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February 27, 2025

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Stakeholders Want More from MISO on Tx Project Cost Containment

CARMEL, Ind. — MISO doesn’t think it needs to step up cost monitoring on its ever-larger transmission projects even as some stakeholders call for tighter measures.

Speaking at a Feb. 25 cost allocation working group meeting, MISO’s Jeremiah Doner said the RTO doesn’t see a need to upend its current variance analysis process, the mechanism it uses to investigate projects that incur cost overruns or other difficulties.

“We think that the current process is designed to sufficiently monitor and track projects,” Doner told stakeholders.

MISO’s End-Use Customer sector in December asked the RTO and stakeholders to discuss transmission cost containment measures. The request coincided with MISO announcing it would investigate one long-range transmission project from its first portfolio, which experienced a 2.5-times increase in costs. (See Cost Overruns on Project in 1st LRTP Prompt MISO Analysis.)

MISO staff perform variance analyses on regionally cost-shared transmission projects that encounter schedule delays, permitting challenges, significant design changes or experience at least a 25% cost increase from original estimates. The studies are also triggered when developers find themselves unable to complete the project or if they default on the terms of their selected developer agreement.

After completing the analysis, MISO can either let a project stand, develop a mitigation plan for it, cancel it or assign it to different developers if possible. A committee of MISO employees selected by RTO executives makes calls on how to deal with such projects.

The End-Use Customer sector and the Coalition of MISO Transmission Customers have said that MISO’s 25% trigger is too high.

Some stakeholders have suggested MISO lower the current 25% cost-increase limit to around 10%. They have also said the RTO should consult with state regulators to review the cost mitigation measures it prescribes to some developers.

MISO settled on the 25% threshold 10 years ago, Doner said.

“There were stakeholders who wanted the value to be higher, there were stakeholders who wanted the value to be lower,” he said.

Zachary Callen, an economic analyst at the Illinois Commerce Commission, asked if MISO has considered notifying stakeholders about projects with up to a 24% cost overrun that might run the risk of a variance analysis.

Doner said MISO thus far hasn’t encountered too many projects that have cost overruns that come close to the 25% limit.

“There still is room for some modest enhancements,” argued attorney Ken Stark, representing MISO end-use customers. He added that the End-Use Customer sector is willing to come before the working group in April to propose some stiffer requirements to “layer on” to the existing process.

“The world has changed. The portfolios that are coming in aren’t exactly cheap,” said consultant Kavita Maini, representing MISO industrial customers. She said for a billion dollar transmission project, costs could spill over by $250,000 before MISO commits to examining them.

“That’s a lot of money. … It seems like this threshold should be much lower,” Maini said. She said she believes there’s more to do to make the variance analysis more transparent and ensure proper monitoring of projects.

Doner maintained that the process is sufficiently transparent. He said MISO staff uses the publicly available reporting that developers submit to MISO to review projects. However, he acknowledged the RTO can’t always share confidential project information.

“We think that the tools are there. We’ve been able to track costs with projects and make changes, if need be,” he said.

Although MISO so far doesn’t seem receptive to increased variance analysis activations, Doner said it plans to more clearly provide notice to stakeholders through its public planning committees when it finishes a variance analysis and develops an action plan.

MISO has completed nine variance analyses to date. For most studied projects, the RTO has either drawn up mitigation plans or let projects stand. While the grid operator has never reassigned a project developer through the analysis, it has canceled one 500-kV project due to a new right of first refusal law in Texas. (See FERC Rejects Last-ditch Effort to Save Tx Project.)

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Dragos: Attacks on ICS Increased in 2024

The barrier to entry for malicious cyber actors to target operational technology and industrial control systems (ICS) continued to drop in 2024, paving the way for new adversaries to target electric utilities and other critical infrastructure providers, cybersecurity firm Dragos claimed in its annual Year In Review report released Feb. 25. 

At the same time, cyber defenders made “incremental but uneven” progress adapting to the new pressures on them, Dragos said, with electric utilities and other regulated industries demonstrating “higher maturity levels” than peers in other sectors, including water utilities and manufacturers. The firm said that “visibility into OT environments lags behind adversary tactics in many cases.” 

“Organizations with strong incident response capabilities, defensible architectures, secure remote access protocols and robust network monitoring are far better positioned to reduce the risk of a successful attack on the enterprise OT even in this increasingly complex environment,” Dragos said. 

Dragos publishes its Year in Review each year to alert cybersecurity professionals to trends in cyberattacks, as well as specific threat groups that were active during the previous year. The firm said nine of the 23 threat groups that it tracks were active in 2024. 

New Adversaries with Stage 2 Capabilities

Two of these groups — Graphite and Bauxite — were identified last year for the first time, although Graphite is now known to have been active since at least 2022, and Bauxite since 2023. 

Graphite has conducted spear-phishing campaigns — in which an emailer attempts to gain confidential information by impersonating trusted senders — against natural gas pipeline operators and hydroelectric facilities in West Asia and Eastern Europe, along with energy and government entities in Poland, Ukraine and the Middle East. 

While Dragos does not link attack groups with specific nation-states in its report, the firm did note that “Graphite focuses on organizations with relevance to the military situation in Ukraine.” 

According to the report, Graphite’s activities have not yet risen past Stage 1 of the ICS kill chain, a model of ICS attacks adapted from Lockheed Martin’s cyber kill chain framework. SANS Institute defines Stage 1 as “espionage or an intelligence operation.” But the other newly identified group, Bauxite, has demonstrated the ability to reach Stage 2 of the kill chain, Dragos said, meaning “a capability that can meaningfully attack the ICS.” 

Bauxite’s first campaign affected nearly 100 organizations globally and involved compromises of programmable logic controllers connected to the internet. This gave the attackers the ability to launch a denial-of-service attack against the victims’ ICS. The group went on to target devices manufactured by Sophos, leading to “enterprise impact on chemical, food and beverage, and water and wastewater industries.” 

Dragos noted that Sophos devices are also found in North American electric and oil and natural gas utilities, though these were not identified as having been affected by the attack. The firm said that Bauxite “shares substantial technical overlaps, based on capabilities and network infrastructure, with the pro-Iranian hacktivist persona CyberAv3ngers.” 

Three other active threat groups demonstrated ICS cyber kill chain Stage 2 capability: Chernovite, developers of the ICS attack framework Pipedream; Electrum, previously involved in attacks against Ukraine’s electric grid in 2016; and Voltzite, a group with “extensive technical overlaps with” the China-connected Volt Typhoon group. Volt Typhoon has been accused of embedding itself in the information technology networks of U.S. critical infrastructure organizations for at least five years. (See CISA Leader Reiterates China Cyber Warnings.) 

Dragos called Voltzite “arguably the most crucial threat group to track in critical infrastructure, [with a] dedicated focus on OT data.” The firm said it has observed Voltzite stealing “data that contains critical information about the spatial layout of energy systems” and expects the group to continue operating against critical infrastructure both in the U.S. and “Western-aligned nations” in 2025. 

Dragos Urges Ransomware Preparedness

Ransomware remained a serious threat across industries in 2024, with Dragos saying the number of ransomware attacks against industrial organizations has doubled year over year since 2022. 

Last year, the firm observed ransomware groups posting sensitive data of 1,693 industrial organizations on their dedicated leak sites; 984 incidents, more than half the total, were observed in North America, with 419 in Europe and 137 in Asia. Fewer than 100 incidents each were observed in South America, Africa, the Middle East, and Australia and New Zealand. 

Companies in the electricity industry constituted a relatively small portion of the ransomware attacks, with only 30 incidents in 2024. The vast majority of incidents affected the manufacturing sector, which Dragos attributed to the knowledge that “even brief disruptions can cause significant financial and logistical fallout” for manufacturers. However, the firm warned that other sectors, including energy, transportation and ICS vendors, “remain high on the list as ransomware groups refine their tactics to maximize pressure and impact.” 

“With these threats showing no sign of slowing, organizations must prioritize resilience, proactive defenses and incident response readiness,” Dragos said. 

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NARUC Winter Summit Tackles Uncertainty Around Demand Growth

WASHINGTON — Demand growth coupled with an ongoing changeover in supply has dominated the power industry’s attention, and it was a major theme at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit, held Feb. 23-26. 

Those trends have pushed up prices, notably in PJM and its recent capacity auction, but FERC Commissioner David Rosner said all of the RTOs save billions of dollars annually by wringing efficiencies out of the grid. 

“The advantage of markets really is their ability to attract capital and attract the lowest-cost resources,” Rosner said. 

It gets complicated because markets also have to recognize that different resources provide different reliability benefits, and figuring out how to design to markets to address that fact has proven to be a long, iterative process. 

“The commission has approved different ways to ‘accredit’ capacity; that’s a fancy word for saying, ‘We are compensating resources for their actual contribution towards reliability,’” Rosner said. “And that evolves as the system evolves, and the more smart policies like that that we can have in place that pay for service provided, that just makes sense.” 

Markets have improved resource performance, and they have placed the risk for bad bets away from customers and toward investors, NYISO CEO Rich Dewey said. But the fleet has changed significantly in the quarter-century since ISOs and RTOs started running parts of the grid. 

“You’ve got to think about valuing the attribute of what these resources bring, and getting that right, so the investment that’s necessary matches the value and the performance that you get out of that attribute,” Dewey said. “So, markets are in a continuous evolution. You can’t just stand it up and then sit back and collect the rewards of harnessing that spirit of competition. We need to continue to work at it.” 

New York has a goal of getting to net-zero emissions by 2050, but the markets were not set up to address that issue initially, Dewey said. So a big part of the ISO’s work has been to get the rules place that attract the kinds of investment that will realize the policy. 

“The challenges, however, seem to be getting bigger,” Electric Power Supply Association CEO Todd Snitchler said. “We’re going through what I think is a second round of an important opportunity for new investment into restructured markets. But it’s not unique to restructured markets. You’re seeing this in vertically integrated portions around the country as well, where load growth is growing, and growing meaningfully for the first time in a generation.” 

All the change is happening at a time with real challenges from the political side, as states that stood up markets in the 1990s now have very different policies, Snitchler said. The focus used to be on least-cost dispatch, which is what the markets were designed for, and now many states want carbon reductions, or other policies that do not always line up with others in the same market. 

“It’s not an absolute degree of certainty that’s needed, but it’s a reasonable degree of certainty that’s needed,” Snitchler said. “And we find ourselves in very uncertain situations presently, which makes investment very difficult at the very time we need investment to be flowing fairly dramatically.” 

These issues recently came to a head in PJM when its last capacity auction cleared the rest of the market at $270/MW-day after years of lower pricing, a signal for needed new supply, Snitchler said. 

“There already is market behavior that is responding to just one price signal,” he added. “Now we do have to be thoughtful and understand that a number [of], or several more, high auction clears are probably not politically palatable.” 

Pennsylvania Gov. Josh Shapiro (D) and PJM have agreed to a deal that will cap prices for the next couple of auctions as the RTO considers additional changes in the capacity market. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

All of the changes to markets make it riskier to commit the capital needed to get new generation built, Shell Energy North America CEO Carolyn Comer said. 

“The more markets continue to get tweaked, the more uncertainty we see, the harder it is for me to compete for that capital, quite frankly, and that’s a problem,” Comer said. 

Shell has started to invest directly in power plants, so it is watching those rules for its own purposes, she said. It also offers risk-management services for smaller market players. In the past, hedges were commonly offered to such customers for 15 to 20 years, but the pace of change makes that less feasible. 

“I do believe it’s important to take risk off consumers and move it to the product; that’s the whole point of creation of competitive markets,” Comer said. “Then I also have to think about making a return on the risk that I’m actually taking. And in order to be able to calculate that return on risk, I need a certain amount of policy certainty.” 

The changes have led to a number of policies at PJM, especially including price caps and temporary queue jumping, but the ultimate solution to higher prices is to get more resources onto the grid, and that should involve all kinds of generation, American Clean Power Association Vice President Carrie Zalewski said. 

“The obvious answer is, let’s interconnect stuff,” Zalewski said. “Waiting in an interconnection queue is one thing, but not knowing how long you’re going to wait, there’s a whole other level of uncertainty that creates more issues with supply chain.” 

Developers can spend so much time waiting for a generator interconnection agreement (GIA) that permits already approved expire. Order 2023 from FERC will help once implemented, but more can be done both before the GIA and after, she added. 

Uncertainty on the Demand Side

While suppliers face uncertainty, the issue is increasingly important on the demand side as the grid faces load growth not seen in decades from data centers, reshoring manufacturing and the early days of electrification. 

Artificial intelligence is a major source of demand for data centers now, and despite some recent improvements in efficiency from Chinese firm DeepSeek, that is expected to continue to grow, Electric Power Research Institute CEO Arshad Mansoor said. 

“There’s Jevon’s paradox that says things that get more efficient are used more, and that’s really what’s going to happen,” Mansoor said. 

The large language models that have dominated AI so far can only train on the information that is on the public internet, which is only about 5 to 6% of the total data in the world. Industries, including energy, are going to start training AIs on their proprietary data to help out in their operations, and that is going to lead to huge new computing demands regardless of how efficient the code is, Mansoor said. 

All that growth represents a huge economic opportunity for the country, and meeting it is going to require getting the load forecasts right, PJM Senior Vice President Asim Haque said. 

PJM is working closely with its member utilities and increasingly the data centers themselves, while focusing on the areas in its footprint with the highest demand, like Northern Virginia and Columbus, Ohio. 

The new load growth is going to require more transmission and generation, but some of the data center customers are focused on speed to market. 

“They’ve got to get to market to a particular point in time,” Haque said. “That’s why you’re seeing some more adventurous efforts outside of directly connecting to the grid — this concept of co-location.” 

While many data centers are focused on getting to the grid quick, Meta’s Etta Lockey said her firm was not interested in shifting costs to other customers and ultimately looks at data center expansion as a net positive. 

“We sit at a really generational, hopefully once-in-a-career opportunity to think about some economic growth in this country that could be unprecedented,” Lockey said. “And that’s the future state that I really want to [home] in on and force us all to kind of think about what that can really look like.” 

While rates have been on the rise, if the load growth from data centers is handled right, it will lead to more infrastructure, and the overall costs of the system will be spread across a bigger base. 

“The end goal should be downward pressure on rates, let’s be honest,” Southern Co. Vice President of System Planning Clay Rikard said. “This new load is the opportunity to put downward pressure on rates, if we do it right.” 

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NYISO Preparing to Collect Duties on Canadian Electricity Imports

NYISO presented the Installed Capacity Working Group with two proposals it plans to file with FERC to give itself the means to collect duties in case President Donald Trump’s tariff on Canadian energy imports applies to electricity.

Trump had announced a 10% tariff on “energy resources from Canada” but paused it on Feb. 3. While NYISO’s current position is that import the tariff does not appear to legally apply to electricity — and it is not necessarily its job to collect the duties if it does — it wants to be prepared on Day 1. (See NYISO Assessing Impact of Trump’s Canada Tariff on Electricity Market.)

“The goal is to have effective March 4 the tariff infrastructure in order to comply with whatever the government may impose,” NYISO General Counsel Robert Fernandez said.

“It seems to me that what we think about whether or not they apply is not relevant because ultimately, it will the wannabe king and his minions who tell us whether it applies or not, and I don’t get the impression they’re going to consult with you,” said Mark Younger of Hudson Energy Economics.

NYISO’s primary proposal would allow it to collect duties from real-time scheduled imports originating from “Duty Eligible Proxy” buses that represent interties between New York and Canada. It would create a new Rate Schedule 21 for duty recovery that would be paid to a relevant federal authority and charged to the “financially responsible party” for each subject transaction.

Under this proposal, NYISO would use day-ahead location-based marginal prices to calculate duties. NYISO said that using this method will allow both day-ahead and real-time transactions to reflect the cost of duties in their offers. Using real-time prices would make it impossible for duties to be calculated on day-ahead transactions.

“The day-ahead LBMP represents a financially binding price for electricity sales at the relevant tie and location,” said Nathaniel Gilbraith, manager of energy market design for NYISO. “Using real-time prices alone to calculate duties would create a duty cost risk that the day-ahead transactions could not reflect in their offers.”

Until NYISO develops software to automate calculating, collecting and paying duties, the process would be manual. The ISO would not collect duties on Canadian energy wheeling in from other control areas.

NYISO’s alternate proposal defines subject transactions the same way but would collect the required duties from withdrawals on a ratio-share basis. This is being done to create a duty mechanism that would apply to load in order to maximize the likelihood that NYISO has the legal authority to collect.

“My understanding is that the importer of record pays the collection that pays the tariff and ultimately passes it on to the consumer,” Fernandez said. “And that’s analogous to what we’re saying could happen under the load-ratio-share approach.”

Fernandez said this was not the favored approach because it was not as economically efficient. The alternative, which the ISO calls a “backstop,” was being filed out of an abundance of caution, he explained.

Younger said he appreciated the steps NYISO was taking to protect the market and added that it should ensure that capacity was also covered by any language filed with FERC.

Ted Murphy, a lawyer for NYISO from law firm Hunton Andrews Kurth, explained that there was historical precedent against import duties being levied against electricity. He said federal customs and tariff enforcement agents did not know how applicable tariffs were to electricity.

“One thing that gives me comfort is that one line in the trade tariffs suggest that intangible things are not subject to tax,” Murphy said. “There are cases saying electricity is intangible. In my mind, capacity as one level of abstraction out from actual electrons crossing the border makes me think that the focus is going to be on energy, not capacity or other products. But nobody knows.”

Chris Casey, with the Natural Resources Defense Council, said that filing a request with FERC to enable compliance with potential import duties made him nervous because no formal ruling on electricity had been made by any relevant authority. Fernandez replied that the ISO had considered going through a more formal process of getting a declared ruling, but the problem was lack of time.

“In a perfect world, these rules would have been developed through the normal shared governance process,” Fernandez said. “But March 4 is next week, and we’ve been looking at this for a couple weeks now, and we simply do not have time to get that ruling.”

Fernandez said that if Customs and Border Protection or the Treasury Department did not give NYISO a definitive ruling by March 4, the import duties would not be collected or remitted to the government. They would set up the accounting necessary to do so only when ordered.

“Dollars will not flow, will not be collected or remitted until we know that we actually have a legal obligation to do that,” Fernandez said. NYISO staff and counsel would consider whether to add capacity to the proposals in a pre-filing conference, he said.

Fernandez went on to say that he expected ISO-NE to file a similar request by the end of the week with FERC but that he did not know where the other ISOs or RTOs stood on this issue. A stakeholder said that he was worried that NYISO’s filing would “raise awareness” and cause reinterpretation of existing law.

“Are we making this a self-fulfilling prophecy?” Fernandez reflected. “I don’t know, but I read the newspapers. It’s not like we can stick our heads in the sand and act like ostriches on this and hope it doesn’t happen. On March 4, NYISO needs rules in place so we can comply with the law if it eventually comes to pass.”

When NYISO staff were asked by other stakeholders how much money was at stake for the federal government, they said that forecasting that figure was complicated and that they didn’t want to go on record with a dollar figure.

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MISO South Hit Record, 33-GW Winter Peak in Jan. Storm

The MISO South region relied on transfers from the Midwest to handle a record, 33.1-GW winter peak during a Jan. 20-22 storm. 

The peak Jan. 22 unseated the previous winter peak of 32.6 GW from Jan. 27, 2024. This year’s storm brought near-blizzard conditions to parts of the Gulf South, with 10 inches of snowfall in New Orleans. MISO South’s topmost demand remains the 35.2 GW the region realized in late August 2023.  

Speaking at a Feb. 24 Entergy Regional State Committee meeting, MISO Independent Market Monitor staffer Robert Sinclair said MISO Midwest assisted the South region with large transfers during the storm.  

Sinclair said the Midwestern assist demonstrates the value of the South’s membership in MISO. He said footprint-wide, MISO mitigated potential storm impacts through preparation. MISO increased short-term reserve requirements ahead of time, Sinclair said, paving the way for an increase in imports “that helped ease system stress.”  

Overall, MISO set a 108-GW winter peak Jan. 22, about 1 GW short of its all-time winter peak. The grid operator did not have to resort to emergency measures to power through the arctic blast.  

MISO South adviser Tag Short said MISO’s entire transmission system held up well throughout the storm.  

“[That] gets very dicey, when you have ice on the transmission system,” Short said.  

Otherwise, Sinclair said voltage and local reliability issues have persisted over the winter in MISO South’s load pockets. He explained the region is short on generation in some locations at times, prompting MISO operators to make out-of-market commitments. Sinclair recommended MISO use short-term reserves instead to price the reliability issues and lower revenue sufficiency payments.  

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ERCOT Board OKs Mobile Generators in San Antonio

ERCOT’s Board of Directors on Feb. 25 approved staff’s recommendation to pursue use of 15 mobile generators as an alternative to extending the life of two aging gas-fired units slated for retirement in South Texas.

Staff said during a special board meeting that, based on current cost estimates, LifeCycle Power’s generators and their combined capacity of 450 MW will be more cost effective in mitigating the “relevant reliability risks” in the San Antonio area posed by CPS Energy’s planned retirement of the three units at its V.H. Braunig plant.

Nathan Bigbee, ERCOT’s chief regulatory counsel, said continuing to operate Braunig Units 1 and 2 for two more years beyond their 2025 retirement date is budgeted to cost $59 million, including expected fuel costs and incentive factors or adders. The two units went into service in 1966 and 1968 and have a combined summer maximum rating of 392 MW, according to a CPS update.

In contrast, LifeCycle’s generators are projected to cost $54 million, including fuel costs and incentives. They can reach full output in 10 minutes, faster start times than the three Braunig units. ERCOT and CPS signed an RMR contract on Feb. 24 for Braunig Unit 3, which has a summer max rating of 400 MW.

The age of units 1 and 2 creates additional risks in extending them RMR contracts, Bigbee said. He said the budgets for the two units have increased 8% since November.

“These are both 60-year-old units, so they’re very old generators,” he said. “CPS Energy has told us that these are going to need lengthy outages and expensive inspections and repairs to ensure that they can be safely operated.”

The two units would have to be inspected consecutively, potentially pushing the inspections past the high-demand summer season. They would also have to wait until CPS completes its 60-day inspection of Braunig Unit 3, which begins March 3.

“That just shows you that this is subject to a lot of variability,” ERCOT General Counsel Chad Seely said.

The generators are leased by Houston utility CenterPoint Energy, which has agreed to release its obligation to LifeCycle for two years without compensation. CenterPoint leased the generators and several smaller ones after the deadly 2021 winter storm, but the large generators have sat unused ever since. (The utility says it plans to resize its generator fleet to address future hurricane outages.)

CPS has said it can interconnect the generators in batches to its substations, starting in June and ending by September. The generators will be registered as generation resources and would be the last resources deployed by ERCOT during actual or anticipated emergency conditions, as are RMR units.

One sticking point is the diesel-fired generators’ emissions permitting. Bigbee said the resources might not meet nitrogen oxide gas emissions limits. Staff are working with LifeCycle and the Texas Commission on Environmental Quality to “identify an appropriate solution under the current regulatory framework.”

The board’s decision also begins a 90-day clock for ERCOT to come up with an exit strategy from operating Braunig and the mobile generators. Staff said that involves accelerating three transmission projects south of San Antonio to alleviate the constraint causing the congestion. Two of the projects are scheduled to come into service in 2027 and a third in 2029.

In the meantime, ERCOT and the market are on the hook for $45.85 million under the terms of Braunig 3’s RMR contract. That is the budgeted amount, which ERCOT said is a 33% increase since the first submission from CPS in November.

The RMR contract is ERCOT’s first since 2016, when it entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Ending Greens Bayou RMR May 29.)

CPS told ERCOT in 2024 that it planned to retire the Braunig units in March 2025. However, ERCOT said the plant’s retirement would lead to reliability issues in the San Antonio area until the transmission constraint is resolved. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)

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BPA Markets+ Phase 2 Bill Could Reach $27M — or More

The Bonneville Power Administration will be on the hook for nearly $27 million in funding for the next phase of SPP’s Markets+ — and potentially more depending on the market’s final footprint, according to a document the RTO filed with FERC on Feb. 21 (ER25-1372). 

BPA’s funding obligation — and that of other Markets+ funders — appears in a table appended to the end of the Markets+ Phase 2 Funding Agreement, which SPP submitted to FERC to gain approval for its plan to obtain third-party financing to cover the $150 million needed for the Phase 2 implementation process for Markets+. 

The agreement details the purpose, terms and timelines of the financing and outlines how Markets+ funders will collateralize the loan up front and then ultimately fund its repayment through future market transactions. Funders who back out before the market goes live would still be liable for paying their share. 

The agreement contains a few provisions that seem specifically tailored for BPA. For instance, BPA’s status as a federal agency prohibits it from posting collateral, so the SPP will instead require BPA to submit a “letter of assurances” committing the agency to cover its obligation. 

Another apparent accommodation for BPA is the carve-out Feb. 13 to Aug. 12 as “Stage 1” of Phase 2. During that stage, Markets+ funders will only be obligated to commit to two-thirds of the total spending for Phase 2 — or $100 million. That will allow a funding entity to withdraw from Phase 2 before incurring full charges, a potentially important option for BPA, given that it has committed to funding the market before issuing an official decision on whether to actually join it. 

Unclear Liability

But regardless of whether BPA will ultimately be liable for its full share of Phase 2 or only a portion, the Markets+ agreement indicates the agency will likely be obligated to cover more than the $25 million that BPA staff had previously estimated. 

The table at the end of the agreement lists the eight entities that have so far publicly committed to funding Phase 2, including BPA, Powerex, Arizona Public Service, Tacoma Power, Grant County Public Utility District (PUD), Chelan County PUD, Salt River Project and Tucson Electric Power. 

Absent from the table are two investor-owned utilities known to be leaning in favor of Markets+ — Puget Sound Energy (PSE) and Xcel Energy’s Public Service Company of Colorado (PSCo), as well as El Paso Electric (EPE), which last month committed to join the SPP market despite not having participated in its Phase 1 development process. (See El Paso Electric to Join SPP’s Markets+ in 2028.) 

The table shows BPA’s “Stage 1” obligation comes to about $26.8 million in a market footprint consisting of the eight committed funders, slightly above — but in line with — BPA’s previous estimate for its Phase 2 implementation costs. 

But another column for full “Phase 2” obligations, which are calculated off the $150 million Phase 2 total, shows BPA’s share increasing to nearly $40.2 million, a figure agency staff did not broach during funding discussions at its most recent day-ahead market stakeholder workshop in late January. (See BPA Considers Impact of Fees in Day-ahead Market Choice.)

Industry sources have told RTO Insider that the $40.2 million figure is likely an outlier and that its Phase 2 funding exposure should decline once entities such as PSE, PSCo and EPE commit to funding, although those commitments are not guaranteed and the agency’s final obligation isn’t clear. 

BPA expressed confidence that its funding obligation will decrease as other parties sign on to Markets+. 

“The $40.19 million represents BPA’s total share of the Phase 2 development costs based on the current list of funding participants,” agency spokesperson Nick Quinata said in an email. “BPA believes, based on discussions with other Phase 1 participants, that other entities will commit to Phase 2 funding, which will lower each entity’s liability.” 

“Each entity’s pro rata share will be recalculated to account for any additional entities that execute funding agreements once their internal and/or regulatory processes are complete,” SPP COO Antoine Lucas said. 

Michael Linn, director of market analytics at the Public Power Council (PPC), which represents the publicly owned utilities comprising BPA’s “preference customers,” said his group isn’t concerned about the $40 million figure. 

“PPC expects additional entities will announce their intention to fund Phase 2 over the coming months and BPA’s costs will be close to the original anticipated costs,” said Linn, whose group has advocated for the agency to choose Markets+ over CAISO’s competing Extended Day-Ahead Market (EDAM). (BPA staff have estimated EDAM will require lower startup costs than Markets+ but potentially higher annual costs.) 

At least one of those announcements appears to be pending. Earlier in February, PSCo filed with the Colorado Public Utilities Commission for permission to join Markets+. The Colorado utility is expected to pay about $20 million to help fund Phase 2. (See related story, PSCo Seeks to Join Markets+.) 

‘Mousetrap Situation’

Both Linn and Quinata said the staged funding approach outlined in the Markets+ funding agreement should work to BPA’s advantage. 

Linn said it would contain the agency’s costs as uncommitted entities “work through their internal processes prior to executing the agreement,” while Quinata noted it “limits each party’s liability should Phase 2 discontinue for any reason.” 

But Fred Heutte — senior policy associate with the Northwest Energy Coalition, which has urged BPA to join EDAM — cautioned that the timelines established in the agreement effectively bind the agency to joining Markets+ before it issues its draft market decision in early March and its final “letter to the region” on the choice in May. 

Speaking with RTO Insider, Heutte pointed out that timelines in the agreement require BPA to provide its “letter of assurances” committing to Phase 2 funding by Feb. 28, a week before it issues the draft letter March 6. 

“So the timing on this is what’s really interesting, because by the time that Bonneville issues the draft letter to the region, they’ll already have put the financial commitment on the table. It’s not just something they’re considering —they’re already in the game,” making them liable for their full obligation if they pull out after Stage 1, he said. 

Heutte laid out a potentially complex scenario in which SPP begins investing in and staffing up for Phase 2 after securing financing this spring, creating an “immediate contingent liability” for the RTO and Markets+ funders such as BPA. Launch of the market in the first half of 2027 would create yet another contingent liability for BPA as it works through its next rate case, because it would then be obligated to begin repaying its portion of the loan whether or not it chooses to participate in the market. 

“This is a mousetrap situation. Bonneville’s going to say, ‘Well, you know, we did what we were asked to do, and now we’re kind of in, so we have to stay in,’” he said. “And I have a feeling that, while they are still under a tremendous amount of pressure to have a letter [to the region] say, ‘Well, we’re not going to decide right now; we’re just not going to make a market choice,’ which is what we [NWEC] strongly prefer. The financial hook on this letter of assurances is a pretty big one.” 

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Conn. Set to Reappoint Top Regulator amid Utility Legal Challenges

Marissa Gillett, the top regulator at the Connecticut Public Utilities Regulatory Authority (PURA), is poised to be reappointed amid utility lawsuits and outcry about the state’s regulatory environment.

Tensions between utilities and regulators have escalated during Gillett’s tenure. The utilities have argued that the agency has demonstrated a lack of transparency and threatened their ability to receive a fair return on investments, while Gillett has argued that she is simply holding them accountable to existing laws. (See The Rocky Road to Performance-based Regulation in Connecticut.)

In January, Eversource Energy and Avangrid, which own gas and electric utilities in the state, sued the agency in Hartford Superior Court, alleging that Gillett has illegally issued unilateral decisions on “scores of substantive rulings across a wide range of contested and uncontested dockets conducted by PURA over the past five years.”

“Certain actors at PURA have undertaken a number of unlawful procedures that have the effect of reducing what the legislature intentionally designed as a multi-member agency to the province of one commissioner,” the companies wrote.

Gov. Ned Lamont (D) has stood by Gillett and helped craft a deal to ensure her reappointment on the eve of her confirmation hearing Feb. 20. The administration agreed to appoint state Sen. John Fonfara (D) and former state Rep. Holly Cheeseman (R) to fill the vacancies on PURA’s board, which would return the agency to a full complement of five members.

The deal would also transition PURA from a subsidiary of the Department of Energy and Environmental Protection to a quasi-public agency, enabling the administration to circumvent rules preventing it from appointing sitting legislators to executive-level positions.

At a nearly six-hour confirmation hearing with the legislature’s Executive and Legislative Nominations Committee, Gillett fielded a wide range of questions about her leadership at the agency, energy affordability in the state and utility decarbonization efforts.

She defended PURA against the utilities’ allegations in their lawsuit and said she has not made any final rulings without holding a vote with her fellow commissioners.

“We have votes recorded on every final decision of the agency in accordance with law,” Gillett said. She pointed to PURA’s record in recent court challenges to agency decisions, noting that it has “consistently and repeatedly won when challenged in court — four times at the [Connecticut] Supreme Court.”

Responding to questions about the regulatory environment for the state’s investor-owned utilities, Gillett said PURA has continued to apply “traditional ratemaking principles” and emphasized that its statute makes clear that the burden of proof in regulatory dockets is on the utilities.

In May 2024, Eversource announced its plans to cut $500 million in planned investments in the state because of the state’s “negative regulatory environment.” (See Eversource Announces $500M Cut in Connecticut Investments.) More recently, Eversource and PURA have disagreed over a potential expedited cost recovery mechanism for deploying advanced metering infrastructure, putting the estimated $766 million investment on hold.

“It is the legal obligation of these entities to appropriately invest in the grid,” Gillett said. “If a regulated monopoly is not adequately investing in the grid to meet its statutory obligations of maintaining a safe, reliable and affordable grid, the consequence of that is a revocation of their franchise.”

Gillett also criticized Eversource for not yet coming in for a rate case during her tenure, noting that it “has not been in for an adjudicated rate case since 2014; there was a settlement in 2018. If there is a question of whether the utility has enough revenue to build out and invest in this state, there is a remedy for that, and that remedy is coming in for a rate case before PURA.”

“It is my opinion that it is an unacceptable amount of time for a regulated utility to stay out of receiving scrutiny from not just its regulator, but other stakeholders,” she added.

Gillett said the fight between utilities and regulators in Connecticut is being watched throughout the country and could affect utility regulation in other states.

“The work that my colleagues and staff have positioned ourselves to continue … has been viewed at times as existential threats to traditional ways and business models. I think folks should understand that this is being watched and does have larger implications,” Gillett said.

Legislators focused much of the hearing on energy affordability in the state, which has some of the most expensive electricity rates in the country.

“People are telling us that they are suffering; they are truly having to make a decision between paying their utility bill … and having to give something up in exchange for that,” state Sen. Eric Berthel (R) said.

Gillett pointed to a significant recent increase in the public benefits charge for Eversource ratepayers as a key cost driver, which she said was largely from unrecovered costs associated with the power purchase agreement for the Millstone nuclear plant. She said she voted against the 10-month increase in the charge, which will conclude at the end of April, but was overruled by her fellow commissioners.

Environmental justice advocates attending the hearing voiced their support for Gillett, while the committee voted along party lines to support her reappointment. She still must be confirmed by the General Assembly, where Democratic legislators hold large majorities.

Avangrid declined to comment on Gillett’s renomination and the agreed-upon changes to PURA’s makeup. Eversource wrote in a statement that “the planned changes provide a pathway for a constructive, predictable and transparent regulatory environment that benefits customers through investment and a focus on reliability.”

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Holtec Announces SMR Plans at Palisades Nuclear Plant

Holtec has set a 2030 target for commercial operation of two small modular reactors to be built beside the large nuclear plant it is working to restart in Michigan.

The company’s Feb. 25 announcement also laid out a roadmap for Holtec and Hyundai Engineering & Construction to build a 10-GW fleet of SMRs elsewhere in North America through the 2030s.

Both announcements build on existing plans and an existing alliance between the two companies.

They said their respective construction expertise and in-house manufacturing capabilities will be key to increasing the speed and decreasing the cost of SMR construction compared with the few recent large-scale U.S. reactor projects, which have been restrictively slow and expensive.

Holtec’s SMR-300 initiative is just one of several small modular reactor development efforts. The 2030 target date for commercial operation makes it one of the more ambitious efforts, but the concept is similar: Standardize the design, increase deployment and develop economies of scale, rather than intermittently building what amounts to a series of first-of-a-kind projects.

“The key to making SMR deployment faster and more cost effective isn’t just learning from the industry — it’s applying those lessons directly to each new project,” Rick Springman, Holtec’s president of global clean energy opportunities, said in a news release. “With Holtec’s in-house manufacturing and Hyundai E&C as our construction partner, we control most of the process, allowing us to refine and improve with every reactor we build. That’s how we scale smarter and deliver reliable energy where it’s needed most.”

The two companies held a launch ceremony Feb. 25 at Michigan’s Palisades nuclear plant, which Holtec acquired from Entergy when it shut down in 2022. Holtec initially planned to decommission it but now is preparing the 54-year-old 800-MW reactor for a first-of-its kind restart. The company received a $1.52 billion federal loan guarantee for the project in March 2024.

Holtec said it has invested more than $50 million in SMR-300 site development efforts and expects to start its formal permitting process with the Nuclear Regulatory Commission next year.

Holtec began collaborating with Hyundai E&C in 2021, and the two have now signed an expanded cooperation agreement for SMR-300 construction.

The SMR-300 is a 300-MW advanced Generation 3+ pressurized light water reactor design. Holtec’s intention is to build the plants, service them through their operational life, manage spent fuel and perform decommissioning.

Multiple other companies and consortia are pursuing SMRs, and many potential customers are keenly interested in them as a non-intermittent source of emissions-free electricity, but SMRs still must reach a long series of engineering, regulatory, financial, supply-chain and political milestones before they are deployed at scale.

Hyundai E&C CEO Han-Woo Lee said in the news release that the partners intend to do just that: “To ensure the successful completion of this project, we will work closely with the U.S. government and leading local companies to build a systematic supply chain, create and develop high-quality jobs in the U.S., and develop strategies for mutual growth with local communities, ultimately pioneering a new era in the global SMR industry.”

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PSCo Seeks to Join SPP’s Markets+

Xcel Energy subsidiary Public Service Company of Colorado (PSCo) has asked the Colorado Public Utilities Commission for permission to join SPP’s Markets+, saying the market option would not lock “the company into other markets which have suboptimal policies for customers and Colorado’s state goals.” 

In a Feb. 14 filing, PSCo requested that the commission find it is in the public’s interest that the utility join SPP’s Markets+ while also asking for approval of modifications to the electric commodity adjustment tariff to recover costs associated with its market decision. 

Specifically, PSCo seeks recovery of approximately $2 million in Phase 1 funding fees. The company also seeks recovery of costs associated with Phase 2 of Markets+, including approximately $14 million in administrative fees during the first five years of market operations and about $13 million to $15 million in technology upgrades, according to the filing. 

Gerald Deaver, a commission adviser sitting in for CPUC Chair Eric Blank during a Feb. 21 Markets+ State Committee, said, “PSCo indicates in the filing that it would enter into the Phase 2 agreement as quickly as it could after a commission order approves their participation.” 

PSCo “has evaluated several alternatives to Markets+, including the SPP RTO expansion and CAISO EDAM,” the filing stated. “The company’s analysis concluded that, at this time, participation in Markets+ provides the best option to retain the benefits of market participation while not prematurely locking the company into other markets which have suboptimal policies for customers and Colorado’s state goals.” 

The company said it favors Markets+ for several reasons, including its governance structure, benefits “overall and in relation to costs relative to the other markets studied, including EDAM,” and Markets+’s greenhouse gas emissions tracking and accounting system. 

PSCo also said “Markets+ is the only organized day-ahead market proposal for the West that will have a fully impartial and independent market operator, providing confidence that all market operator actions will be for the benefit of all participants and stakeholders.” 

Markets+ supporters have repeatedly touted the benefits of the market’s independent governance in comparison with CAISO’s state-backed governance, an issue supporters of the ISO’s EDAM and Western Energy Imbalance Market have been attempting to address through the West-Wide Governance Pathways Initiative. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.) 

“Over the past 10 years, through the successful implementation of the Western Energy Imbalance Market, regional coordination has proven an essential tool in maintaining grid reliability and lowering costs for electricity consumers in California and across the West,” CAISO spokesperson Jayme Ackemann said. “We look forward to continuing that work as we move [toward] the launch of the Extended Day-Ahead Market in 2026, which will build upon the benefits of the WEIM for all participants.” 

In an email, Xcel spokesperson Tyler Bryant told RTO Insider that the company has been involved in the development of Markets+ since 2022. Bryant said the company believes joining Markets+ is in the public interest based on CPUC’s criteria. 

Antoine Lucas, SPP vice president of Markets, said the RTO is pleased with the application and the company’s continued participation in Markets+. 

“SPP values their unique voice as an entity representing the Mountain West region and the specific needs of Xcel customers, and we look forward to their engagement in phase two of Markets+ development,” Lucas said. 

‘Thoroughly Intermeshed’

But not everyone is thrilled with the decision.  

In an interview with RTO Insider, Brian Turner, director of Advanced Energy United, contended that the application lacked sufficient analysis of climate change impacts and the purported costs and benefits to Colorado ratepayers. 

Turner also said the decision will create market seams within Colorado. He noted that Colorado-based Tri-State Generation and Transmission — which sells energy to utilities all around the Centennial State — has indicated it will join SPP’s full RTO as that entity expands into the West. 

Meanwhile, the utilities that buy power from Tri-State have each indicated they will join different markets, some going with Markets+, others committing to SPP RTO, and others joining no market, Turner said. 

The transmission systems of Xcel and Tri-State “are thoroughly intermeshed,” according to Turner. 

“The seams between Xcel, going with Markets+, and Tri-State, going with SPP RTO and [Tri-State] having its own issue with seams with individual co-ops, is going to be a very major issue here, and one that should be raised to Colorado policy makers and is not,” Turner said. 

“I fear the Colorado utilities, and therefore, policymakers, and therefore, ratepayers, are headed down a road to a very limited market with lots of costs and reliability risks from the seams and the limited market that they’ve set themselves up with, basically driving down a dead-end road,” Turner said. 

Tom Kleckner contributed to this story.