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December 13, 2025

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NYISO Details Late June Heat Wave for Reliability Council

ALBANY, N.Y. — NYISO performed an autopsy on the system conditions during the late June heat wave for the New York State Reliability Council at its Installed Capacity Subcommittee meeting on July 10. 

“We got a net demand on the 24th of 31,857 MW, which is over our 50/50 forecast by a couple hundred megawatts,” said Aaron Markham, vice president of operations for NYISO. “When we add back in the assumed behind-the-meter [solar], we were pretty close to the 34,000 MW load we hit in 2013.” (See NYISO Issues Energy Warning as Heat Wave Boils N.Y.) 

By 3 p.m., Markham said, neighboring reliability coordinators reduced imports to New York by about 730 MW, increasing to 1 GW by 5 p.m. NYISO cut exports in response, to a total of 1,660 MW by 5 p.m. 

Between 5 and 6 p.m., the Astoria 3 generator tripped and NYISO declared an Energy Alert. The ISO escalated the alert to an Energy Emergency at 7:13 p.m. as more imports were cut. As the evening wore on, NYISO purchased emergency energy to meet 30-minute operating requirements several times. 

Timeline of the energy use of the New York Control Area. | NYISO

In total, about 2,000 MW of power were curtailed from NYISO from neighboring areas. New York generators tripped or otherwise experienced performance issues, resulting in about 1,000 MW of derates during peak hours. 

“The driver was really high demand that stressed system conditions regionwide due to the heat and performance issues,” Markham said. 

NYISO called on all the demand response programs and saw about 1,000 MW of relief. It also dispatched generation to optimize 30-minute reserves. The ISO purchased about 1,960 MW across all available interfaces. 

Markham said all fuel types were needed during the event but that it looked like wind and solar did better than NYISO initially assumed they would in its summer capacity assessment. 

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BPA Cuts Payments for Tribes, Salmon Restoration Under Revised Cost Projections

The Bonneville Power Administration on July 14 said it is revising future power rates by removing millions of dollars of costs associated with a Biden administration agreement with Northwest tribes aimed at restoring salmon habitat and potentially breaching dams on the Snake River. 

BPA Chief Financial Officer Thomas McDonald detailed the revised power cost projections for the BP-26 rate period in a letter dated July 11 following a Trump administration memorandum in which the president pulled the federal government out of a deal Biden struck with Oregon, Washington and four tribes on four dams along the Snake River in 2023. (See Trump Directs Feds to Withdraw from Deal on Snake River Dams.) 

The deal included payments to the Yakama, Umatilla, Warm Springs and Nez Perce tribes, along with Oregon and Washington. The costs were reflected in BPA’s program forecast issued Oct. 23, 2024. The forecasts serve as an input into the development of rates, according to the letter. 

Under the new forecasts, the agency predicts BPA power rates will see a “slight decrease,” a spokesperson told RTO Insider. 

However, under the updated power cost projections, those payments are removed, including $10.6 million for 2026, $10.8 million for 202 and $11 million for 2028 

Additionally, the agency removed cost projections related to the Lower Snake River Compensation Plan, a hatchery program to return salmon and steelhead to the Snake River Basin.  

The removed cost projections associated with that plan include $11.7 million for 2026, $19.4 million for 2027 and $28.2 million for 2028. 

McDonald noted in the memorandum that removal of the plan cost projections “will not result in a dollar-for-dollar reduction in BPA’s costs.” 

“The Lower Snake Compensation Plan hatchery costs were included as part of BPA’s capital cost projections, which means that the annual spending is recovered over time rather than in the year it is spent,” McDonald added. “The cost savings will appear as lower interest expense, amortization expense and principal payments.” 

President Donald Trump issued the memo June 12 withdrawing from the 2023 deal that was struck after lengthy litigation about four tribes’ rights to fish in the river. The deal was opposed by other interests in the region including senior Republicans in Congress. (See Parties Split on Biden Administration Deal on Snake River Dams.) 

The deal supported federal investments in a comprehensive plan for salmon restoration, energy development and transportation infrastructure in the Columbia Basin, according to a previous press release from the Confederated Tribes and Bands of the Yakama Nation. 

The Biden administration was considering breaching four dams that produce more than 3,000 MW, but had not made a final decision. 

The Department of Energy said the Biden-era memo of understanding (MOU) required the government to spend $1 billion to comply with commitments aimed at replacing the dams in the Lower Snake River, including possibly breaching them. 

The June 12 memo directs cabinet secretaries to work to withdraw from the deal and to rescind a supplemental environmental impact statement on the four dams that was published in December 2024. 

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PJM Reviews June Heat Wave

PJM saw its highest peak loads in over a decade during a heat wave that stressed the Mid-Atlantic region from June 22 to 26. (See PJM Exceeds Forecast Summer Peak Load During June Heat Wave.)

The region saw a preliminary integrated hourly peak load of 162,401 MW on the afternoon of June 24, its third highest ever summer peak. The next day followed up with a peak of 161,770 MW. Those figures include demand response deployments, which included all available long and short-lead resources on that day.

The RTO prepared for the heat by issuing a recall on generator maintenance outages between June 21 and 26 and a hot weather alert starting one day later. As the temperatures rose, maximum generation and load management alerts were issued for June 23 to 25, coinciding with pre-emergency DR deployments.

PJM’s Kevin Hatch told the Operating Committee on July 10 that summer risk continues to be driven by peak loads like those seen during the heat wave, the scale of which have been offset by increasing solar penetration. As those resources go offline, increased importance is being placed on the evening ramp, and overall intermittent penetration has required more flexibility, with wind availability varying day-to-day.

Director of Operations Planning Dave Souder said much of the generation interconnection queue is solar, which could lead to reliability risks continuing to be concentrated in the winter, where gas availability and low temperatures are the drivers of system strain.

Stakeholders asked whether PJM experiences a decline in DR availability in the evening when many businesses begin switching machines off at the end of the work day. Hatch said PJM gets updates from curtailment service providers throughout the day and has not seen a decline in evening availability.

The average resource outage rate across the heat wave was 9.65%. The bulk of the outages were from plant equipment failures. A relatively smaller amount were from environmental restrictions. Hatch said the heat wave fell closer to the close of the spring maintenance season than past summer events, contributing to some of the outages.

PJM’s Brian Chmielewski told the Market Implementation Committee on July 9 that high load, reserve shortages and congestion pushed the system marginal price to peak at $3,700 on June 24, $3,011.96 the day prior and $2,358.36 on June 22.

Congestion peaked on June 24, with 12 out of 13 binding constraints in real-time security-constrained economic dispatch, but Chmielewski said congestion played a smaller role in pricing than in recent winter storms. The heat wave saw around half the binding constraints that were seen during the Martin Luther King Jr. Day winter storm, he said.

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SPP REAL Team Endorses Demand Response Framework

SPP’s Resource Energy and Adequacy Leadership (REAL) Team endorsed RTO staff’s framework for demand response during a special meeting, allowing the grid operator to bring it forward to the quarterly governance meetings in July and August and to then begin drafting the tariff change. 

The framework includes various metrics, criteria and thresholds for both reliability and market-registered demand response to reduce consumption during tight grid conditions. SPP has put together what it called a cohort team to gather feedback, including many of the RTO’s working groups. 

“We started talking about policy changes to 2017. … We’re coming up on a decade before we implement changes,” Natasha Henderson, SPP’s senior director of grid asset use, said during the July 10 webinar. “That’s kind of scary to think about, but because we have not been able to get consensus through our stakeholder process, the cohort team … helped drive some specific feedback and focused feedback.” 

The grid operator also scheduled a demand response engagement forum July 15 before the Markets and Operations Policy Committee to discuss the proposed policy and to gather additional feedback. MOPC will then take up the policy framework for its endorsement. 

The current framework includes: 

    • no opt-out for Level 2 energy emergency alert (EEA) testing; 
    • moving the accreditation lookback from one year to three; 
    • authorized outages and 50% accreditation within the first year of tests for fully market-registered resources; 
    • a 100-hour cap for the EEA2 product; 
    • changing resource accreditation to be grossed up for the planning reserve margin and to allow partial accreditation; and 
    • a 1,700-MW limit based on the historical remaining capacity in real time, with the allocation method yet to be defined. 
  • “We have a good structure,” said Omaha Public Power District’s Colton Kennedy, the Supply Adequacy Working Group’s chair. “We’ve had concerns around specific details. I think staff has been very responsive in listening to those concerns.” 

SPP is considering an option to allow controllable load modifiers that are not accredited to participate in demand response. Kansas Commissioner Andrew French urged transparency into the load modifiers. He said earlier in the week, Kansas regulators had approved Evergy’s 50% stake into two new combined cycle plants, a deal French said equates to $1.6 billion for 710 MW of capacity. 

“So that’s the cost of new capacity right now. It is extremely steep,” he said. “We emphasized in our order it is really going to be important to look at alternatives and to make sure we are maxing out any opportunities for things like demand response as we see the capital costs increase.” 

French said load modifiers need to be visible to the balancing authority. 

“If you get rid of that and make it non-transparent and it’s just within the load forecast, there is a concern then that you’re immediately increasing the amount of generation and reserves that a utility is going to have to build, unless the state regulator immediately works with them to make sure that they are calling on that to reduce their peaks,” he said. “The other option is that it stays as a load modifier, subject to a lot of BA scrutiny. It makes me nervous to force it into being a registered resource. That’s just a huge paradigm shift.” 

The REAL Team passed the measure, 8-6. There were five abstentions. 

The DR policy’s approval is contingent on a later endorsement for SPP’s load-resource entity’s peak demand assessment, which has drawn concerns in recent meetings. Staff is not asking for the assessment’s endorsement in July. Assuming MOPC and board approval in October and November, staff intended to file both tariff revisions simultaneously at FERC. 

“We’re just moving the DR policy in a faster time frame than that of the LRE peak demand assessment,” Henderson said. 

“Here’s a policy that we’re moving forward without analysis of impacts, without a specific methodology, and we’ve done that without bringing it back to the group that has the closest awareness of all the data,” Kennedy said, referring to the LRE assessment and the SAWG. “What staff has proposed here is shifting out the timeline so this MOPC working group really does have more time to understand what’s being done with demand assessment.” 

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RA Technical Conference Comments Urge a Variety of Market Reforms

Concerns about PJM and the growth of data center demand dominated the comments received by FERC after its recent technical conference on resource adequacy (AD25-7).

The two-day technical conference in June focused on all of the organized markets under FERC jurisdiction, but PJM took up the most time. (See FERC Dives into Thorny Resource Adequacy Issues at Technical Conference.) Post-conference comments were made available July 7.

PJM’s Independent Market Monitor said continuing with the status quo will mean “a massive wealth transfer” from other consumers as market prices spike almost entirely due to the needs of data centers. The IMM offered a way to avoid that.

“That solution is to require large data center loads to bring their own generation,” the IMM said. “It is essential to have a pragmatic market solution that is consistent with and sustains efficient and competitive PJM markets rather than to create the conditions for a return to cost-of-service regulation.”

That “bring your own generation” would have to have locational and temporal characteristics that meet the data center’s load profile.

Some states are considering withdrawing from PJM’s markets or returning to cost-of-service regulation to address the gap between growing demand and new supplies being too slow to materialize. (See N.J. Mulls PJM Withdrawal amid Energy Shortfall Predictions.)

Data center demand was responsible for $9.3 billion, or a 174.3% increase in the 2025/26 base residual auction (BRA). Absent reforms, those high prices will continue despite their political unsustainability.

“Data center load growth is the core reliability issue facing PJM markets at present,” the IMM said. “There is still time to address the issue, but failure to do so will result in very high costs for other PJM customers and could also result in a switch from competitive markets to cost-of-service regulation.”

Regardless of what the states do, PJM has a rule that has never been deployed, as its BRAs have always met the target reserve margin. If it were to fall short three delivery years in a row, it would start offering generators 15-year cost-of-service contracts. The idea of shortening that trigger from three years has been suggested by some stakeholders, the IMM said.

“Implementation of such long-term cost-of-service contracts would undermine competitive markets and suppress prices for competitive entrants because the backstop capacity is required to be offered in the capacity auctions at zero price,” the IMM said.

Constellation Energy, an independent power producer and competitive retailer that is competing to serve data center load, pushed back on the “BYOG” proposal, arguing it would discriminate against large consumers.

“Any suggestion that some load growth should be addressed efficiently through PJM’s capacity market, but large load should be subject to a bring-your-own-generation requirement makes little sense; it is unclear why the existing capacity market is the efficient vehicle to incentivize needed investment for some types of load but not others,” Constellation said. “Further, this requirement will distort competitive capacity market prices and result in inefficient long-run price signals. This outcome will likely result in less efficient investment decisions and higher overall costs for wholesale electric customers.”

The Federal Power Act says FERC must avoid “undue discrimination,” and the IMM argued the BYOG proposal falls short of that.

“It is not unduly discriminatory to identify the class of large data centers and impose requirements on that class that match the impact of that class on all other customers,” the IMM said. “It would be unduly discriminatory to all other customers, from the smallest residential customer to the largest industrial customer, to allow large data centers to add massive amounts of load to the system with resulting price impacts and reliability impacts on those other customers. Preventing undue discrimination requires that data center loads bring their own new generation.”

Constellation argued the proposal would affect existing generation because those deals are not likely to be reflected in the capacity market price, and that will distort its signals. For that reason, however, the firm agrees with the IMM on utility-owned generation.

“Likewise, requiring utility ownership of new generation in market regions will negatively impact market performance and impose unnecessary costs and risks on wholesale electric market consumers,” Constellation said.

Constellation wants to see more facilitation of long-term bilateral contracting to hedge resource adequacy risk. It also argued for improved load forecasting and improvements to energy market price formation so markets can be as effective as possible.

Dominion Energy Resources owns one of the largest vertically integrated utilities in PJM. Its zone includes rural cooperatives and also is home to the largest concentration of data centers in the world. Winter and summer peaks are expected to grow at 4.7% and 4.9%, respectively, on an annual, compound basis in the coming years.

The capacity market is at risk of falling short of meeting the demand from load-serving entities (LSEs).

“LSEs are forecasting the interconnection of significantly large amounts of new load while expecting the BRA to bring on sufficient new capacity in time to serve that load,” Dominion said. “The current rules simply do not require such LSEs to themselves do anything to ensure that most of the capacity will ‘be there.’ This deviation from the original intent of the market design is stressing the system.”

Dominion wants FERC to establish obligations for LSEs to provide a certain amount of generation or other capacity supply to serve their load — making the BRA a true residual market. It also suggested strengthening the fixed resource requirement self-supply alternative and moving to more seasonal auctions.

The Edison Electric Institute made the point that the load growth, which has grown to levels unseen for decades and has disrupted resource adequacy plans around the country, has its good side.

“This load growth is a positive development for the United States and holds the potential to create economic benefits for all customers over the long term,” the investor-owned utility trade group said. “The electric grid provides an extraordinary platform to deliver resilient, reliable power to address customer needs on a large scale. To accommodate current and future growth, as well as maximize benefits, new and proactively planned energy infrastructure of all types will be required.”

FERC has its role in getting the wholesale market design correct, but it must work with states, LSEs and others to deal with the issue.

“States’ authority includes control over in-state facilities used for the generation of electric energy, whereas the commission has exclusive jurisdiction over wholesale sales of electricity in the interstate market,” EEI said. “Given their jurisdictional authority with respect to generation resources, states will have a central role in identifying and implementing needed changes.

“However, the commission must recognize that state commissions have elected to exercise their jurisdiction over generation resource adequacy differently — some state commissions directly exercise authority over generation resource adequacy issues, while others rely primarily on regional reliability councils or RTOs/ISOs.”

Advanced Energy United, the American Clean Power Association, the American Council on Renewable Energy and the Solar Energy Industries Association agreed that states are important to solving the issue.

“When allowed to function as designed, and when coordinated with state policies and resource planning processes, competitive markets remain an effective and efficient tool to ensure resource adequacy,” the clean energy trade groups said. “Across the RTOs/ISOs, there are multiple approaches to meeting resource adequacy needs — from centralized and hybrid markets to non-market approaches — any of which can help ensure sufficient resources for a reliable grid. It is not market failure, but the failure to let markets function that threatens resource adequacy.”

Existing resource adequacy constructs can be improved incrementally to increase their transparency, accuracy, granularity and durability. Those changes will improve the chance for more bilateral contracting to take pressure off the centralized markets, they said.

“Bilateral contracts are an essential tool for resource adequacy: they offer longer-term certainty to new resources than a three-year forward or prompt auction for a single delivery year can, and are therefore important for facilitating investment in the new resources needed to support resource adequacy,” the clean energy trade groups said. “States can play a key role in enabling and encouraging more bilateral contracting, but stable, predictable, transparent markets are a critical foundation without which more robust, efficient contracting cannot occur.”

While incremental reforms are needed, the trade groups urged caution against rushing the process and relying too heavily on quick fixes.

“Urgency constrains optionality and accurate analyses, which as a result often leads to sub-optimal solutions,” the four groups said. “For example, short-term fixes imposed in a rush to mitigate the effects of market prices will only deepen uncertainty and cause further harm by negating the role that market prices can play in stimulating entrance of new capacity.”

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Stakeholder Forum: Texas’ Renewable Energy Bubble

By Doug Sheridan

While pundits wrangle over the implications of the One Big Beautiful Bill Act for America’s power sector, Texas has managed to blow itself a renewable‐energy bubble — one spawning so much solar and wind energy that the kind of generation it actually needs sits on the drawing board. 

The culprit? A mix of federal incentives and state policies that turned the state’s grid into a speculative sandbox for developers chasing subsidies rather than serving actual energy demand.  

In recent years, ERCOT has enjoyed a reputation for fast interconnections and friendly regulatory treatments for new generation. This has spurred the rush by renewables developers to use the system to monetize federal investment tax credits (ITCs) for their projects before tax codes change. 

Current law affords investors in qualifying projects a tax credit equal to 30% of the original cost of the project. In reality, the tax breaks are even larger. According to Neil Booth of Orbis Consulting, under current IRS guidance, project developers may immediately “step up” the value of a project’s equipment to a higher value on the basis that the economic value of the equipment is higher once connected to the grid.  

This accounting maneuver and other add-ons mean tax-equity investors can recoup 100% of their investment as soon as 90 days after a project goes live. It doesn’t take a genius to understand how such a siren call of quick returns can incentivize investors to target the one grid on which they can get their projects online as fast as possible — irrespective of whether that grid needs the incremental intermittent power. 

Companies like Meta, Microsoft, Amazon and Google add their own distortions. These hyperscalers sign long-term power-purchase agreements (PPAs) with renewables developers to help brand themselves as “green” operators. On its face, this makes it seem like corporate America is doing its part to decarbonize. In practice, it’s not clear how many hyperscalers are in fact consuming the electrons for which they have contracted. 

Instead, hyperscalers may simply pay for the renewable power per the PPA, then sell it back into ERCOT’s wholesale market. This affords their operations the environmental seal of approval they seek, even though their facilities might be running on gas-fired generation in other states. Meanwhile, the intermittent power from the renewables is being dumped onto the Texas grid without a stable, long-term customer — undermining both supply and demand fundamentals, as well as prices for the dispatchable power needed to balance the system. 

The EIA reports that Texas added a net 29.2 GW of supply from 2022 to 2024. Subsidized solar, wind and battery capacity represented 97.9% of this. More capacity has since been added, and ERCOT now reports 86.8 GW of renewables on its system — for a grid with an all-time demand peak of less than 90 GW. 

NERC has taken note, pegging ERCOT’s on-peak reserve margin at more than 40%. In a rational market, this would slam the brakes on further buildout of renewables. Instead, ERCOT’s interconnection queue shows 374 GW of new renewable and battery projects interested in connecting to the system—more than 10 times all other resource types combined. 

Meanwhile, despite leading the nation in natural gas production, Texas has seen developer interest in newbuild gas-fired generation nearly vanish. The problem is developers can’t pencil out viable projects when first-in-line solar, wind and batteries crush revenue expectations. 

As a result, the new combined-cycle and peaking plants needed to keep the grid stable during peak hours and weather lulls and to back up renewables are effectively locked out of the Texas market. This has left ERCOT’s administrators with little choice but to continue connecting more part-time renewables. 

Texas’ booming population, rising EV adoption and prospective surge in on-grid data center demand all point to the need for more dependable, around-the clock generation. Instead, the state is hardwiring increasing amounts of intermittent energy — and the operational costs and complexities that come with it — into its grid. What’s more, over 40% of its nuclear, coal and gas-fired capacity is 30 years old or older. Aging infrastructure and falling revenues can lead to delayed maintenance and lower investment, putting reliability at risk. 

Unless Texas policymakers change course, the consequences of swelling market distortions will become harder to manage. A grid saturated with financially engineered, subsidy-seeking projects won’t in the long run deliver stable prices or dependable service. Without serious reform, Texas faces a future of inflated rates, reliability challenges and growing dependence on taxpayer-funded interventions. 

It’s time to restore the integrity of ERCOT’s wholesale power market and re-center its grid planning around the kind of dispatchable power that can deliver when Texans need it. Otherwise, this renewables bubble won’t just pop. It will burst — with the state’s energy security caught in the fallout. 

Doug Sheridan is President of EnergyPoint Research in Houston, Texas. 

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FERC Rejects Voltus Appeal for Interim MISO Order 2222 Compliance

MISO is free to keep working toward its 2030 goal of fully incorporating aggregators of distributed energy resources into its markets without an interim participation option, FERC ruled in an order on rehearing.  

The commission’s July 10 order denied aggregator Voltus’ request to compel MISO to reinstate a temporary role for aggregators in its markets while it works on full FERC Order 2222 compliance (ER22-1640).  

MISO nixed the provisional step from its first compliance proposal in the spring after the commission said it didn’t fit within the requirements of Order 2222. The RTO planned to use an existing demand response participation category to get aggregators of distributed energy resources participating on a limited basis a few years ahead of its full implementation. (See MISO Discards Interim Participation Option from Order 2222 Plan.)  

FERC disagreed with Voltus’ contention that it got it wrong when refusing the partial participation. The commission said its history of accepting interim models while grid operators work on full compliance with orders and directives on a longer timeline didn’t apply in this case because MISO’s pro tem demand response plan contained elements that didn’t square with Order 2222. 

FERC said its precedent of approving an interim plan for electric storage resources in MISO markets before the RTO complied with Order 841 was fundamentally different because that case dealt with a Section 206 complaint under the Federal Power Act, not Order 841 itself. Voltus cited Indianapolis Power and Light’s (now AES Indiana) 2017 complaint over MISO’s treatment of the utility’s Harding Street Battery Energy Storage System when arguing for rehearing. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)  

FERC said it continues to find MISO’s provisional demand response model lacking, namely its failure to meet Order 2222’s 100-kW minimum size requirement for aggregations. The commission also said it was unpersuaded by Voltus’ claim that it ignored the benefits of a timelier rollout of at least some Order 2222 directives. FERC said it wouldn’t debate a piecemeal implementation further.  

FERC backed MISO’s 2030 effective date for its comprehensive distributed aggregation model and said it was “timely,” irrespective of a partial rollout. The commission once again underscored MISO’s reasoning that its underlying computer systems need work over the next four years before they can support aggregations.  

“MISO stated that the foundational enhancements to its settlement systems are expected to be completed in the middle of 2028,” FERC said. It disagreed with Voltus that MISO didn’t expound on which specific settlement upgrades would be necessary, and said MISO provided detailed timelines that outlined delays and additional work.  

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Grain Belt Funding Appears on Shaky Ground with DOE; Invenergy Firm on Value

Invenergy is standing by the value of its $11 billion, 800-mile Grain Belt Express transmission project with a letter to Energy Secretary Chris Wright, who is said to have pledged to block the line.

Grain Belt Express Vice President Jim Shield wrote July 11 that Wright should put aside “unfounded noise” and confirm closing of the Department of Energy’s $4.9 billion in federal loan guarantees as Republican leadership in Missouri targets the line’s federal funding.

U.S. Sen. Josh Hawley (R-Mo.) and Missouri Attorney General Andrew Bailey have taken aim at Grain Belt. Hawley sent a letter insisting that Grain Belt’s conditionally approved DOE loan guarantee be pulled, while Bailey has opened a consumer protection investigation into the nature of the line’s development. (See Missouri AG Opens Inquiry into Grain Belt Express.)

In a July 10 press release, Hawley said he secured a pledge from Wright to “halt” the line.

Hawley said in a follow-up social media post the same day that he had a “great conversation” with President Donald Trump and Wright, who he said pledged to “put a stop” to the project. Hawley called the Grain Belt Express an “elitist land grab harming Missouri farmers and ranchers” and claimed it is set to cost taxpayers billions of dollars.

Hawley has demanded for months that the Trump administration terminate government funding for Grain Belt and has questioned the line’s viability.

“Your department should be taking every possible action to stop this loan — not only to save taxpayers’ money, but also to save generational land from being ripped away from families and hard-working farmers and ranchers in Missouri,” Hawley wrote in the June 25 letter to Wright.

‘Open Season’ on New Infrastructure

Shield said it’s unfortunate Hawley and Bailey “are declaring open season on America’s ability to build needed energy infrastructure” and that Grain Belt is the “target of egregious, politically motivated lawfare.”

He characterized Hawley and Bailey’s “crusade” as “unwarranted and unhinged.”

“Recent false accusations from Sen. Hawley and A.G. Bailey saying that the Grain Belt Express will cost America billions instead of saving us billions, whether mistaken or purposefully declared, are misleading at best,” Shield said.

Shield wrote that Grain Belt is a “critical energy security project” that will deliver reliability and savings and is supported by a broad range of stakeholders.

“It is an open-access line that will deliver all forms of American energy based on customer demand and available market power, enhancing the ability of the largest grid operators to share power, including from generators directed to operate under DOE’s 202(c) authority,” Shield said, in an apparent attempt to appeal to the conservative leadership’s pro-business philosophy.

Shield said the line — capable of delivering four nuclear power plants’ worth of electricity and the second-longest line in U.S. history — would connect four of the country’s grid regions while delivering cost savings and reliability to “29 states and D.C., more than 40% of Americans and 25% of Department of Defense installations.”

Shield said recent questions raised by Bailey were addressed through the Missouri Public Service Commission’s “long and rigorous” regulatory process that began in 2022 and concluded in late April. What’s left is “procedural abuse” to roll back state regulatory approval that wastes public resources and harms the public, Shield wrote.

“The state of Missouri was represented throughout these proceedings, yet A.G. Bailey never intervened or otherwise contested the proceeding. Missouri law and constitutional due process protect the Grain Belt Express’ property interest in its permit granted by the MPSC. No amount of political posturing and unrelenting attacks can change that fact,” Shield said.

He said the timing of the “anti-growth” attacks doesn’t make sense given the country’s booming energy demand and that the line is even more important now than when it was conceived in 2010.

The CEO of Associated Industries of Missouri, a pro-business lobbyist organization, said Grain Belt is an “obvious solution,” given demand growth from new manufacturing and emerging technologies.

“It is nonsensical to try to impede a project that will put Missourians to work constructing infrastructure that delivers affordable and reliable power of all kinds to Missouri businesses while enhancing grid security for America,” CEO Ray McCarty said in a statement.

In a separate press release issued by Invenergy, the company questioned whether America has “lost its will to build.”

“If projects can’t count on certainty even after being approved and reviewed upon appeal, America can’t count on ever getting steel in the ground. America will lose the test of its will to build,” Invenergy said. The company lamented “political actors making last-gasp attempts to reopen existing state approvals or halt a yearslong federal review in its tracks.”

Invenergy noted that states lead on transmission permitting and said Grain Belt already has cleared Kansas, Missouri, Illinois and Indiana’s routing processes. It said it made “every effort” to negotiate with landowners.

“Grain Belt Express has among the strongest set of landowner protections and compensation packages, including a code of conduct and agricultural impact mitigation protocol. In fact, the Kansas Farm Bureau called for these protocols to be made a standard for the industry,” Invenergy said. “Living up to our commitment that eminent domain be used only as an absolute last resort, land has been secured through voluntary agreements in all but a low single digit percentage of cases, a rate equal to or better than the utility industry standard.”

Invenergy says it has completed over 95% of land acquisition for Phase 1, the segment connecting Missouri and Kansas. The phase’s construction is scheduled to start in 2026.

Invenergy added that when it acquired Grain Belt from now-defunct Clean Line Energy in 2020, it invested in a redesign and listened to stakeholders’ concerns, ultimately deciding to make more power deliveries to Missouri. (See Invenergy Announces Grain Belt Express Expansion.)

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Texas Public Utility Commission Briefs: July 10, 2025

Regulators Approve SPS, SWEPCO System Resiliency Plans

The Texas Public Utility Commission has approved system resiliency plans for Southwestern Public Service and Southwestern Electric Power Co. (SWEPCO), as it continues to meet a requirement from the 2023 legislative session. 

Both plans were the result of agreements with intervening parties. SPS, an Xcel Energy subsidiary, reached a settlement over its three-year plan with the Office of Public Utility Counsel (OPUC), Alliance of Xcel Municipalities, Texas Industrial Energy Consumers (TIEC), Walmart, the International Brotherhood of Electrical Workers Local Union 602, Golden Spread Electric Cooperative and PUC staff (57463). 

The SPS plan includes distribution overhead hardening, distribution system protection modernization, communication modernization and wildfire mitigation. The utility proposed $538.3 million of investments to be implemented from 2025 to 2028. 

The settlement removed the five lowest benefit-cost ratio projects from the distribution overhead hardening measure, totaling $5.9 million by the agreement. However, the commission agreed to reinstate the projects, saying they also were designed to strengthen overhead infrastructure to prevent, withstand and mitigate wildfire risks. 

In February 2024, downed power lines from a broken SPS utility pole ignited the Smokehouse Creek Fire in the Texas Panhandle. It became the largest wildfire in recorded state history, burning more than 1 million acres before being contained. 

“Given where this is and the recent history in the area, I think adding those measures back in makes sense to me,” PUC Chair Thomas Gleeson said during the commission’s July 10 open meeting. 

Xcel has acknowledged its role in the fire and has settled 151 out of 225 claims filed through a dedicated claims process. 

SWEPCO’s plan was included on the PUC’s consent agenda. The American Electric Power subsidiary reached a unanimous agreement in March with commission staff, OPUC, Cities Advocating Reasonable Deregulation, TIEC and Walmart. The commission modified the plan to remove several “enhanced vegetation management” measures with benefit-to-cost ratios below 1.0, reducing its estimated cost from $88.9 million to $83.7 million (57259). 

The four-year plan also includes distribution feeder and lateral hardening, and increased distribution automation circuit reconfiguration. 

The 2023 Texas Legislature’s House Bill 2555 allows the state’s electric utilities to file resiliency plans for approval with the PUC. The plans must include measures that would “help the utility prevent, withstand, mitigate or more promptly recover from resiliency events, which include extreme weather, wildfires, and cybersecurity or physical security threats.” 

Oncor was the first utility to secure approval of its resiliency plan in November 2024. (See Texas PUC Approves 1st System Resiliency Plan.) 

Wildfire Mitigation Plans

The commission established a July 25 deadline for utilities, municipalities and cooperatives that own transmission and distribution facilities to provide input on PUC rules for wildfire mitigation plans, as required by a new state law (56789). 

“I know it’s a short timeline, but please provide … your input,” Gleeson said. “As you hear us say often up here, the best outcomes happen when we get as full participation as possible, so please avail yourselves of this opportunity to provide input to commissioners.” 

Staff plan to bring a formal proposal for publication to the PUC’s Aug. 21 open meeting. 

Status Quo for FFSS Program

After consulting with the grid operator and its Independent Market Monitor, PUC staff have proposed maintaining the same parameters for ERCOT’s firm fuel supply service (FFSS) program during the winter 2025/26 contract period. That will retain the program’s $54 million budget, $12,240/MW offer and 48-hour deployments (56000). 

The program has procured 3,319 MW and 4,194 MW in its first two years, at a cost of $29.4 million and $42.4 million, respectively. 

Staff plan to gather feedback from ERCOT, the IMM and stakeholders to develop rule language before future contract periods, allowing the commission to consider next phase options before the 2026/27 winter. 

The FFSS program provides additional grid reliability and resilience in the event of fuel disruptions during extreme cold weather, compensating generation resources that meet a higher standard. 

SB6 Workshop July 21

The PUC has scheduled a workshop for July 21 to gather public and stakeholder input as it prepares to implement Senate Bill 6.  

The “seminal piece of legislation” from the 2025 biennial session, as Gleeson described it, directs the commission to determine a cost allocation for large loads to ensure they pay their fair share of infrastructure expenses and requires their developers to pay a $100,000 fee for the initial screening studies (58317). 

Gleeson said it will be important to standardize how load is counted for transmission purposes and to focus on the bill’s co-location and net-metering agreements. He urged staff to work with ERCOT staff on transmission and resource adequacy issues. 

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D.C. Circuit Declines Review of SPP Cost Allocation

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.