FERC on July 21 approved a controversial MISO proposal to create a fast lane for certain reliability-related projects in the RTO’s interconnection queue — just two months after rebuffing an earlier version of the plan (ER25-2454).
The commission in May rejected the first iteration of the Expedited Resource Addition Study (ERAS) proposal, which was designed to speed up interconnection of resources that state regulators have identified as necessary to ensure resource adequacy in areas under their oversight.
In its May decision, the commission found the original ERAS plan lacked clarity around standards for identifying true RA projects and that — absent a cap on potential applicants — the expedited process was at risk of becoming bogged down with too many proposed projects. (See FERC Rejects MISO’s Interconnection Queue Fast Lane.)
Responding to those concerns, MISO quickly developed a revised proposal that caps the ERAS fast lane at 68 project requests and includes a provision requiring the RTO’s relevant electric retail regulatory authorities (RERRAs) to verify in writing that a project will either address an RA risk or help load-serving entities meet previously unexpected load growth.
Of the 68 slots, MISO proposed that a maximum of 10 would be carved out to accommodate requests from independent power producers that have agreements with entities other than LSEs, while eight will be dedicated to requests for resources intended to serve retail-choice load.
The RTO also proposed to cap the number of expedited studies to just 10 per quarter and limit transmission service requests to 150% of the need identified by a RERRA. It also made clear the ERAS process would be a temporary fixture, concluding at the earlier of either August 2027 or when the queue is cleared.
While MISO’s rapid turnaround on the revision earned support from the RTO’s vertically integrated utilities, it provoked protests from independent power producers and clean energy groups, who argued the newer plan still retained “many of the shortcomings” of the earlier version while introducing additional legal concerns. They also argued it still offered “preferential access to thermal resources at the expense of renewable resources.” (See MISO’s Queue Fast Lane, Take 2, Nets Déjà vu Arguments.)
Michigan’s Public Service Commission also opposed the plan, arguing it lacked “sufficient enforcement of shovel readiness and project completion” and that a provision to cap the megawatt value of expedited projects at 150% of an identified RA need might exclude meaningful participation by developers of renewable energy projects, which have lower capacity factors than thermal projects.
In its comments to FERC, Invenergy argued the new proposal still vested RERRAs with “nearly unbounded discretion to select projects, without any objective criteria to judge whether such projects are capable of satisfying MISO’s resource adequacy needs.”
But the revised plan had strong backing among MISO’s utilities, among them Alliant Energy, Ameren, Big Rivers Electric, Consumers Energy, DTE Energy, Northern Indiana Public Service Co. and Ottertail Power.
‘One-time Design’ Weighs Heavily
FERC’s July 21 order found the eligibility requirements set out in the revised proposal were adequate to “deter speculative interconnection requests from entering the ERAS process and minimize disruption” to resources already sitting in the definitive planning phase of MISO’s existing interconnection process.
“We find that MISO’s revised ERAS proposal sufficiently addresses these concerns identified in the May 2025 order by capping the number and size of ERAS projects, strengthening the RERRA verification requirement, [and] requiring ERAS interconnection requests to be located in the same local resource zone as the resource adequacy or reliability need that it will address,” the commission wrote.
“Additionally, we note that the limited, one-time design of the process weighed significantly on our decision here,” it added.
The commission also found that MISO had “strengthened” the “notification” requirement in the initial ERAS plan “to better ensure that RERRAs affirmatively verify interconnection requests will address specific resource adequacy needs that are not otherwise being addressed.”
The commission said it was “reasonable and appropriate” for MISO to allow RERRAs to select the ERAS projects and “implement their own processes for making such determinations, as this approach strikes a reasonable balance between state authority over resource procurement and commission authority over generation interconnecting to the interstate transmission system. Accordingly, we find that it is not necessary for MISO to establish scoring criteria or a ranking process for proposed ERAS projects, as protesters suggest.”
The commission rejected the argument by IPPs that the proposal intrudes on the commission’s exclusive Federal Power Act jurisdiction over the transmission service terms and conditions set out in MISO’s tariff.
To support their argument, the IPPs cited the U.S. Supreme Court’s Hughes v.Talen Energy Marketing decision, which held that the Maryland Public Service Commission’s authority over generating facilities did not allow it to “exercise control over the terms and conditions of interconnection service.”
“We find that the revised ERAS proposal is permissible under Talen because RERRA participation in the ERAS process would be wholly pursuant to a commission-jurisdictional process (i.e., the generator interconnection process), proposed by MISO and approved by the commission — not by state authorities — and under which a [generator interconnection procedure] is on file with the commission and any future revisions would be subject to commission approval,” FERC wrote.
The commission also rejected the contention that the proposal violates the “filed rate” doctrine because it allows states — through their RERRAs — to set the criteria for determining a resource’s participation in ERAS without subjecting that criteria to FERC approval.
“NextEra and MISO IPPs argue that the revised ERAS proposal violates the filed-rate doctrine because it allows RERRAs to establish criteria that would not be on file with the commission and that would determine whether or not an interconnection request is eligible for ERAS. We disagree. We find that the revised ERAS proposal does not present a filed-rate doctrine concern because it provides adequate notice of the ERAS eligibility requirements, including the RERRA verification requirement,” the commission wrote.
MISO intends to kick off the first ERAS process on Sept. 2.
Strong winter discounts on electricity delivery rates are needed to more fairly charge Massachusetts homes with heat pumps for their share of grid costs, according to a new report commissioned by a coalition of environmental groups.
Written by climate policy think tank Switchbox, the report estimates that heat pump owners are being overcharged by an average of 23% during the heating season and finds that seasonal discounts could make electrified heating cheaper than natural gas heating for most residential consumers. It also finds that heat pump rates could help address significant cost barriers to heat pump adoption in the state.
“Heat pump customers are subsidizing everybody else, and that’s why they’re being overcharged,” Juan-Pablo Velez, one of the authors of the report, said during a webinar July 22.
Because New England has a summer-peaking power system, incremental demand during the heating season generally does not add to the cost of the grid, he said. However, volumetric delivery charges incurred during the winter frequently cause heat pump owners to pay more than their fair share of system costs, Velez said. “There is plenty of capacity to go before we run out of room with the existing [winter] capacity,” he said.
ISO-NEforecasts the region transitioning from summer-peaking to a winter-peaking system by the mid-2030s, largely because of heating electrification. The timing of the shift likely will depend on the pace of heat pump adoption.
The Massachusetts Department of Public Utilities already has directed the state’s investor-owned utilities to adopt specific heat pump rates. However, advocates for heating electrification argue that these rates do not fully address the issue of overcharging heat pump owners and have urged the DPU to direct the utilities to roll out steeper discounts aimed at more closely calibrating delivery costs with the grid impacts of electrified heating.
Under this updated discount, houses with heat pumps would pay roughly the same delivery costs as those heated by gas during the heating season. Supply costs would not be affected by the discount, and heat pumps still would pay for their full supply costs throughout the year.
Kyle Murray, director of state program implementation at the Acadia Center, emphasized that heat pump rates do not represent a “handout to heat pump owners.”
“Even though heat pump owners are using more energy than their non-heat pump counterparts, they’re not actually causing more stress on the system,” Murray said. “Heat pump rates just simply represent fairness in ratemaking.”
The DPU in March opened an investigation into requiring new heat pump rates following the 2025/26 heating season (DPU 25-08). In comments in the proceeding, the Massachusetts Department of Energy Resources supported the working group’s proposed rate, writing that the lower, DPU-approved heat pump rate “would provide approximately one-third to one-half the savings each winter-heating season as compared to the [working group’s] proposed heat pump rates.”
The Switchbox report found that “across all homes in Massachusetts, the median electric bill for heat pump customers would decrease by 12% under the DPU’s 1.0 rates and by 23% under DOER’s proposed 2.0 rates.”
Under default rates, about 55% of customers switching to a heat pump would see an increase in their annual energy costs, the report found. Adopting the DPU-approved heat pump rate would improve this cost comparison, reducing annual energy costs for about 64% of customers that make the switch, the report notes.
Unsurprisingly, the report found that the higher discount rate supported by the DOER would bring the greatest savings for heat pump owners and estimated that 82% of Massachusetts households converting to heat pumps would save money under the rate.
Massachusetts has set aggressive targets for heat pump deployment and will need to significantly accelerate adoption in the coming years to meet its climate targets. The state estimated in early 2025 it will need to double its rate of heat pump conversions between 2025 and 2030 to meet its deployment goals.
Seasonal heat pump rates likely will be a short-term solution for the state as its utilities work to deploy advanced metering infrastructure, speakers at the webinar noted.
“In about three or four years, everybody in Massachusetts should have an advanced meter,” which will require a new set of rate structures, said Larry Chretien of the Green Energy Consumers Alliance. He added that while seasonal heat pump rates may be a relatively short-term solution, they are an important tool for eliminating excessive cost burdens on heat pump owners over the next few years.
With data centers contributing to “staggering load growth” for Western utilities, a new report suggests that more utilities adopt clean transition tariffs for data centers or even make the tariffs mandatory for certain large customers.
The proposal is one in a set of recommendations from Western Resource Advocates, which released its report, “Data Center Impacts in the West,” on July 22.
The report examines seven of the eight largest utilities in the Interior West: Public Service Company of Colorado, Public Service Company of New Mexico, NV Energy, PacifiCorp, Arizona Public Service, Salt River Project and Tucson Electric Power. These utilities are seeing a surge in large-load interconnection requests, and data centers are the largest factor in their load growth, the report says.
“Data centers are driving staggering increases in electricity demand,” WRA says in its report.
And the surge in demand is a threat to climate progress, unless it can be met with clean energy resources, according to WRA. That’s where clean transition tariffs can play a role.
“If properly designed, these tariffs can enable data centers to do more than just mitigate their climate impacts with conventional clean resources like solar, wind and battery storage; they can help drive innovation by scaling new clean technologies,” the report says.
The report notes that companies such as Google, Meta and Amazon have corporate climate and clean energy goals — along with “expansive financial resources.” Under a clean transition tariff, a utility may develop new, clean resources on behalf of a large-load customer, with the large customer paying any premium cost of the clean resource.
For example, Nevada regulators in March approved NV Energy’s clean transition tariff, a framework developed in partnership with Google. NV Energy added to its integrated resource plan an enhanced geothermal energy project from Fervo Energy that will help power Google’s northern Nevada data center. Without Google’s involvement, the utility would not have included the project because of its cost. (See Nevada Regulators Give Nod to NV Energy Clean Transition Tariff.)
WRA said clean transition tariff structures should be developed before a data center asks for interconnection and clean resources, because fast interconnection typically is a priority for the centers.
Only zero-carbon resources should be eligible for the tariff, the report says. One approach for finding resources would be for the utility to issue a request for proposals based on its completed IRP, select resources to serve customer loads and then make any resources not selected available to customers under its tariff. Utilities also could solicit bids for resources under their tariffs between IRP cycles.
Regulators should encourage utilities to develop clean transition tariffs, WRA says, and they could even consider making them mandatory for larger loads or those that are steady around the clock.
Surging Demand
The seven utilities’ energy demands are projected to be 32% higher in 2030 and 55% higher in 2035, compared to 2025 levels, representing a compound annual growth rate of 4.5%. Those figures are significantly higher than what utilities predicted just a few years ago.
The growth rate also is higher than the rates projected by WECC (2.1%) and Grid Strategies (2.4%), which looked at regional and national trends, respectively.
The difference among the forecasts could mean that utilities in the WRA study are overestimating their load growth, the report says, or that they are “burgeoning hubs” for data centers with concentrated load growth.
As for peak demand, the utilities now expect a peak of 9,500 MW in 2030, 19% higher than in 2025, and 16,900 MW in 2035. The projected compound annual growth in peak demand is 2.9%.
The WRA report makes other recommendations for utilities and regulators, including:
establishing best practices and requirements for utility load forecasting;
revising IRP processes to better accommodate the rapid and uncertain nature of data center growth;
allowing data centers to install behind-the-meter clean resources and storage systems; and
developing interconnection standards that allow for load interruption in exchange for faster interconnection.
NextEra Energy Transmission (NEET) has completed the second of its three competitive projects in SPP’s footprint, the 92-mile, 345-kV Wolf Creek-Blackberry project in Kansas and Missouri.
NEET Southwest, a NextEra subsidiary, confirmed in an email to RTO Insider that the project was energized on July 16. It said the project was completed “within budget” and nearly five months ahead of SPP’s required in-service date.
The project was awarded to NEET Southwest in October 2021. The developer’s bid came in at $85 million, far below the high proposal of $151 million. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)
Matt Pawlowski, NEET’s vice president of development, celebrated the announcement during the July 17 Strategic Planning Committee meeting.
Interrupting himself mid-comment, Pawlowski said, “Did I mention that we energized Wolf Creek to Blackberry a couple days ago? I’m sorry, I think I forgot to mention that earlier. Did I? Did I mention that yet? No? OK.”
The projects are the only two of five approved by SPP under FERC Order 1000 that have been completed.
SPP also has awarded NEET Southwest Crossroads-Hobbs-Roadrunner, a 137-mile, 345-kV project in Southwestern Public Service Co.’s service territory in Texas and New Mexico. NEET’s $291 million bid was higher than incumbent SPS’ $220 million proposal, but the former offered a one-year construction timeline. (See SPP Awards NextEra 3rd Competitive Project.)
The project is scheduled to be completed by mid-2026.
PJM capacity prices soared to $329.17/MW-day (UCAP) RTO-wide for delivery year 2026/27, hitting the price cap approved by FERC after prices rose nearly 10-fold in the July 2024 auction.
The clearing price is the highest in PJM history and an increase of $59.22 (22%) from last year’s record for the RTO.
Prices would have hit $388.57/MW-day without the cap, PJM said in its report on the auction. The cleared supply totals $16.1 billion, up 9.5% from the $14.7 billion last year.
“This is a continuation of trends that we’ve been seeing: a tightening of the supply and demand conditions,” Stu Bresler, executive vice president of PJM market services and strategy, said in a press briefing after results were announced July 22.
PJM’s forecast peak load for 2026/27 increased by 5,446 MW from last year due to data center expansion, electrification and economic growth. “It’s probably a true statement to say that the majority of the demand increase we saw was … those data center additions,” Bresler said.
However, prices fell in the Baltimore Gas and Electric (BGE) and Dominion zones, which cleared at $466.35/MW-day and $444.26/MW-day respectively last year. Thus, although the increased capacity costs will boost many retail customers’ bills by 1.5 to 5%, Dominion customers could save money, Bresler said.
Supply offered dropped 500.5 MW (UCAP) to 135,191.8 MW. New generation and uprates totaled 2,669 MW, the first increase in the past four auctions. In addition, 17 generating units with 1,100 MW of Capacity Interconnection Rights withdrew their retirements since the 2024 results were announced.
“We were pleased to see the new resources and the uprates that came in,” Bresler said. “We’re pleased to see the reversals of retirements, because that’s the kind of thing we need and the kind of thing that one would expect from the collection of information that’s out there, including the results of the last capacity auction.” The Base Residual Auction (BRA) procured 134,311 MW of unforced capacity generation (UCAP) and demand response. Regions under the Fixed Resource Requirement acquired an additional 11,933 MW (UCAP) for a total of 146,244 MW (UCAP).
The reserve margin is 18.9%, 309 MW ICAP lower than the target of 19.1%.
Cleared resources were dominated by natural gas (45%), nuclear (21%) and coal (22%), with contributions from hydro (4%), wind (3%) and solar (1%). Declining fleetwide accreditation values pushed the amount of supply offered down by about 326 MW from the 2025/26 BRA. PJM’s auction report stated that 3 GW less gas was offered in the 2026/27 auction.
An additional 2 GW of wind generation cleared in the auction, followed by 867 MW of coal and 578 MW of oil. While the amount of DR offered was nearly flat, the resource class saw a significant drop in its effective load-carrying capability (ELCC) rating, causing the amount of UCAP clearing to fall by 224 MW.
Bresler said almost every resource that submitted offers cleared, aside from one that had its minimum offer set above the maximum clearing price. He said the results follow a trend of tightening supply and demand in recent auctions, which PJM has argued could lead to a capacity shortfall in the 2029/30 delivery year.
“I think this auction, just as the last one, served its purpose and very transparently reflected supply and demand,” Bresler said.
RMR Impact
Bresler said including generators on reliability-must-run (RMR) agreements as supply helped dampen prices and reduced constraints, allowing BGE and Dominion to clear along with the rest of the RTO.
“I think that there was a significant impact from including the RMRs at zero [dollars] in the supply stack, and … there were probably transmission upgrades going into place that changed the transmission import capabilities for those two zones as well,” Bresler said. “So, even without the lower cap, we still would not have had price separation in this auction.”
In the 2024 auction for 2025/26, the clearing price for most of the RTO jumped to $269.92/MW-day, the result of load growth, generation deactivations and changes to risk modeling that shrank reserve margins. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) The 2024/25 auction had seen a price of $28.92/MW-day for most of the RTO, with BGE hitting $73/MW-day.
Pa./PJM Settlement Lowered Clearing Prices
The 2026/27 auction design has been the subject of several rule changes and FERC complaints, including a settlement between PJM and Pennsylvania Gov. Josh Shapiro (D) to lower the maximum clearing price to $325/MW-day and establish a $175/MW-day floor. The settlement is effective for the 2026/27 and 2027/28 auctions (ER25-1357). (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor.)
Base Residual Auction clearing prices by beginning delivery year for the RTO, EMAAC, SWMAAC and MAAC Locational Delivery Zones. All four LDAs cleared at $329.17 for 2026/27, a $59.25 (22%) increase from $269.92 for 2025/26. | PJM
While the price band initially would be set at $175 to $325/MW-day, those values would be readjusted annually based on the accreditation of the reference resource.
PJM and the governor argued the settlement would stabilize prices while several market changes are implemented. A complaint filed by Shapiro’s office said a lower maximum price was needed as the capacity market is unable to send adequate price signals under a compressed auction schedule and while the interconnection queue remains backlogged, preventing developers from bringing new supply in response to high prices (EL25-46).
In a statement following the posting of the auction results, Shapiro said the settlement avoided “grossly excessive price increases” and saved consumers $8.3 billion.
NRDC Senior Advocate Tom Rutigliano said the settlement prevented windfall payments to generation owners without compromising on reliability. He said the resulting price signals are ample to maintain existing resources and support new development and so long as there are barriers to new entry, such as the backlogged interconnection queue, higher prices would have served no purpose.
In a statement, Illinois Citizens Utility Board Executive Director Sarah Moskowitz noted the settlement blunted capacity prices but argued the spike in capacity prices remains unacceptable and follows policy shortcomings at PJM.
“The power grid operator’s policy decisions too often favor outdated, expensive power plants and needlessly block low-cost clean energy resources and battery projects from connecting to the grid and bringing down prices. This extended price spike was preventable. It ramps up the urgency of implementing long-term reforms at PJM and comprehensive energy legislation in Illinois, such as the Clean and Reliable Grid Affordability Act, to protect customers from price spikes that serve only to give power generators windfall profits,” she said.
Auction Design Changes
PJM also received FERC approval to rework several market components, including modeling some resources operating on reliability-must-run agreements as supply in the capacity market (ER25-682). One of the factors that drove a spike in capacity prices in the 2025/26 BRA was two generators leaving the supply stack to begin running as RMR resources — the 1,289-MW Brandon Shores coal plant and the 843-MW H.A. Wagner oil-fired plant. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)
The filing also established an RTO-wide non-performance charge rate and maintained the reference resource for the 2026/27 auction as a combustion turbine, rather than going through with a scheduled shift to a combined cycle unit.
This is the first auction in which intermittent, storage and hybrid resources holding capacity interconnection rights (CIRs) were required to submit capacity offers. FERC granted PJM’s proposal to eliminate an exception from the capacity must-offer requirement for those resource types after the RTO said there was about 1.6 GW of capacity not offered. PJM argued that requiring all resources holding CIRs to submit capacity sell offers will prevent the exercise of market power and more accurately reflect supply and demand (ER25-785).
Cleared new generation, uprates, imports and reactivated capacity by delivery year | PJM
The order eliminating the must-offer exemption also established an alternative market seller offer cap (MSOC) set at a resource’s capacity performance quantified risk (CPQR). The filing argued the change would allow intermittent and storage resources to more accurately reflect the risks they face by taking on a capacity obligation.
Rising capacity clearing prices, and wholesale market costs generally, have been a source of consternation for consumer advocates and political leaders across many PJM states. Both Pennsylvania and New Jersey have raised the specter of leaving the RTO if reliability and cost concerns go unanswered. In July, nine governors signed onto a letter requesting that the qualifications for candidates to replace CEO Manu Asthana and to fill two open Board of Managers positions include the ability to restore public confidence and address “difficult decisions that could substantially raise consumer bills.”
“In the past, other regions looked to join PJM due to its many strengths; today, across the region, discussions of leaving PJM are becoming increasingly common,” the letter said. “These unwelcome developments reflect legitimate concerns about PJM’s trajectory. We write, as a bipartisan group of governors elected by the many millions of citizens of our respective states, to tell you that fundamental changes, and new leadership, are needed to restore confidence in PJM’s ability to meet the many challenges of this moment.”
Rutigliano said prices increased due to the combination of increasing data center demand and risk modeling capturing reliability issues with gas generation. Without the increase in wind generation, he said PJM would not have been able to meet reliability standards, underscoring the need for PJM to continue clearing its interconnection queue and for states and the federal government to address siting and permitting barriers.
“The bright spot in this auction is a 75% increase in wind and solar. That jump will save PJM from an unacceptable risk of blackouts in 2026. PJM will stay reliable in 2026 thanks to the increase in renewable power. However, these low-cost resources still only account for 4% of the PJM’s supply, so PJM must continue to significantly speed up approvals of the 85 GW waiting to connect. The only real solution to higher energy prices is to keep adding more renewable energy and storage to the grid,” he said in a statement.
Rutigliano told RTO Insider that states pushing for winterization of gas plants and PJM easing its restrictions on external resources selling capacity into PJM could buy the RTO at most two years before reliability issues become paramount, but the long-term solution lies in ensuring that renewable penetration accelerates.
Advanced Energy United Policy Director Jon Gordon said the auction results show that new resources are needed to meet forecast demand. However, long interconnection queues prevent developers from bringing new supply to market. He said fast-track study processes, advanced transmission technologies, load flexibility and virtual power plants can facilitate new entry while PJM advances its cluster-based interconnection study process.
“When prices go up, it’s meant to send a signal to energy developers: ‘We need more supply.’ But at the same time, PJM is holding up a big red ‘STOP’ sign to energy developers,” Gordon said. “Many projects have been stuck in the closed queue for over six years, a significant delay that adds additional risk and cost for developers and is likely to contribute to some otherwise viable projects never getting built.
“Given the magnitude of this crisis, PJM, transmission owners, project developers and states need to do everything they can to move projects in the current interconnection process through to completion while finding additional ways to accelerate the interconnection process immediately. The high auction prices underscore the urgency of allowing project developers to begin to propose new projects for the queue that reflect today’s economic realities and come online in time to lower prices and ensure resource adequacy.”
PJM Power Providers Group (P3) President Glen Thomas said the capacity market is successfully delivering reliability at a price that remains below surrounding regions.
“The auction results show a market that is responding but remains tight. New generation is being added, existing generation retained, external capacity imported and retired capacity reactivated. The resource mix remains diverse, and it is important for the market to continue to send the signal that more capacity is needed. In the meantime, consumers should feel comforted that PJM has secured capacity commitments sufficient to maintain reliability through May of 2027 at a price below what many other regions of the country are paying,” he wrote in a statement.
Electric Power Supply Association CEO Todd Snitchler said the auction prices show new resources, not political interventions, are urgently needed.
“Higher prices are a signal to build more generation resources, and reflect increasing stress on the system,” Snitchler said. “In recent years, a combination of state and federal policy shifts and poor market signals led to the premature retirement of essential generation. Now, as demand grows and supply tightens, we can’t ignore the consequences of past decisions, and we must accept that reliability comes at a cost. Investment follows clear, consistent rules.”
He argued that competitive wholesale markets have kept energy prices stable and efficient, whereas rising retail rates can be attributed to state policy mandates, as well as transmission and distribution spending not subject to the same transparency and market pressures.
The power industry can meet growing demand in a timely and cost-effective way by deploying commercially available new technologies to increase the use of the existing grid and proactively planning for new infrastructure, a new report from the Clean Air Task Force said.
The “Optimizing Grid Infrastructure and Proactive Planning to Support Load Growth and Public Policy Goals” report, prepared for CATF by The Brattle Group, highlights how to deal with demand growth from data centers, reshoring manufacturing and electrification.
“By mobilizing demand-side flexibility, increasing the utilization of the existing grid and recognizing uncertain future needs through proactive planning, utilities and other grid operators can serve new loads while mitigating cost increases, thereby avoiding large bill increases for existing retail customers and protecting them from future risks,” the report said.
“Combining more efficient capital utilization with more proactive planning thus offers a win-win proposition that protects customers, serves new loads more quickly, benefits utilities and grid operators, and supports a wide range of public policy goals for clean energy and economic development,” it said.
Demand growth has come back at a time of stressed supply chains, compounded by long interconnection queues and other factors contributing to a slowdown in the speed and scale of deploying new resources, CATF Electricity Director Kasparas Spokas said in an interview.
“We hope this report serves as a little bit of a menu of options of underutilized, but effectively no-regrets solutions that policymakers can evaluate and assess and hopefully adopt to both grow load while minimizing emissions and cost as much as possible,” Spokas added. “And so, the goal really here was to highlight … some of the near-term, no-regrets solutions that even if demand, which is highly uncertain, were not to materialize, would still be beneficial for ratepayers.”
The paper offers actionable recommendations for grid planners, but it does not cover the full scope of potential reforms that could be needed under the new demand paradigm, such as changes to wholesale power markets or technology innovations that might become commercially viable.
The pressure from demand is most acute with large loads such as hyperscale data centers and advanced manufacturing facilities because they often require access to vast amounts of reliable electricity and can start operating in a few years, while installing new infrastructure can take decades.
Some of the quicker ways to help manage that rapid demand growth include use of demand-side resources, grid-enhancing technologies and advanced transmission technologies, as well as taking advantage of upsizing opportunities when power lines are refurbished and facilitating interregional trade, the report said.
“Regulators and advocates just have to be very disciplined about requiring planners to effectively evaluate some of these [virtual power plant] demand-side solutions and advanced transmission solutions before committing to new buildout,” Spokas said.
‘Political Feasibility’
Policymakers also should establish and expand efficiency and bill assistance programs for low-income customers and extend demand-side management to those customer classes. Another option is to establish rules that ensure customers with large loads don’t end up imposing stranded costs and financial risks on other customers, the report said.
“I think that there’s a lot of very acute and near-term political pressure that policymakers and legislators and others are feeling with regard to increases in customer prices for electricity, increases in utility bills,” Nicole Pavia, CATF’s director for clean energy infrastructure, said in an interview.
“We think that the political feasibility of implementing a broad suite of solutions kind of depends on gaining and maintaining political will for the energy transition,” Pavia said. “A lot of that has to do with how consumers feel about rates and if affordability is top of mind. And, so, we think some of the measures around affordability can help reduce the political pressure in terms of the increasing rates and utility bills.”
Transmitting energy more efficiently, speeding up queues and addressing affordability concerns will help, but the power system eventually will need new generation and transmission. Those investments can be assisted by facilitating customer-sponsored generation investments and procurements, and collocating generation and load in “energy parks.”
Planning and procurement process should pick the flexible, least-regrets solutions and, where needed, attract new investments in a timely manner. Load forecasts can be improved, clean energy development can be sped up by picking zones that can be connected proactively with transmission and deliberately planning the distribution system to more cost-effectively manage load growth.
The return of demand growth also has increased interest in developing new natural gas-fired power plants around the country.
“There are a lot of low-cost, no-regrets solutions that need to be considered before you get to the point of building a new gas plant,” Spokas said. “Once you get to that point as well, you need to consider the life of that asset.”
Spokas thinks there’s “a lot of talk” about future gas-fired plants being built as “hydrogen-ready” without much consideration about the investments needed to make them so.
“Where will the hydrogen come from? What will be the cost? So, I just think we all need to be very disciplined about what it takes to get to the point of saying, yes, a new gas plant is the solution,” he said.
Members Shoot down Staff’s Proposal for Integrating High-impact Large Loads
LITTLE ROCK, Ark. — The SPP Markets and Operations Policy Committee resoundingly rejected a proposed tariff change to integrate large loads, pushing back against what some say is a rushed process outside of the normal stakeholder structure.
The committee’s decision during its July 15-16 meeting won’t stop the revision request (RR696) from going before the Board of Directors during its next quarterly meeting Aug. 5. The board in April directed SPP staff to deliver a draft proposal during the meeting that helps integrate large loads, and that includes the “requisite stakeholder engagement.” (See “Cupparo Issues ‘Executive Order,’” SPP Board OKs 1-time Study for LREs’ Gen Needs.)
The measure failed with only 53.7% approval. The Transmission Owner segment voted 11-5 for the measure, while Transmission Users voted 24-38. There were 12 abstentions.
“As SPP members continue to receive or — really, in the case of some members — actually submit large load requests to us, we’ve needed to develop an effective policy that allows our members to be both responsive and competitive in the pursuit of these loads,” COO Antoine Lucas said in setting up the discussion, which ate up much of the meeting’s two days.
“The large load policy is essential to responsibly allow this new industrial-scale electricity demand such as AI, data centers, advanced manufacturing and even energy-intensive production processes to integrate and operate,” he added.
SPP slide showing growth of data centers in recent years | SPP
SPP says its 2025 Integrated Transmission Planning assessment includes about 10 GW of large loads, with an average size of 235 MW. The 2026 ITP includes more than 20 GW of large loads.
The grid operator’s solution addresses gaps in current planning processes that have resulted in long wait times for projects, a lack of flexibility for limited connection or operation of load with system limits and cost uncertainty for transmission upgrades.
The proposal is built around 90-day studies that allow faster load connection with certain reliability-driven conditions. The policy defines several large-load types or services, including:
high-impact large loads (HILLs): any commercial or industrial individual load facility or aggregation of facilities at a single site, connected through one or more shared points of interconnection or points of delivery that can pose reliability risks to the grid. HILLs are nonconforming loads of either 69 kV or below with a peak demand of 10 MW or greater, or greater than 69 kV with a peak demand of 50 MW or more.
conditional high-impact large load (CHILLs): the portion of a HILL that is receiving conditional high-impact large load service (CHILLS). This is intended for any HILL specifications that cannot reliably be served on a firm basis by existing designated resources or the current transmission system. CHILLs can exist at the same delivery point as firm load.
CHILLS: a new transmission service available to HILLs to transfer energy to designated points of delivery to serve a transmission or network customer’s CHILL. The service will be available for yearly periods ranging from one to five years.
“HILLs, CHILLs and thrills,” cracked one wag at the table.
“A big principle in this is to have a path to firm service and balanced reliability,” said Casey Cathey, SPP’s vice president of engineering. “Our solution is to be the fastest connection study in the United States. We’ve looked at all of our fellow ISOs and RTOs. We work with them at least quarterly and share best practices. We also looked at Southern Co. We looked at a number of different areas that are challenged with similar challenges. … We want to provide transmission customers all the options necessary in the toolbox.” (See SPP Embraces Need for Speed to Meet Change Head-on.)
SPP said the rules for large load’s cost allocation are consistent with the existing tariff and aim to minimize cost shifts from HILLs and CHILLs to other customers, aligning costs with those causing the upgrades. Those costs are directly assigned to the large-load customer until it secures firm service and is potentially eligible for base plan funding.
CHILLS is billed on reserved capacity megawatts. If curtailed, charges adjust to the curtailed megawatts.
In opening the second day of discussion on large loads, CEO Lanny Nickell expressed the need for speed and stakeholder input. To bolster his case, he said a person could draw circles around any 14 contiguous states in the country — as he did — and they would find more data centers in that region than in SPP’s 14-state service territory.
Quoting ChatGPT, Nickell said the lost opportunity of a more-than-$1 billion capital investment for a 100-MW load amounts to more than the $1 billion: It also results in $200 million to $500 million lost construction and ongoing jobs, $50 million to $150 million of lost tax revenue over 10 years and $25 million to $75 million of lost grid and system value.
“That’s the pure evidence. That’s the pure data,” he said. “That’s not something I really want to go to the governor and say, ‘You know what? Because we couldn’t get this done in a timely fashion, you just lost another 100 MW.’
“It was made clear to me several months ago [by members’ leadership] that this is an opportunity that we have to take advantage of, and if we don’t, it’s not only hundreds of millions to billions of dollars of lost opportunity if we don’t take advantage of this. It turns into a threat to our long-term existence. So that’s why we’re doing this, and that’s why this is urgent, and that’s why we’re doing it as fast as we can, but we still are trying to do it in a way that considers as much input as we can possibly get. We want every piece of input that we can get.”
Over two days, including a half-day education session on large loads, SPP got that input.
“My background has always been in operations, and I have extreme concerns about the reliability impacts of large loads. I don’t think we’ve thought of all the potential issues that can come from bringing these large loads on,” NextEra Energy’s Jeff Wells said, calling for more time. “I’m not saying we need three months. I’m not saying we need six months, but we need time to go to our experts in SPP that aren’t SPP employees. … We need to get their feedback, and we need to make sure that we’ve addressed all those concerns.”
The Advanced Power Alliance’s Steve Gaw said SPP has not followed its stakeholder process. Members, some constrained by a lack of internal resources, have struggled to keep up as the policy and revision requests are developed at the same time.
“There’s a reason why we need to prioritize things,” he said. “There are lots of investment dollars that have been lost because of road blocks to getting generation interconnected over the last several years. We would not have the same kinds of problems in having resources to match this load if we had done some additional work to prioritize things in that fashion as well.”
Gaw also complained about the little time stakeholders have had to comment on the proposal’s “500-plus pages that were dropped on us” in late June.
Noting that additional comments to the board on the tariff change are limited to two pages, Western Farmers Electric Cooperative’s Matt Caves asked whether the directive could be reciprocal.
“Can SPP reduce this RR to, say, 100 pages?” he asked, drawing chuckles from staff and stakeholders.
Olivia Hough, a regulatory strategist with City Utilities of Springfield in Missouri and MOPC’s vice chair, said the utility has formed a task force to go over the “voluminous” document.
“It’s a lot to go through, and I understand that everyone maybe can’t read every single line item of it,” she said. “In whole, we want to see this move forward. We don’t want to miss out on the opportunity, and we think that the economic development potential and the challenge is worth it. I appreciate SPP’s commitment to putting this together at the same time that all the utilities are trying to develop their own frameworks.”
“This is what SPS has been asking for: help to serve loads,” Southwestern Public Service’s Jarred Cooley said. “We really see that this is something that needs to be done. … We get the opportunity to get in front of FERC, get that feedback, figure out maybe what changes we need to make in the next iteration, and continue to push forward.”
SPP’s Market Monitoring Unit also weighed in, saying that despite a “high level” of engagement with the RTO, it still has concerns that the proposal introduces risk to the market and other participants. It recommended risks be mitigated before any implementation and said it may identify additional risks and make further recommendations in the future.
MOPC passed a motion to hold a special workshop and further consider RR696 no later than the end of September. The motion passed with 69.9% approval.
COO Lucas emailed MOPC’s membership on July 18, laying out the several channels open to stakeholders who want to continue shaping the proposal before it goes to the board. SPP followed the email with a survey that members can use to share their concerns and recommended solutions.
Members can also provide “high-level, strategic feedback” directly to the board. The feedback, using a template to ensure consistency and focus, is due July 28, the same date the grid operator is keeping the comment period open for RR696. Several working groups will each review the proposal during their scheduled meetings before Aug. 5.
“Your continued participation in this process is valued and vital,” Lucas wrote. “You have our continued commitment to incorporate our stakeholders’ diverse perspectives as thoughtfully and equitably as possible. With your help, we aim to bring a proposal to the board that reflects both the urgency of this issue and the collective wisdom of our stakeholders.”
Seams Cost Allocation Rejected
MOPC also rejected a proposed tariff change RR681 that would provide a cost-allocation mechanism for projects that don’t qualify as interregional projects and where SPP shares cost with one or more neighbors. The measure received only 54.9% approval.
Aaron Shipley, the RTO’s senior interregional coordinator, said the proposal would make the process of building future jointly funded projects more efficient. He said it would be helpful to have the tariff change in place as SPP moves forward with the RTO’s Western expansion.
“We would expect to receive efficiency in our processes by having this cost-allocation tariff mechanism already approved and thus eliminating individual at-the end-of-the-process cost-allocation debates that we have all been through before and provide significant risk at the end of a project and process,” he said. “This is something we’ve heard support from both stakeholders and regulators all the way from the beginning of this effort.”
SPP’s membership first raised the issue in 2014, and it was later readdressed and confirmed through the Strategic and Creative Re-engineering of Integrated Planning Team’s (SCRIPT) work in 2020-2021. The RTO’s state regulators in October 2024 endorsed a seams policy white paper and directed staff to move forward with a recommendation to seek FERC approval.
Stakeholders pushed back against RR681 over concerns the seams projects would be subject to the grid operator’s competitive process screening. They wondered whether staff would be able to take on the number of new planning processes feeding into the process.
“I’m not opposed to following this kind of process in general,” American Electric Power’s Richard Ross said. “I’m opposed to just automating it so that it’s just there all the time. I think there may be some serious instances where we do things in one area that really don’t have greater benefits across the region, and so they ought to be allocated more. I do hope you will share with me that we ought to take a closer look at these on an individual basis.”
Three RRs Endorsed
Members endorsed three other revision requests with varying levels of approval.
RR693 received 76.5% approval, with SPS the only transmission owner of 17 to vote against it. The first phase of Surplus Plus and its suite of initiatives designed to accelerate the addition of new generation, the measure would quickly add shovel-ready incremental capacity at existing generating sites. The process would end when the Consolidated Planning Process begins in 2026. (See SPP ‘Blazes Trail’ with Consolidated Planning Process.)
Under the proposal, priority requests would be queued higher than study clusters that haven’t started. The process would be conducted on an accelerated time frame, not subject to waiting for open seasons or processing as part of a cluster or from needs driven by other requests.
Assuming FERC approval in October, the first requests would be submitted for a 90-day system impact study, with the first GI agreements issued by April 1.
RR693 was an outgrowth of discussions at the Resource and Energy Adequacy Leadership (REAL) Team, said Steve Purdy, SPP’s technical director of engineering policy.
“It is another tool in the toolkit for customers to be able to add new generation to the system, in addition to all of the existing processes that customers have available to them,” he said. “It’s a new process that will allow a customer to make a request and submit that outside of the DISIS [definitive interconnection system impact study] window.”
RR689, which passed with 95.8% approval, was opposed only by four members of the Transmission Users segment. The proposal would reject market participant bids in the transmission congestion rights (TCR) market when sourcing from an electrically equivalent settlement location (EESL) to another settlement location on the system, or when the participant adds another bid from a settlement location back into the original EESL group that sinks at a different settlement location than the source.
“We saw some concerning TCR bidding strategies in the TCR market,” said Micha Bailey, SPP’s manager of congestion hedging. “[EESLs] don’t have to be co-located, but electrically equivalent settlement locations basically have what we like to call unconstrained flow between them. So, you can basically get an infinite amount of TCR awards.”
The MMU’s Raleigh Mohr said the Monitor was supportive of the measure.
“Essentially, the message is this behavior is bad. FERC has ruled in other markets and in our market that this behavior is manipulative. We wanted to make sure that at this full representation body, that everyone heard that message,” he said.
A motion to include comments from The Energy Authority (TEA), speaking for six market participants, failed with only 35.8% approval. TEA recommended restricting implementation to auction revenue rights (ARRs) submitted for self-conversion to TCRs and not applying the restrictions to settling ARRs.
“Our general principle is if a gaming opportunity exists and it can be closed, then it should be closed,” Mohr said, arguing against TEA’s comments.
RR676 came within a percentage point of unanimous approval, receiving its only opposing vote from NG Renewables Energy Marketing. The measure creates a process for studying electric storage resource loads subject to SPP’s generator interconnection process and ensure compliance with FERC Orders 845 and 2023 and NERC reliability standard FAC-002-2.
“Today, our studies assess them for injection as a resource,” Evergy’s Derek Brown said. “One of the reasons for the enhancement is to better assess the impacts of these electric storage resources.”
The RTO currently has 179 active storage projects, totaling 31 GW, in the queue.
“We just think this is a crucial step forward for ensuring reliability and compliance of ESRs within the SPP transmission system,” Eolian’s Kyle Martinez said. “This is generation that can come online [and] provide ancillary service products off of the market.”
DR Policy Endorsed
MOPC endorsed SPP’s demand response and load-responsible entity peak-demand assessment policy proposals, designed to help ensure realistic forecasts that reflect the effect of flexible load.
Members amended the original motion to direct staff to prepare an RR based on the DR policy framework and conduct stakeholder reviews in conjunction with the LRE peak-demand assessment’s policy and RR.
Assuming their eventual approval, SPP plans to file both tariff changes together at FERC in early 2026 because of the “interdependency” between the two. A joint filing would provide a single, transparent foundation for resource adequacy and tariff evolution, staff said.
The DR framework includes various metrics, criteria and thresholds for both reliability and market-registered DR to reduce consumption during tight grid conditions.
MOPC endorsed RR692 by more than 91% approval after it was pulled from the consent agenda over timing concerns.
The change allows multiple Phase 1 restudy iterations within the DISIS process in the face of growing interconnection clusters. The 2024-001 cluster has 380 requests totaling more than 100 GW of capacity, almost double the size of the previous largest cluster.
“We’re seeing large amounts of dropouts between phases. Customers are being asked to make decisions about moving to the GIA portion of the DISIS analysis before we really have an understanding of what customers are going to remain when we’re through the entire process,” SPP’s Natasha Henderson said. “What’s proposed here is that we add additional Phase 1 studies. For instance, if 30% of the projects drop out in Phase 1, we would repeat Phase 1 again if we’re going to Phase 2, which adds stability to the mix.”
The measure received 91% approval from members.
The consent agenda included eight other revision requests that, if approved by the board, would:
RR675: modify the local market power test for resources in a nonbinding frequently constrained area.
RR677: add language that was inadvertently omitted from the settlement calculations changes approved in RR628 (Price Formation) that checks whether a resource is below its day-ahead market position.
RR678: remove outdated references to quick-start resources, which have been replaced by fast-start resources, from the protocols because of updates in registration parameters.
RR679: revise the ITP manual to remove conflicting language and references to the Model Development Procedure Manual’s new process. The new method allows for more data points to be included in calculating the number used for renewable resource dispatch, resulting in increased accuracy and confidence in the base reliability model.
RR680: establish the incremental market efficiency use (IMEU) mechanism to provide revenue that offsets the increased operational costs of the West DC ties because of more frequent market-directed dispatches under the five-minute market.
RR683: clarify and align governing document language with actual operational practices for notifying market participants during emergency conditions, including cleanup edits and new language allowing operations to issue notifications as soon as practical when emergencies are anticipated.
RR685: update the Integrated Marketplace rules to allow SPP’s Western balancing authority area to join the Western Power Pool’s Reserve Sharing Group, lowering ancillary service costs and strengthening system reliability.
RR691: revert tariff language back to its correct verbiage regarding changes for the RTO’s Western expansion.
FERC on July 18 rejected a petition from MISO seeking approval to not pay its Independent Market Monitor, Potomac Economics, for monitoring its transmission planning process (EL25-80).
MISO’s petition argued that the IMM’s review of its recent long-range transmission plans exceeds the scope of the Monitor’s authority and has contributed to recent cost overruns compared with the IMM’s contract.
IMM David Patton has argued that MISO’s tariff unambiguously authorizes him to monitor transmission plans, which have clear impacts on the wholesale markets. (See MISO IMM Contends He Should Have Role in Tx Oversight.)
RTO tariffs give rise to and define the scope of an IMM’s authority, and FERC and the courts consistently have found Monitors are limited to the authority laid out for them there and in agreements they sign with grid operators. In interpreting the MISO tariff, FERC had to address whether it unambiguously addresses the issue at hand — and the commission found that it does.
As the order pointed out, section 53.1 of the MISO tariff says the IMM can review any RTO actions that affect any of its markets and services.
“We also find that MISO’s transmission planning is an action that affects its markets and services, and that section 53.1.e unambiguously authorizes the IMM to review and analyze the competitive or other market impacts of MISO’s transmission planning,” FERC said.
FERC said it found no conflict in letting the IMM monitor transmission plans while MISO retains the sole authority to conduct transmission planning. The tariff does not let the IMM engage in transmission planning but simply authorizes him to review its impact on the market.
“We see no conflict between our finding here and the fact that the costs of transmission planning and of market monitoring are recovered under separate schedules to the tariff,” FERC said. “The cost recovery of transmission planning under Schedule 10 of the tariff is not relevant to the instant proceeding.”
FERC also rejected MISO’s argument that siding with Patton would be the same as amending the tariff absent a filing under Section 205 of the Federal Power Act.
And while MISO transmission owners had argued the case could risk the IMM involvement in any business area within the ISO, FERC found the tariff requires that the Monitor watch only issues that “affect the competitiveness, economic efficiency and proper operations of the markets and services.”
FERC also said that because no party had asked it to review any specific activities undertaken by the IMM, it was in no position to determine whether specific activities in the proceeding should have been billed to MISO. The commission encouraged the parties to work collaboratively on resolving such disputes.
‘Recognized and Applauded’
The order drew a pair of concurrences — one from Chair Mark Christie and another from Commissioner David Rosner.
“That transmission planning affects RTO markets is factually undeniable and thus makes this order an easy legal call,” Christie said.
Growing calls for expanding transmission are coming as consumers are facing rising bills, driven in large part by the rising costs of that infrastructure.
“Despite the understandable concern and publicity over capacity market auction results in MISO and PJM over the past year, transmission costs are the single biggest driver of skyrocketing monthly power bills and have been for years,” Christie said. “Transmission costs are driven not by the price of fuels such as natural gas, coal or oil, which change literally hourly and are set in global markets, but by capital expenses (capex), which are a result of intentional planning and intentional policy decisions, in this case by the management of MISO.”
The latest long-range plan comes with a price tag of $21.8 billion along with additional costs such as financing and return on equity that will be passed on to consumers.
“So, to his credit, MISO’s IMM has stepped up and provided a critique of the assumptions and calculations used by MISO to develop and attempt to justify this latest costly tranche of transmission projects,” Christie said. “Since the transmission planning that produced this tranche obviously affects the rates consumers pay, this is exactly what the MISO IMM and any market monitor should do.”
Christie also noted that state regulators and consumer advocates defended the IMM in the proceeding, which he said was in line with his experience with PJM during his time as a Virginia regulator.
“The role of an IMM requires courage and a willingness to put his job on the line by bringing to light uncomfortable (for some) facts and drawing conclusions about those facts that he is prepared to defend forthrightly,” Christie wrote. “The MISO IMM has done so here and he should be recognized and applauded.”
Rosner wrote separately that it’s important that a Monitor and its RTO should have a good working relationship, and ideally MISO and Patton should have settled the dispute on their own.
“In a situation like this one, which is essentially a contractual dispute, the best outcomes are achieved when the parties reach agreement among themselves — not when the commission is asked to interpret decades-old language,” Rosner said. “When parties ask the commission to answer a ‘yes or no’ question, they forfeit the opportunity to reach a compromise solution that results in better outcomes for everyone involved.”
He also noted that nothing in the order should be read as a requiring an independent transmission monitor, a concept discussed in Order 1920 that the commission could not reach consensus on.
As new solar and wind developments face hurdles due to changes in federal policy, the projects are also encountering growing resistance at the local level, according to speakers at a webinar.
“In most of the United States, it’s very local government — counties or townships — that have the authority to decide whether these large-scale clean energy projects can move forward or not,” said Dahvi Wilson, founder and president of consulting firm Siting Clean. “And increasingly, they are saying no.”
Wilson was one of four panelists at a July 17 webinar on obstacles to energy infrastructure. The event was hosted by Resources for the Future, a nonprofit research institution.
At the heart of the local resistance is the feeling that utility-scale solar and wind projects are transforming rural landscapes, giving them an industrialized feel, Wilson said. But the opposition to projects frequently expands to arguments that “often aren’t legitimate,” Wilson said, such as claims that the projects will have health impacts, hurt property values or are part of the “green new scam.”
Another factor in the growing local resistance is the transmission system’s limited capacity, Wilson said. As a result, clean energy developers are flocking to places where they can get on the grid.
“It leads to a ton of pressure on those places,” she said. “Suddenly, the resistance to this kind of development increases.”
Mapping Restrictions
Panelist Robinson Meyer, founding executive editor of Heatmap News, said that following enactment of the federal budget reconciliation bill, called the One Big Beautiful Bill Act (OBBBA), clean energy adversaries increasingly will focus their efforts at the local level.
“That is where the big fights are coming for slowing down clean energy production,” Meyer said.
Heatmap News surveyed counties across the country and found that 605 counties — accounting for about 17% of the land area of the continental U.S. — restrict solar or wind development in some way. The restrictions might be in the form of an outright ban, development requirements such as setbacks that make it nearly impossible to build, or moratoria that can be slapped on at will.
Meyer said areas such as the Southwest have had a “relief valve” for building renewable projects on federal land, where county rules don’t apply. But now even that relief valve is under fire from the Trump administration.
Under a new directive from the Department of the Interior, all decisions concerning wind and solar energy facilities must be reviewed by Interior Secretary Doug Burgum, including leases, rights-of-way, construction and operation plans, grants, consultations and biological opinions. Critics called the order a “shadow ban” on clean energy projects. (See Interior Dept. Places Solar, Wind Under Close Review.)
Some states, such as New York and Michigan, are addressing local resistance to solar and wind projects by adopting mechanisms to override the opposition.
“State preemptions of these rules can be quite effective,” said Meyer, who noted there are more clean energy projects on the Michigan side of the Michigan-Ohio state line than on the Ohio side.
Tax Credit Clock Ticking
With the enactment of OBBBA, solar and wind developers now face a tight timeline for starting and finishing projects in order to qualify for sunsetting tax credits.
Investment and production tax credits no longer will be available for solar and wind facilities placed in service after Dec. 31, 2027 — unless construction starts by July 6, 2026, in which case the deadline for placing the project in service is extended. The dates are subject to Treasury Department guidance; an update to the guidance is expected by Aug. 18.
The tight tax-credit timeline means opponents need only to delay a project to derail it, Wilson said.
“They don’t even have to kill the project,” she said. “They have to delay them maybe a year, to knock them out of being qualified.”
Webinar panelist Rich Powell, CEO of the Clean Energy Buyers Association, said there could be a rush for developers to “commence construction” of solar or wind projects to meet the tax credit deadline. That might entail starting work on a new transformer or road, or meeting a spending threshold by buying solar panels, turbines or batteries.
“Which is painful from the buyer’s perspective, because that’s going to mean prices go up for all of these things … as people sort of rush to do that,” Powell said.
Panelist Allison Clements, a former FERC commissioner and now a partner at ASG, a consultant to the data center, cloud and real estate development industries, called the administration’s actions “economically irrational.”
“I couldn’t have guessed in my most creative moment some of these things they’re doing to slow things down. [Saying] ‘I really hate this color of electron versus that color of electron,’” Clements said.
But Clements said given the “durable demand” expected over the next five to seven years due in part to computing needs and electrification, she still expects projects to proceed.
“Things will just be increasingly messy but continue to go forward,” she said.
NERC is seeking comments from industry stakeholders on potential changes to the ERO’s standards development process found in an upcoming white paper, members of the task force that wrote the document said in a webinar July 21.
The draft white paper is a key product of NERC’s Modernization of Standards Processes and Procedures Task Force (MSPPTF), launched by the ERO’s Board of Trustees at its February meeting. (See “Task Force to Examine Standards Process,” NERC Leaders Highlight Canada-US Collaboration.) It will be released July 22, with a public comment period to open the same day and close Aug. 27.
NERC’s board decided to stand up the task force after growing concern that the ERO’s standards process was too deliberative to keep pace with the rapidly changing reliability risk landscape. The board’s use of its authority in 2024 under Section 321 of NERC’s Rules of Procedure to accelerate the pace of two standards projects that seemed unlikely to meet a FERC deadline brought more attention to these issues.
“The industry is at an inflection point due to the rapid evolution in reliability risks, such as plant retirement, more variable generation and … extraordinary load growth,” MSPPTF Chair Greg Ford, CEO of Georgia System Operations, told webinar attendees. “While previous incremental enhancements have marginally improved our efficiency, the task force believes that a more transformational change to the NERC standard development process will certainly improve NERC’s ability to address these risks in a timely manner.”
Ford said that NERC’s data showed the development of a standard takes on average about three years, with about 20% of that time spent developing an initial standard authorization request (SAR) into a final version that a standard development team can work on. The next stage of development, going from the SAR to submitting a first draft standard for industry ballot, takes about 50% of development time on average, and the remainder is spent refining the draft standard based on industry feedback until it meets final approval.
Recognizing these stages, the white paper’s authors divided their proposed changes by the phase of development to which they apply. The initiation phase begins when a request to develop a standard is submitted and ends when the request is approved to begin drafting; standard development begins when the request is approved and ends when a first draft is proposed; and balloting begins when a proposed standard is ready for industry to vote and ends when the standard is either approved or returned to drafting.
Two of the white paper’s proposals will pertain to the initiation stage, Southern’s Todd Lucas said, calling them “options that we can use as a starting point … and get to a draft recommendation later this fall based on the input we get.”
Both options are intended to address the fact that “there are multiple ways [today] for a [SAR] to get initiated” by establishing a single process to identify and vet candidates for development. The first would involve a biannual review process, involving an open submission period and industry conference focused on prioritizing submissions. The other would be to centralize all submissions through NERC’s Reliability and Security Technical Committee.
Another three proposals, introduced by Ford, apply to the development phase, with the goal of getting “off the blank page … much sooner.” One way to do this, Ford said, is to use artificial intelligence more extensively, at least for low- or medium-priority projects, in tandem with a standing body of subject matter experts maintained by NERC.
“Not every standard that goes through this process may need a drafting team,” Ford said. “We can run [low- and medium-priority] projects through this process using subject matter experts, as well as this AI tool. We’ll run that through comment periods from the industry, we will convene technical conferences throughout this stage so that we can keep industry in tune … and we’ll be able to put together a package that we can communicate and get comments from the industry.”
An alternative to this proposal is to outsource standards drafting to a third-party contractor. In this scenario NERC still would oversee the contracting and drafting processes, and it still would go out for industry comment as normal. The third proposal would see the current process remain in place, but with tweaks for greater efficiency, possibly using AI tools.
For the third phase of development, balloting, MISO’s Todd Hillman listed three potential ideas. The first would involve replacing NERC’s current system of ballot pools formed from industry volunteers for each candidate standard, representing “somewhere in the neighborhood of 470 potential votes,” with a standing ballot body composed of about 24 members. These members still would represent the ERO’s industry sectors, but with a smaller, dedicated membership the authors hope that participation in each balloting process could be higher.
Another option would be to adopt an approach similar to FERC’s rulemaking process, which would replace the stakeholder balloting with a “notice and comment approach.” Under this model, NERC would post a draft standard for comments with questions to guide feedback. NERC then would analyze any comments received, update the draft based on the feedback, and then move forward to the board rather than calling for votes from industry. Finally, the third proposal under the balloting section would keep the existing system, with incremental changes.
NERC and the regional entities plan to hold industry outreach events during the comment period, with Q&A sessions the week of Aug. 4. Based on feedback, the MSPPTF will create formal recommendations with the goal of submitting them to the board at its February 2026 meeting.
