The D.C. Circuit Court of Appeals has denied a review of a FERC decision that allowed SPP to incorporate some Missouri transmission facilities into one of its pricing zones, spreading the costs of the newly integrated infrastructure across the zone’s customer base (23-1133).
The court ruled July 11 that FERC “reasonably applied” the cost-causation principle in approving SPP’s tariff revision to include the annual transmission revenue requirement for the city of Nixa’s facilities in the RTO’s pricing Zone 10. Nixa’s 10 miles of transmission lines and substations are owned by GridLiance High Plains.
Writing for the court, Circuit Judge Justin Walker said the commission determined that the Nixa assets brought “integration, reliability and power transfer benefits to Zone 10 customers” that justified spreading the costs across the transmission zone.
“FERC may analyze costs and benefits at the zonal level rather than the customer level, and FERC reasonably determined that all the zone’s customers will enjoy benefits,” he said. “Because of those zone-wide benefits, it was reasonable for FERC to spread the integration’s costs to all the zone’s customers.”
The appeal was brought forward by the Arkansas city of Paragould’s Light & Water Commission and other parties, several of whom unsuccessfully requested FERC rehear its 2023 order approving SPP’s tariff revision (ER18-99-007). (See “City of Nixa, Mo., Annual Transmission Revenue Requirement,” FERC Briefs: Orders Addressing Arguments Raised on Rehearing.)
The utility objected to FERC’s level of generality in considering benefits, the type of benefits considered and the case’s evidence of benefits. The court rejected each of the objections.
Walker said FERC had no duty to “take such a hyper-granular approach to weighing costs and benefits” and that it “reasonably analyzes costs and benefits at the zonal level” when considering integration of new facilities in the zonal system.
“As a significant customer in Zone 10, Nixa has paid a considerable share of Zone 10 transmission facility costs — a share that includes costs for facilities that primarily serve load to non-Nixa customers,” Wright wrote. “So, even though Nixa itself does not draw direct, quantifiable benefits from these facilities, it has footed part of the bill. In sum, the petitioners want Nixa to keep paying a substantial percentage of the costs of facilities that directly serve non-Nixa areas of Zone 10, while the petitioners themselves pay no part of the facilities that directly serve Nixa.”
The D.C. Circuit found that as it and other circuit courts have held, “benefits justifying a cost shift do not need to be tangible, nor must they be amenable to precise tabulation.” It said it is enough that there is “an articulable and plausible reason to believe” the integration’s benefits are “roughly commensurate” with the integration’s costs.
The court also said the claim that FERC did not have sufficient evidence to conclude that integrating the Nixa assets would provide any benefits to non-Nixa customers faced “a high bar.”
“FERC’s decisions need only be supported by ‘substantial evidence,’ which is ‘more than a scintilla’ but ‘less than a preponderance,’” Walker wrote.
The petitioners argued their case before Walker and fellow Circuit Judges Florence Pan and Cornelia Pillard in April 2024.
MISO stakeholders are skeptical of the RTO’s proposed new approach to divvying up reliability obligations among load-serving entities based on evolving system risk.
At a July 9 Resource Adequacy Subcommittee meeting, MISO said it would make a few changes from when it announced its plan about six months ago. Now, it plans to use different demand hours that determine the allocation and keep those hours in place for three years at a time in a bid for the allocation to be more stable for LSEs’ resource planning.
MISO assigns its LSEs a portion of its overall planning reserve margin requirement (PRMR). Today, the grid operator divvies up the PRMR based on LSEs’ 50/50 load forecast for MISO’s coincident peak. MISO said because of shifting and growing risks to the system, its reliability requirement should be reallocated among LSEs based on periods that contain the highest reliability risks. MISO previously said there’s a mismatch between LSEs’ obligations and the load LSEs are consuming at the times of greatest need on the system.
MISO Market Design Economist Bill Peters said though MISO needs to change the responsibility of each of the LSEs because risk is shifting, it also needs to respect that LSEs “need stability and a way to plan” with a somewhat stable PRMR allocation year over year.
MISO is reassessing its PRMR allocation partly because it moved to an availability-based capacity accreditation based around risky hours, not peak load. Peters called reallocating the PRMR the “opposite side of the coin” to accreditation.
But MISO no longer proposes to use the same set of annual risky hours that it uses for its capacity accreditation, when resource availability is expected to be less than 25% of operating margin. Instead, it plans to devise what it calls “seasonal expected resource adequacy risk hours” that will be fixed for three years at a time. Peters said those hours still would ensure that LSEs furnish output during the times of greatest need.
MISO staff stressed that the seasonal expected risky hours would be different than MISO’s existing “resource adequacy hours,” or the anticipated risk periods that MISO deems critical for its availability-based resource accreditation.
The seasonal expected risky hours would be derived from an analysis of the past three years of historical resource adequacy hours. Peters said the analysis would examine how the hours are “trending and when are we seeing risk.”
Peters said MISO may consider updating the hours if “substantial changes” occur sooner than the three-year cycle. He said MISO would have to set criteria for what magnitude of change could trigger an update outside of the regular three-year cadence.
Peters said a MISO analysis of five years of data has shown that resource adequacy hours “slowly shift but remain relatively stable” year-over-year, making the three-year option viable.
Stakeholders asked if MISO expects the seasonal resource adequacy hours to change dramatically from one three-year set to the next.
“I expect some different hours in the next three-year iteration,” Peters said, but didn’t venture a guess as to what degree.
Peters said MISO no longer can portion out the PRMR based on a single annual peak demand period, as is done now.
“We have a lot of capacity availability while the sun is shining now,” Peters said. “The model is showing us we have problems when the sun goes down. That’s different than what we’re used to.”
MISO has about 14.5 GW of solar capacity and counting.
“Should your obligation be based on a peak period where the sun is shining and system risk is low? We think not,” Peters said.
Peters said the shared PRMR obligations are emblematic of the interconnected nature of the system and how “your actions affect everyone else.” He said the PRMR allocation exemplifies the Hawaiian word “kākou,” which expresses collective responsibility, or “we’re all in this together.”
Peters said MISO still needs to add historical meter data on demand reductions and behind the meter generation from LSEs to get the full picture of net settled load to provide allocation examples. He said without that information, MISO cannot allocate the PRMR properly.
Some stakeholders said MISO needed to collect that LSE-level data before proposing the new design.
Attorney Jim Dauphinais, representing multiple industrial end-use customers, said he had “serious concerns with the proposal” because it relied on too many hours —upwards of 500 in the summer based on MISO’s illustrative example — and didn’t appear to account for actions LSEs might take in emergencies or near emergency situations to cut back load.
“It seems like almost an overcompensation for the stability issue and dilutes the price signal of trying to keep load off of true loss of load risk hours,” Dauphinais said. He said he feared the proposal would eliminate the incentive to reduce load and warned that load that hasn’t shown up before on the system in certain hours could begin cropping up.
WPPI Energy’s Steve Leovy said MISO didn’t provide enough data to show that the PRMR allocation would give LSEs the steadiness they need to plan. He said he saw “nothing” in MISO’s proposal that would prevent an LSE’s obligation from jumping “four or five percentage points” from one year to the next.
“We’re getting way too ahead of ourselves without knowing what the results of this process would look like,” he said.
MISO’s Davey Lopez said MISO’s proposal is far from final. MISO said it hopes to file a new PRMR allocation for FERC approval sometime in early spring.
Dauphinais said MISO would be better off using an allocation based on demand during a few hours of net peak throughout the year rather than trying to tie the proposal loosely to RA hours.
Minnesota Power’s Tom Butz said MISO should ask itself whether it’s seeking to truly quantify risk or develop a “mechanism of math.”
“The chances of this being stable are really, really low,” Butz said.
MISO is collecting stakeholder opinions on its PRMR allocation blueprint; staff will return to the Resource Adequacy Subcommittee in August for more discussion.
At the April Resource Adequacy Subcommittee meeting, Public Utility Commission of Texas economist Werner Roth said the proposal might introduce “a ton” of complexity for little payoff.
The Southern Renewable Energy Association appeared before Entergy’s state regulators to urge them to think twice before considering leaving MISO for the Southeast Energy Exchange Market.
Simon Mahan, executive director of the SREA, told attendees at a July 11 Entergy Regional State Committee Working Group that SEEM doesn’t appear capable of delivering the savings of MISO or SPP.
Mahan said SEEM averages 80,000 MWh in monthly transactions. He said while that sounds like a lot, SEEM’s annual amounts are equivalent to a 300- to 500-MW solar farm, with less than 0.1% of all bilateral trades in the Southeast conducted through SEEM.
Mahan said, “for a region as big as SEEM,” which has more demand than MISO, the numbers are minuscule.
“So, we’re talking about a very, very small market and very little impact on how the utilities [operate] on a day-to-day basis,” Mahan said. “There are 99.9% more bilateral trades already going on in the Southeast without SEEM.”
Mahan said SEEM’s estimated $1 million per month in gross savings over 2025 excludes all the parties that need to be paid: Hartigen as market platform provider; Potomac Economics for monitoring; Mahan McGuire Woods for legal fees; and various utility positions dedicated to monitoring the marketplace.
“The total benefit we’re looking at here is far below the $40 million estimate provided to FERC a few years ago,” Mahan said. “If you join SEEM, you’re going to lose a significant number of benefits.”
Mahan said while SPP (95 GW of installed capacity) and MISO (198 GW of installed capacity) estimate their total value to members at $2.14 billion and anywhere from $3.1 billion to $3.9 billion, respectively, SEEM (representing 160 GW) appears poised to deliver just $12 million in annual savings.
By contrast, Mahan said savings conferred to Entergy Louisiana alone for one year of MISO membership are about $79 million/year (La. PSC docket X-36326). Cleco, meanwhile, is primed to save about $112 million from 2025 to 2027, a 13% savings over leaving MISO (La. PSC docket X-36327), Mahan said.
Entergy associate general counsel Matt Brown confirmed that the $79 million savings take into account the MISO administrative costs.
Mahan’s presentation comes as one Louisiana regulator wants the South to defect to SEEM.
Louisiana Public Service Commissioner Eric Skrmetta wrote an opinion piece updated July 9 blasting SPP and MISO for recent blackouts and high-priced leadership while advocating trying out SEEM.
“Under the guise of regional cooperation, SPP and MISO have steadily eroded the authority of state commissions, drained resources from ratepayers, and handed over control to unelected bureaucrats. Executive compensation has soared while customer service has declined. This centralized, unaccountable model is a bad deal for American families and businesses — especially in the South, where traditional energy values and pro-consumer policies matter,” Skrmetta said.
Skrmetta said instead of southern states “being tied to bloated RTOs,” SEEM could offer a “market that reflects the conservative principles of low overhead, local accountability and respect for state sovereignty.” Skrmetta argued that in addition to eliminating a costly RTO bureaucracy, regulators and ratepayers would enjoy more authority under SEEM, which prioritizes “performance, not politics.”
Skrmetta asked southern utilities to notify MISO and SPP of their intention to leave; he said regulators, governors and utility CEOs should coordinate on transition plans.
“Defenders of the current system claim SPP and MISO bring ‘market benefits’ and ‘supply diversity.’ But when it mattered most — during storms and heat waves — they failed. What good is diversity if it doesn’t work?” Skrmetta wrote.
However, Mahan said SEEM audit reports show that offers decline during periods of high demand. The Independent Market Auditor’s report from December 2022 described scarce offers and zero matched trades during record cold and blizzards Dec. 24-26, when members Tennessee Valley Authority and Duke were forced to order rolling blackouts.
“It is not really working in a way that you can depend on it during extreme weather events,” Mahan said of SEEM.
Since before the market’s launch in 2022, SEEM’s critics — which include SREA, the Southern Environmental Law Center, the Carolinas Clean Energy Business Association, the Sierra Club and the Southern Alliance for Clean Energy —have argued it would entrench the power of monopoly utilities while providing limited benefits to customers compared to alternatives. (See After One Year, SEEM Still Drawing Criticism.)
Mahan said SEEM doesn’t offer forecasting, a day-ahead market, locational marginal prices or transmission planning. He added that SEEM doesn’t appear to involve state regulators in decisions or maintain stakeholder groups for transparency.
Bill Booth, a consultant to the Mississippi Public Service Commission, asked if Mahan’s presentation was meant to dissuade regulators from considering SEEM membership over MISO.
Mahan said he was there to provide more information about how the SEEM market functions. He added that he preferred a locational marginal pricing setup over a voluntary buy and sell approach led by utilities because the former is much more transparent.
“It’s not entirely clear how the utilities come up with the prices for the offer or sale of energy,” Mahan said.
Mahan added that no utility appeared to be arguing that SEEM is lowering retail rates, with no docketed rate case demonstrating any savings.
Booth insisted that MISO South regulators are just “looking for the lowest cost” and said MISO’s membership rates are expensive.
Mahan responded that “MISO and SPP provide more value to the ratepayers that can flow through their bills” than SEEM’s lackluster savings for the Southeast.
SEEM did not respond to RTO Insider’s request for comment on Skrmetta or Mahan’s positions. SEEM’s most recent press releases contain an 800 media hotline that connected to a KOA campground in Greensboro, N.C.
Mahan noted the dockets over the years from MISO South states that investigated savings estimates and explored alternatives to remaining in MISO.
“Some of those dockets, I’ve noticed, have become more and more redacted,” Mahan said. He requested regulators consider revealing some of the redacted language.
Brown said Entergy makes its savings reports public and redacts information only when it would be “harmful to customers’ interests.”
“That’s why we protect it. It’s not that we have secrets,” Brown said.
Mahan also recommended the Mississippi PSC open a docket to investigate SEEM member Mississippi Power to get “real world data” on how the utility is engaging with the market and the savings it has experienced.
Portland General Electric’s need for more resources by 2030 has grown by 16%, according to updated modeling, largely because of a decreased capacity contribution from batteries, particularly in winter.
The figures are in an update to PGE’s 2023 integrated resource plan the utility presented to the Oregon Public Utility Commission (OPUC) on July 8.
Updated modeling led to changes in PGE’s preferred resource portfolio, which includes 4,629 MW of new resources by 2030 compared to 3,984 MW in the 2023 IRP — a 645-MW increase.
While the amount of resources such as wind and non-emitting energy contracts decreased in the updated portfolio, the biggest change was the addition of 881 MW of battery storage.
New modeling in the IRP update found the effective load-carrying capability for four-hour battery storage would be 46% in summer and 22% in winter — compared to roughly 70% in summer and 45% in winter modeled in the 2023 IRP for 100 MW of nameplate capacity.
“The reduced capacity contribution of storage resources, particularly in winter, highlights a critical planning challenge regarding the interaction between storage and energy resources in a system with growing demand and thus energy deficits,” the IRP update states.
Jimmy Lindsay, director of resource planning at PGE, attributed the decreased capacity contribution in part to “a saturation issue,” as the utility is planning “a significant quantity” of four-hour lithium-ion batteries in its portfolio.
But he said another factor is increased load forecasts during the winter, when demand can surge for several days in contrast to shorter peaks in the summer.
“That is an issue that we had anticipated would emerge … that the models weren’t necessarily capturing the challenge around recharging on a multi-day event,” OPUC Chair Letha Tawney said.
The IRP update said it didn’t look at including long-duration storage in the preferred portfolio “due to the lack of commercially proven projects.” Long-duration storage will be explored further in the 2026 IRP.
The presentation was informational only; PGE is not seeking formal acknowledgement of its update from the commission.
Tax Credit Implications
Existing plus new resources in the updated preferred portfolio total about 10,000 MW in 2030, about double the amount of resources in 2026. A large jump in resources is expected in 2029, as resources procured through requests for proposals come online.
Another jump in resources is expected in 2032, when new transmission will support imported power.
In particular, PGE is working with the Confederated Tribes of Warm Springs on a 500-kV upgrade of the 230-kV Bethel-Round Butte line. They secured a $250 million Grid Resilience and Innovation Partnerships program grant from the U.S. Department of Energy that will allow survey work to begin.
Another challenge for PGE is changes in federal policy — and the cost impacts to the utility’s renewable energy transition. The elimination of federal tax credits could increase renewable costs by 30% to 50% or even more, according to the IRP update.
“The change in the federal landscape cannot be underestimated,” said Kristen Sheeran, PGE’s vice president of policy and planning.
Rapid Industrial Growth
The IRP update predicts a 20-year average annual growth rate of 2.8%, an increase from the 1.2% growth rate forecast in the March 2023 IRP. For industrial customers, the 20-year average growth rate now is expected to be 5.2% a year, compared to 3.5% in the 2023 IRP.
“Growth is driven primarily by unprecedented industrial sector expansion, especially in semiconductor manufacturing and data centers,” PGE said in the update.
After the PGE update was released, chipmaker Intel, Oregon’s largest private employer, announced it was laying off almost 2,400 of the 20,000 employees in the state as the company struggles to remain competitive. Intel’s operations in Hillsboro are served by PGE. It’s unclear what effect Intel’s difficulties might have on future load growth.
PGE hit a record summer peak load of 4,498 MW in August 2023 and a record winter peak of 4,113 MW in December 2022.
The IRP update projects a summer peak of about 5,500 MW in 2030 and 8,000 MW in 2044, taking into account electrification of vehicles and buildings. Winter peak is expected to grow to about 4,500 MW in 2030 and 7,000 MW in 2044.
MISO’s Independent Market Monitor has expressed lingering dissatisfaction with NERC’s Long-Term Reliability Assessment, even with potentially corrected values.
Monitor David Patton said though NERC would rerun the numbers on its assessment regarding MISO’s risk, it appears MISO will be downgraded only to an “elevated risk” from “high risk,” which he said he still disagrees with.
NERC in June said it would rerun the numbers on expected risk for MISO after the IMM discovered an inconsistency in the assessment. NERC apparently used unforced capacity values for MISO when calculating a margin that it ultimately compared to an installed capacity requirement. (See MISO IMM Blasts NERC Long-term Assessment, Says RTO in Good RA Spot.)
Patton said NERC is likely to call out MISO for elevated risks for a few more summers despite the RTO maintaining an approximate 17% installed capacity requirement that more than covers forced outages during peak summer demand hours.
Patton said he believes reliability assessments chronically undercount MISO’s interfaces, which grants it more access to imports from neighbors “than just about anybody.”
“It has a powerful impact during emergencies,” Patton said during a July 10 Market Subcommittee meeting.
He said even during MISO’s late June emergency declaration in a wide-ranging heat wave, there was “virtually no potential for load loss.” He said MISO’s emergency declaration didn’t escalate into load-modifying resource use and wound down after MISO was able to access the emergency ranges of generation. (See MISO Declares Max Gen Emergency in Heat Wave.)
“If you look at our neighbors, they were all having operating reserve shortages,” unlike MISO, Patton said.
Despite his confidence in MISO, Patton urged the MISO community to keep an eye on “four to five years out” so the footprint continues to enjoy reliable operations. He said MISO nevertheless should “keep an eye on the pace of entry” for new generation and “continue to be flexible” to slow down retirements.
Potential energy suppliers in IESO’s second long-term energy and capacity procurement (LT2) sparred with ISO officials July 10, saying its proposed auction rules favor natural gas generators by insulating them from most of the cost of gas transmission upgrades.
In a webinar, the ISO said it would reimburse gas generators 75% of upgrade costs “to address natural gas transmission cost uncertainty.” The auction rules also provide cost protections for all generators facing increased tariffs and allow gas generators to extend their commercial operation dates because of delays in obtaining gas turbines.
Mike Marcolongo, associate director of Environmental Defence, said the 75% reimbursement was “quite generous.”
“I think that we have done quite a lot for all of the technologies that are that are eligible to participate in our [requests for proposals] over time,” responded Dave Barreca, IESO’s supervisor of resource acquisition. He cited the materials cost index adjustment the ISO has used in previous solicitations to address the fluctuating costs of lithium for battery providers.
Attorney Jake Sadikman — co-chair of Osler, Hoskin & Harcourt’s national energy group, which is working with IESO on the procurement — also cited the “regulatory charge credit,” which reimbursed battery storage for regulatory energy charges, including global adjustment.
Barreca said the ISO decided a 75% reimbursement was “an appropriate value … that would mitigate the risk sufficiently for a gas generator to be able to participate in the RFP while maintaining the incentive for them to mitigate — or, in fact, avoid — the costs.”
Need for New Gas Generation
Brandon Kelly, director of regulatory and market affairs for Northland Power, said the ISO’s approach could result in “inefficient outcomes” if the added cost makes a gas generator more costly than rejected bids.
IESO says natural gas generation is essential to reliability on Ontario’s hottest summer days. | IESO
“This is an imperfect outcome,” Barreca acknowledged. “It’s not what we would have necessarily wanted. But this is what we need to ensure that all resources are able to participate.
“We wouldn’t be doing this if we didn’t think that we need some amount of … new natural gas on the system to get us through the transition period over the next few decades,” he added. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)
“I can recognize that none of this will be perfectly efficient, but that is true for the rest of the RFP. There are a lot of constraints other than cost: on where sites are selected and what ultimately gets chosen. So we are, I think here, doing the best, given the constraints that we have.”
Kelly was unpersuaded. “What you’ve done here is not to … allow these resources to participate; it’s to advantage them, and that’s materially different from the approach you guys have taken elsewhere,” he said. He suggested gas generators instead incorporate a risk premium in their offers.
IESO’s Ben Weir said if the actual gas transmission connection costs ultimately approved by the Ontario Energy Board are less than the risk premium, “ratepayers end up covering that risk-adjusted premium for really no reason.”
Uncertainty over Grid Interconnection Costs
Eric Muller, Ontario director of the Canadian Renewable Energy Association, said there also is great uncertainty on the costs of interconnections with the electricity transmission system. He said the ISO should provide a cost-sharing or true-up mechanism to address those risks.
Barreca said the risks of electric interconnection costs are “materially different” than that for gas because of a new process that will allow Hydro One, the province’s largest transmission operator, to give generators “perhaps not perfect [certainty] but at least enough certainty on those costs that they’ll be able to confidently submit their bids.
“We continue to work hard with our colleagues at Hydro One on this issue and hope to be able to share something with you all in the very near future,” Barreca said.
Officials said IESO will hold an engagement session with Hydro One on July 30 to provide an overview of the process for making new or modified connections to the grid.
Barreca said the ISO was unable to reach such certainty regarding gas distribution costs. “That ultimately just was not possible. And that is a kind of regulatory thing,” he said.
Tremor Temchin, senior vice president of development for Convergent Energy and Power, said the ISO’s requirement that generators provide continuous power for at least eight hours; its “open ended” commercial operation date for delayed turbine deliveries; and the cost sharing on gas distribution all look “like the ISO picking and choosing winners in a procurement that is supposed to be technology agnostic.”
He suggested the ISO run a separate, gas-specific procurement, saying “it’s the only way to keep this fair for other technology types.”
“This is not the ISO trying to tip the scales in favor of one technology or the other merely to enable participation,” Barreca responded. He said the move to an eight-hour minimum duration is “reflective of system needs and evolving system conditions.”
He noted that the ISO has added nearly 3,000 MW of battery storage “in a very short period of time.”
“The capacity value of that four-hour storage diminishes the more that you add without adding more … energy-producing resources,” he said. Nevertheless, he said, the ISO has not sought to derate storage capacity.
“So, I really do not think that we are here trying to tip the scales in one direction or the other. We want to have as balanced and fair a procurement as possible. We very strongly believe in the value of a diverse supply mix, and that includes some of everything.”
14 TWh, 1,600 MW Sought
IESO announced in December that it was seeking up to 14 TWh of annual generation and up to 1,600 MW of capacity resources in its second long-term procurement. The first window seeks 3 TWh of energy and 600 MW of capacity.
The ISO released final documents June 27 for the first window of LT2 energy and capacity procurements. Energy proposals will be due Oct. 16 and capacity proposals due Dec. 18, with notifications of winners set for April 14, 2026, and June 16, 2026, respectively.
Timelines for the first submission window of IESO’s second long-term energy and capacity procurement (LT2) | IESO
The LT2 documents include updates to some terms to reflect IESO’s May 1 introduction of a financially binding day-ahead market and the elimination of the State of Charge Reduction Factor, a transitional mechanism used to address storage facilities’ need to withdraw real-time market (RTM) offers after depleting energy during RTM obligations. With its new forward market, the day-ahead market no longer includes RTM, eliminating the dual obligation. (See Ontario Introducing Nodal Market May 1.)
The new procurement also gives bidders based in Canada a 2% reduction to their “evaluated proposal price.”
IESO Senior Adviser Nick Topfer said the home-field advantage was added in response to a June 26 directive from the Ministry of Energy and Mines and will be additive — not diluting existing bonuses such as for Indigenous participation.
The new solicitation also will allow bidders to seek price increases if import tariffs imposed after the proposals are submitted “directly” increase capital costs by more than 10%.
The ISO will have 50 days to respond to a “tariff adjustment notice” — down from 100 days, as originally proposed. If it rejects the revised price, the contract will be terminated, and the bidder’s completion and performance security will be returned.
IESO has eliminated from the capacity solicitation a proposal to limit capacity check tests to a maximum of 15 degrees Celsius.
“This decision … was a bit premature and was made hastily by us,” IESO’s Sanjiv Sohal said. “It didn’t wholly consider other articles contained in the contract. So as a result, we’re walking this decision back, and the maximum temperature limit for the winter months in section 15.6 of the contract has not been removed.”
The contract requires the tests be conducted when temperatures do not exceed 35 C in the summer or fall below ‑20 C in the winter.
The Bonneville Power Administration has unveiled its proposals for overhauling its transmission planning, with help from the industry.
BPA in February paused certain transmission planning processes to consider new reforms in light of significant growth in transmission service requests. The agency’s 2025 transmission cluster study includes more than 65 GW of requests, compared with 5.9 GW in 2021. The requests exceed the total regional load predicted for the Pacific Northwest in 2034, according to the agency. (See BPA Halts Some Tx Planning Processes Amid Service Requests.)
During a July 9 workshop, BPA outlined its plan for tackling the queue and ultimately reforming its processes to reach the agency’s vision of reducing the time from transmission request to service to five to six years. (See Industry Sees Challenges as BPA Considers ‘Radical’ Updates to Tx Planning.)
For example, the agency is considering implementing readiness criteria and a new Network Integration Transmission Service initiative where any new forecast increase of 13 MW or more during any year would require participation in commercial planning.
“If you can’t meet the readiness requirements, you leave the queue, and we keep funneling it down until we get to a place where in our long-term firm queue management, we’ve either offered you transmission service on a firm basis, we’ve offered it on a conditional firm basis or some other less than firm,” said Abbey Nulph, manager of transmission commercial planning at BPA.
“Our goal is to make as many offers to those that remain as we can so that folks are getting service, potentially not the long-term firm that everybody wants, but the best that we can without degrading the quality of service for existing rights holders,” Nulph added.
The agency also is contemplating offering interim service and moving toward proactive planning, meaning building ahead of transmission service requests, according to the workshop presentation.
BPA told RTO Insider in a statement that proactive planning “is a 20-year scenario-based power flow, capacity expansion and production cost modeling study, performed with robust stakeholder engagement, that will give BPA the vision to identify the evolving transmission needs within our area.”
“This study will operate on a two- [to] three-year cycle and will feed an evolving transmission expansion and reinforcement project portfolio for which BPA will establish a transparent project selection process,” according to the statement. “The planning scenario will be based on a set of models ranging from capacity expansion to NERC planning standard-based power flow studies.”
The agency received support for its framework from stakeholders participating in the meeting. One representative from the Columbia River PUD said the “proactive planning makes a lot of sense because it gives us the ability to take a holistic view of a community and for you to do the same thing when you make your decisions. It’s not just about a company but really looking at the opportunities and what’s going on in the community.”
However, some also raised concerns about recent staffing cuts at the agency and how the costs associated with the reforms will affect ratepayers.
Fred Heutte, senior policy associate at the Northwest Energy Coalition, said in an interview he supports BPA’s initiative.
“We have a lot more extreme weather. We have a big heat wave coming here next week during a low hydro period,” Heutte said. “We do need more transmission to bring on the … more diverse set of resources so we can keep the grid going. And so I really feel like BPA has put good principles on the table.”
Still, Heutte said BPA must ensure customers have fair access to new transmission rights and that the new readiness criteria are flexible.
“There needs to be a real focus on transparency of how they’re handling transmission requests and sorting them out through this new process that they’re developing,” Heutte said. He added that BPA needs to be “very clear about what their intended outcomes are and work closely with the customers and … with the state commissions.”
During the July 9 workshop, Nulph pointed to these principles, saying the agency will focus on transparency and collaboration and provide insights into how it will “solicit information, which data inputs we use, which scenarios we run, how we select the projects that come out the other end of those studies.”
“We don’t want this to be a BPA plan,” Nulph said. “We want it to be BPA’s plan to satisfy the regional needs.”
MISO’s Independent Market Monitor has released four new market improvement recommendations for MISO concerning transmission congestion, the Midwest-South transmission link, market-to-market coordination and price settlements after grid devastation.
IMM David Patton said the recommendations, provided as part of his annual State of the Market Report, should better position MISO for load growth combined with a renewables-heavy future.
Patton said he wants MISO to maximize its Midwest-to-South transmission limit by being less conservative with the space it reserves for unforeseen flows.
MISO actively derates its Midwest-South transfer constraint to keep flows in either direction below the contractual limit. Unmodeled flows over the constraint can push flows up and violate the limit.
But Patton said MISO’s caution has caused the transfer’s utilization to be just 84% of what’s contractually allowed. He said MISO should work in extra, lower-value steps to the transmission limit’s demand curve and raise its energy-plus-short-term reserve limit to the highest penalty step on the transfer to use the transmission more. He said a more detailed curve and relaxed limits could increase the path’s utilization when the value of transfers is high.
Patton also said the changes could reduce the burden on MISO operators to “constantly monitor and adjust the … limit in the real-time market.”
Think Before You M2M
Patton advised MISO to stop accepting SPP’s requests for constraints to be moved to market-to-market coordination unless it’s “clearly warranted.” He said MISO should accept monitoring responsibility of SPP’s flowgates only if it can provide “significantly more” efficient relief on the constraint than SPP.
Patton said in some cases, MISO has accepted an M2M designation for flowgates from SPP even when it cannot deliver economic respite.
“They end up being a lot more costly in the MISO dispatch than in the SPP dispatch. And that costs MISO customers a lot of money,” Patton said of market-to-market flowgates.
Though he didn’t mention it in his presentation, Patton was among the first to alert stakeholders that MISO could offer little relief for a MISO-SPP flowgate in North Dakota strained by a new cryptocurrency mining facility. The situation in 2023 spurred complaints from the MISO side and a FERC refusal to refund about $40 million in congestion costs. (See FERC Again Declines Changes, Refunds on Crypto-burdened MISO-SPP Flowgate.)
More Frequent FTR Auctions
MISO should move to a primarily monthly or seasonal format for auction revenue rights (ARRs) and financial transmission rights (FTR) auctions, Patton said. He said MISO should shift the bulk of its transmission capability from the existing annual FTR auction to seasonal or monthly auctions.
Patton said more lines joining a more frequent FTR/ARR auction process would limit overselling of FTRs or over-allocating ARRs on constrained lines, especially when MISO isn’t made aware of its transmission owners’ outages.
He said MISO’s transmission owners often report outages too late to be reflected in the annual FTR auction, with the network more accurately modeled in MISO’s less-attended monthly auctions.
But Patton said MISO’s current monthly auctions deliver less net FTR revenues than the value of day-ahead congestion, indicating a lack of participation.
The Market Subcommittee launched a renewed effort to improve the FTR/ARR market at the same July 10 meeting where Patton presented his State of the Market report. MISO’s Tony Hunziker said MISO would dig in at the August meeting, exploring ways to bolster FTR market performance and participation, improve model accuracy, ensure funding and better link the day-ahead market to the FTR market.
More Inclusive Impetus for ‘Forced-off’ Pricing
Finally, Patton said MISO could improve its criteria for pricing when an extreme event forces portions of the grid offline.
Patton said the recommendation applies to MISO’s “forced-off asset” event declaration, which sets real-time prices equal to day-ahead prices. MISO created the new settlement practice in 2024 for generators physically disconnected from the grid during extensive transmission outages triggered by extreme events. It’s designed to prevent generation from receiving excessive penalties or undeserved windfalls. (See FERC OKs MISO Settlement Rules for Widespread Tx Outages.)
Patton said even though 2024’s Hurricane Beryl forced transmission offline that disconnected most loads in the Southeast Texas Load Pocket, the storm failed to qualify as a forced-off asset event. He said MISO should tweak portions of the declaration, namely its constraint management and dead bus criteria, to trigger the settlement style.
Patton said MISO defines its revenue inadequacy criteria too narrowly to have activated the pricing and that to address the issue, MISO should add price volatility make-whole payment criteria to the revenue inadequacy criteria when making the call on forced-off asset declarations. He said MISO also should limit the forced-off asset dead bus criteria to load buses only.
Patton said the two adjustments should “ensure that prices in areas affected by transmission damage during extreme weather events are set at reasonable levels and avoid cost-shifting.”
You Must Decommit
Before wrapping his report, Patton took time to call back to a 2023 recommendation that MISO develop tools to recommend decommitment of resources that have been committed in the day-ahead market.
Patton said in early July, MISO racked up $38 million of congestion because there were two gas turbines committed in the day-ahead market that MISO refused to switch off. He said the transmission constraint in question was in violation for six to seven hours. Patton said that sort of circumstance has a simple fix: turning off one or both of the gas turbines.
However, Patton said “MISO will do virtually anything other than” decommit a resource. Patton said there didn’t appear to be a good reason behind MISO steadfastly refusing to decommit resources. Beyond that, Patton praised MISO’s market performance over 2024.
“In many respects, MISO’s markets are more advanced and well-developed than other RTOs, leading to superior performance,” Patton said.
Patton said MISO’s all-in energy price was an average $31/MWh in 2024, lower than the previous year due to an 8% decrease in natural gas prices. He said there was “little change” in average load from 2023.
MISO will review the Monitor’s report through September and post a public response to the recommendations in October. MISO’s response will include to what extent it agrees with the recommendations and how doable it believes each one is.
A new analysis concludes there will not be enough computer chips produced in the entire world to supply the data centers some sources predict will be built just in the United States.
The report is the latest of many doubts raised about sky-high expectations for data center load growth, and it warns about the huge cost of overbuilding the grid to meet the highest 2030 projections.
The projections are varied, but most are large, and they are driving policy-making discussions.
DOE adopted a midpoint assumption of 50 GW — plus 51 GW of non-data center load growth — to conclude the nation will be unable to meet projected demand “absent decisive intervention” because 104 GW of baseload retirement and only 22 GW of new baseload generation is planned by 2030. (See DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030.)
The DOE report called for rapid and robust reforms, lest adversary nations shape the digital norms and control digital infrastructure.
But others say these are the latest overestimations of a trend and that Big Tech will not need all this electricity.
LEI totaled the projections of data center load growth from RTOs, ISOs and balancing areas covering 77% of U.S. electric load; surveyed global projections for semiconductor chip production and supply; and factored in potential increases in chip energy efficiency and computing capacity.
The interior of Google’s data center in Council Bluffs, Iowa | Google
They concluded that under the implied projection of 57 GW of data center load growth, the U.S. would need to buy 90% of all chips produced worldwide from 2025 through 2030, and said that scenario is unlikely — the U.S. now buys less than 50% of the global chip supply, and other nations are ratcheting up their own data center development.
LEI said these calculations support the anecdotal evidence that data center developers are submitting duplicate requests for grid interconnection in multiple jurisdictions that are being misinterpreted as unique requests.
However, the totals are being treated as real by some policymakers.
President Trump is easing and speeding the regulatory process in response to the national energy emergency he declared on the first day of his second term, in part to “power the next generation of technology” and “remain at the forefront technological innovation.”
This speedup raises environmental and safety questions for some observers, as well as financial worries: If more pipelines, wires and generators are built than data centers need, someone else will have to pay for the resulting overcapacity.
“This report underscores a critical and ongoing concern: Inflated and speculative data center electricity demand forecasts in the Southeast are driving a dramatic and unnecessary overbuild of infrastructure that threatens to lock in fossil fuels, hike energy bills and crowd out more reliable, cost-effective clean energy,” said Megan Gibson, senior attorney at SELC. “Such speculative infrastructure investment creates significant economic risks for ratepayers, who ultimately bear the financial burdens.”
Beyond the fundamental constraint of there not being enough semiconductor chips to supply the highest projections of data center growth, SELC noted, there are limits of powering a fleet of new data centers: There are equipment shortages for new large-scale natural gas-fired plants, nuclear reactors are expensive and slow to build, new-build coal appears unlikely, and wind and solar generation suffered major setbacks in the reconciliation bill Trump signed July 4. (See U.S. Clean Energy Sector Faces Cuts and Limitations.)
Shelley Robbins, the Southern Alliance for Clean Energy’s senior decarbonization manager, said there is immense financial incentive for suppliers and developers to game the system and overestimate demand.
“Data center growth has become a suspiciously convenient justification for pipeline and gas plant projects in the Southeast. Pipeline and utility companies make most of their money by building big things and then charging ratepayers for them,” Robbins said. “The result will be an expensive overbuild if we do not carefully scrutinize the genuine likelihood that data center loads will actually materialize.”
MISO debuted a code of conduct for its stakeholder meetings that forbids rude or callous language, deliberate meeting disruptions or disregarding committee chairs’ instructions.
MISO said that by attending stakeholder meetings, all participants agree to maintain professional conduct, identify themselves and organizational affiliation before speaking, take turns speaking and make sure everyone has the chance to talk, stay on topic according to meeting agendas and minimize distractions caused by electronic devices.
The RTO added that it would not tolerate disruptive or disrespectful behavior, including name-calling or personal attacks; “dismissive, sarcastic or demeaning remarks,” speaking out of turn and repeated interruptions, not following the meeting chair’s direction and “conduct that impedes discussion or intimidates participants.”
MISO said participants’ failure to follow the rules and “repeated or egregious violations” could result in restricted participation or being refused entry into stakeholder activities. The code applies to participants attending meetings virtually or in-person.
In response to RTO Insider’s questions, MISO did not elaborate on whether a specific incident prompted the new rules, if the RTO noticed a pattern of troubling behavior in meetings or whether the rules were in the works for a while.
“MISO values stakeholder input and we want to ensure our stakeholder process reflects that,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.
MISO said reliable operations, competitive wholesale markets and collaborative transmission planning requires “engagement built on a foundation of mutual respect, professionalism and fair debate and dialogue to solve complex regional issues.”
The code states that MISO’s proposals and presentations and reports from staff delivered during meetings are “often works in progress meant to promote discussion, negotiation and consensus-building.” It also said meeting participants are expected to describe the contents of meetings “accurately and contextually” — with the understanding that opinions evolve — when sharing meeting information in news reports, social media posts, blogs or the like.
In a July 9 letter to stakeholders introducing the code, MISO CEO John Bear said he valued stakeholders’ diverse perspectives but said MISO stakeholder forums “also demand professionalism and mutual respect.” He asked the stakeholder community to keep engagement “constructive” and treat fellow stakeholders with courtesy.
“Every comment should further respectful, solution-focused dialogue that fosters trust, encourages collaboration and upholds the high standards we hold at MISO, and you hold as representatives of your organizations,” Bear wrote. “Disagreements are natural in these forums, especially when things are changing so quickly, but we all must remember that our engagement must be grounded in professionalism and respect, which, in turn, encourages fair debate and dialogue.”
