 credits in 2020 and replaced them with incremental long-term congestion rights (ILTCRs) for new upgrades. The ILTCRs will limit total compensation to each upgrade’s directly assigned upgrade costs and interest.

January 28, 2026

New England Power Demand Grew for 2nd Straight Year in 2025

After years of declining or stagnant power demand in New England, annual energy demand ticked up for the second straight year in 2025, potentially indicating the start of a broader upward trend.

Total system demand grew by about 0.8% in 2025, while in-region power production increased by about 2.8%, according to RTO Insider’s review of data recently released by ISO-NE. Over the past two years, total energy demand has increased by about 2.6%, and in June 2025, the region experienced its highest peak load since 2013.

From the early 2000s through 2023, net energy for load in New England steadily declined because of energy efficiency investments and the growth of behind-the-meter solar. But ISO-NE expects electrification of heating and transportation to reverse this trend and predicts that annual energy demand will increase by 11.4% from 2025 to 2034, accompanied by a more than 2-GW increase in peak load. By 2050, ISO-NE forecasts peak load reaching up to 57 GW. (See ISO-NE’s Final 10-year Demand Forecast Tapers Expectations and ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

These forecasts generally do not account for potential data center demand growth, which could add an additional significant source of demand growth. While high power prices have largely kept developers of large-scale data centers away from the region, its largest electric utilities have indicated an uptick in interest in large load interconnections from developers.

As demand increased in the past year, net imports from Québec declined by about 54%. 2025 marks the third straight year with a significant decline in imports from the province. Net imports accounted for just 2% of energy in the region in 2025, compared to an average of over 11% between 2014 and 2022.

The decline in net imports appears to be driven in part by an ongoing multiyear drought affecting hydropower reservoirs in Québec. According to data from the energy consulting firm McCullough Research, the combined energy content at three of Hydro-Québec’s largest reservoirs entered the winter at its lowest point in the last six years. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.)

Hydro-Québec has said it reduced its exports in the leadup to the New England Clean Energy Connect (NECEC) and Champlain Hudson Power Express (CHPE) transmission projects coming online. Both lines include significant supply obligations for the company. NECEC began commercial operations Jan. 16, while CHPE expects to come online by midyear.

It is unclear how the NECEC line will impact New England’s net imports from Québec. While Hydro-Québec has signed 20-year supply contracts with Massachusetts electric utilities for firm power at a fixed price, it is not prohibited from simultaneously importing power from New England on other lines.

While Hydro-Québec plans to make significant long-term investments to add renewable capacity and increase hydropower production, it has a slim reserve margin for the current winter, and reliability issues in the province have forced it to cut or reduce supply along the line for extended periods over the past five days. The contracted supply is not associated with new capacity supply obligations with ISO-NE, but the company faces penalties by Massachusetts for supply interruptions on the line. (See Hydro-Québec Halted NECEC Deliveries amid Reliability Concerns.)

Increased generation from gas, oil, wind, solar and nuclear resources helped fill the gap left by the decline in imports from Québec.

Nuclear and wind power saw the biggest year-over-year growth, both increasing by over 1,000 GWh. The region’s nuclear fleet produced at its highest level since 2019, the year the Pilgrim Nuclear Power Station closed.

Wind power in the region saw a boost as Vineyard Wind ramped up power production in the latter half of 2025. By the end of the year, the 800-MW project had reached about 72% of its production capability. Wind power should be in line for another big year in 2026 if Vineyard and Revolution Wind are both able to complete construction. Revolution is in the late stages of construction but has yet to start producing power. Both projects have obtained stays on the Trump administration’s December stop-work order.

Wind and solar power each accounted for about 4% of total energy in 2025. Solar production increased modestly, by about 6%. This does not include behind-the-meter solar, which has grown significantly in recent years and is the largest category of solar in the region. ISO-NE’s most recent load forecast projected behind-the-meter solar providing 6,316 GWh of energy in 2025, compared to the 4,836 GWh provided by front-of-meter solar during the year.

Oil-fired generation also spiked significantly in 2025. About 80% of this use occurred in January, February or December. The region’s reliance on oil tends to be concentrated during high-demand winter periods when generators have limited access to pipeline gas. Over the past week, sustained cold weather has caused generators to rely heavily on their stored fuel inventories, with oil frequently meeting about a third of energy demand in the region.

Despite the region’s heavy reliance on oil when temperatures drop, oil-fired generation accounted for less than 1% of total energy in 2025.

Gas generation in New England hit another record in 2025, increasing by about 0.8%. Annual gas generation in New England has increased by 21.4% since 2020.

The increased reliance on gas and oil generation contributed to an annual increase in power system carbon emissions. Based on data through Nov. 30, ISO-NE estimates that annual emissions rose by about 2%.

January 28, 2026January 28, 2026

Oregon PUC Probes PGE on Data Center Cost-sharing Proposals

The Oregon Public Utility Commission questioned Portland General Electric’s proposals concerning grid infrastructure cost allocation for data centers, voicing concern that the utility risked prioritizing data centers over other customers.

The Oregon PUC held the hearing under docket UM 2377, which it created in March 2025 to investigate the impact that large loads have on other customers. But with Oregon legislators passing the POWER Act in 2025, UM 2377 has become a first step in rolling out the law.

The POWER Act aims to create a separate customer category for large energy users, such as data centers, and require those users to pay a proportionate share of their infrastructure and energy costs. The law defines a large energy use facility as one that uses more than 20 MW. It applies only to Oregon’s investor-owned utilities. (See Oregon House Passes Bill to Shift Energy Costs onto Data Centers.)

The Jan. 21 hearing focused on PGE’s written testimony submitted on Dec. 19.

PGE wrote that it aims to create a “durable, transparent and equitable rate structure that fairly allocates growth-related costs to the customers driving system growth, whether they are large loads such as data centers or residential demand from increasing use of air conditioning, so that each customer class pays for the costs it causes and the system benefits it receives.”

PUC Chair Letha Tawney asked for clarification on PGE’s proposal, including its proposal to continue to offer an opt-in approach for grid flexibility from data centers.

Tawney asked why the utility is sticking to its voluntary flexibility approach instead of implementing a mandatory requirement to tackle potential “scarcity events” that can impact the system and other customers.

“Your proposition is the opt-in is working: We shouldn’t worry about mandating something,” Tawney said. “I guess I’m really concerned about grid constraints driving pricing and reliability events, truly. So, why should I have confidence that the opt-in is sufficient, as opposed to mandating, from a reliability perspective, that this flexibility has to be on the table?”

In exchange for flexibility, PGE offers data center developers “speed to market,” which has resulted in “very aggressive flexibility proposals,” PGE’s Isaac Barrow replied.

Barrow contended that the opt-in approach has led to “significant resources [at] zero cost to the utility or any other participant, to provide the most benefit.”

“There is also a technical challenge, because it is very bespoke,” Barrow said. “I’m not sure what requirements you could bring forward that would allow that specific optimization of the flexibility proposals.”

Tawney also asked how PGE’s proposals could impact other customers’ compliance with Oregon House Bill 2021, which directs the state’s investor-owned utilities to reduce greenhouse gas emissions by 80% by 2030, on the path to achieving 100% GHG-free generation by 2040. (See Clean Energy, Equity Goals to Reshape Oregon IRP Process.)

PGE has proposed implementing a Peak Growth Modifier (PGM), a methodology to allocate fixed generation and transmission costs to customer classes based on their contribution to peak load growth.

“I am concerned that there is a limited universe of large-scale clean energy projects that are well priced and have reasonable commercial online dates, have interconnection agreements signed and some sort of line of sight to actually energizing,” Tawney said.

She asked how the PGM could address the potential of large loads consuming lower-cost generation resources while leaving residential customers with higher-cost options for HB 2021 compliance.

PGE has proposed new special contracts aimed at allowing large load customers to accelerate buildout of clean energy on the grid with the idea that it would “only be the resources that are left over from an RFP process, allowing for the best projects to go to our cost-of-service customers,” according to Jacquelyn Ferchland, senior manager of rates and regulatory affairs at PGE.

Barrow added that the special contracts would address effective load carrying capability and “what is the appropriate risk allocation for underproduction as well as overproduction of the specific contracted asset.”

He noted that if PGE does not serve data centers within the HB 2021 framework, other entities without decarbonization requirements may take over.

“With the demand we’re seeing, if … PGE does not serve these entities within our service portfolio, within the protections of House Bill 2021, there is a strong potential that they get served by an entity that does not have decarbonization as to the greenhouse gas requirements or is not subject to the Power Act or House Bill 2021,” Barrow said.

Financial Concerns

The hearing also touched on the financial pressure from buildout of resources to meet demand from data center customers.

Although tools like Contributions in Aid of Construction could alleviate some of the pressure, that might not be enough, Tawney said. She noted the risk of PGE running out of capital for other projects.

PGE keeps the balance sheet in mind, which is why the utility does not build at the speed data center customers would like, according to Ferchland. PGE’s flexibility approach and special contracts aim to allow data centers to connect to the utility’s system faster, she said.

“But otherwise, we are concerned about pressure on our balance sheet, and we would want to make sure that we move only as quickly as appropriate to ensure that our balance sheet remains healthy,” Ferchland said.

“I am concerned that you’re articulating a pacing based on your financial situation that I’m not seeing in the tariff,” Tawney said. “And I’m not understanding how you would be able to accomplish without sort of being accused of a discriminatory behavior towards a particular customer. So, understanding that would be really helpful.”

The commission’s final order is due by April 30, 2026, according to the docket.