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December 10, 2025

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MISO Cuts Renewable Estimates in Tx Planning Scenarios

MISO has slashed earlier renewable energy estimates and boosted natural gas contributions in its transmission planning futures in a rethink brought on by the Trump administration.

Director of Economic and Policy Planning Christina Drake told stakeholders that MISO took a “very hard pivot” to incorporate the One Big Beautiful Bill Act into its four, 20-year futures, which are used to plan long-range transmission.

MISO was on its way to completing the futures and publishing capacity expansion estimates when the bill was passed in July. Staff have added months to the process and expect to deliver final futures sometime in early 2026. (See MISO Seeking Realistic Gen Buildout for Tx Planning Futures.)

“There is quite a bit of reduction in some of the renewable buildout,” Drake said before a Sept. 24 stakeholder teleconference. She also said MISO is reflecting increases in natural gas buildout in its members’ resource planning.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said gas now represents a much higher share of the capacity expansion than when MISO last updated its futures in 2022.

MISO’s preliminary capacity expansion estimates by 2045 now include:

    • For Future 1, a total of 383 GW in installed capacity derived from 28% gas, 25% solar, 25% wind, 11% other, 4% battery, 4% nuclear and 3% coal at 911 TWh of output, with 224 GW built between now and 2045.
    • For Future 2, a total of 403 GW in installed capacity from 25% gas, 25% solar, 30% wind, 11% other, 3% battery, 4% nuclear and 3% coal at 1,075 TWh of output, with 254 GW constructed in 20 years.
    • For Future 3, a total of 446 GW from 19% gas, 31% solar, 29% wind, 10% other, 3% battery, 6% nuclear and 1% coal at 1,253 TWh of output, with 318 GW built between now and 2045.
    • For Future 4, a total of 454 GW from 25% gas, 33% solar, 20% wind, 10% other, 3% battery, 4% nuclear and 4% coal at 1,079 TWh of output, with 281 GW constructed.

MISO’s futures are fashioned through a “fast, faster, fastest” methodology for fleet change and demand in Futures 1-3. Future 4 — new for 2026 — anticipates continued supply chain hindrances and only includes member-announced generation retirements. Unlike the other futures, it doesn’t assume age-based retirements of thermal generators, resulting in about 23 GW of additional thermal generation compared to the other three futures.

MISO’s members have announced intentions to build 171 GW in resources by 2045. MISO’s modeling had to add the most supplemental resources to Future 3, where only 58% of capacity needs would be met using the 171 GW.

The RTO’s fleet prediction in 2022 under Future 2 for 2042 was 471 GW of installed capacity, consisting of 14% gas, 24% solar, 34% wind, 11% other, 9% hybrid resources, 6% standalone batteries, 2% nuclear and 2% coal. That future formed the basis for MISO’s nearly $22 billion long-range transmission plan for MISO Midwest.

MISO said sustainability goals from states and members, not federal incentives, would drive future capacity expansion.

Drake said as it stands across all futures, milestone goals from 2026 to 2028 in Illinois’ Climate and Equitable Jobs Act and New Orleans’ renewable portfolio standard were unattainable. MISO said lead times to build units made the goals infeasible in the near term. Illinois has set out to achieve 100% carbon-free energy by 2050, with interim targets of 40% renewable energy by 2030 and 50% by 2040. New Orleans, on the other hand, is attempting to achieve net carbon neutrality by 2040 and 100% carbon-free electric generation by 2050.

Decarbonization goals across MISO states | MISO

MISO’s Environmental Sector requested a sensitivity study on the futures where natural gas prices rise, prompting an energy storage expansion.

Sustainable FERC Project’s Natalie McIntire said she wondered whether the futures for use in scenario-based planning should be more “diverse” from one another and contemplate a wider range of possibilities. She said MISO should contemplate variables like rising gas prices and falling battery prices, along with the possibility of a reinstatement of tax credits for renewables.

Drake said MISO will check in with stakeholders once futures are more developed. She added that MISO planners have asked themselves the same questions.

“If we get to the end of this process and we don’t have broad bookends, we will revisit,” Drake promised. She stressed that MISO’s numbers aren’t final yet.

Drake said MISO is halfway through the recalibration of its futures. She said initially, removal of tax credits for wind and solar resulted in MISO’s model building a hypothetical 100 GW within a single year to take advantage of the fading perks. Drake said after MISO staff “laughed” at the results, they removed the possibility for renewable production and investment tax credits for generation not already in the queue.

“The rationale for that is if it’s not already in queue … it won’t be in the ground and ready to go by 2028,” she said.

Drake also said MISO must complete generation siting and large load siting for use in its transmission models alongside completing energy adequacy assessments to develop the futures. She said MISO would discuss the locations of large loads in the footprint in November.

MISO Senior Vice President of Planning and Operations Jennifer Curran said members recently have swapped lower accredited renewables for higher accredited dispatchable plants in their plans. She also noted that the U.S. Department of Energy has become “directly involved” in resource retirements, issuing a second extension of Consumers Energy’s J.H. Campbell coal plant in Michigan.

“There has been a lot of activity on the federal front,” Curran acknowledged at a Sept. 17 Advisory Committee meeting in Detroit, part of MISO’s quarterly Board Week.

Curran said it became apparent that a repurposing of futures was necessary in July, when the early expiration of tax incentives became clear.

“We’re putting a lot of eggs in the gas development basket,” Clean Grid Alliance’s Beth Soholt said in response to MISO’s remarks, asking whether the RTO would factor in pipeline capacity issues and fuel availability limits.

Curran said MISO would try to capture the fuel availability associated with “explosion” in gas development and pipeline constraints in the resource’s capacity accreditation.

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IESO Ups Capacity Target for Long Lead-Time Resources

IESO has increased the capacity target for its planned solicitation for long lead-time (LLT) resources, even as it acknowledges questions about the need for the procurement. 

The ISO plans to seek 600 to 800 MW of capacity from resources requiring at least five years of lead time, up from its proposed 600 MW, “to recognize the volume of system needs arising in 2035,” officials told stakeholders at an engagement session Sept. 16. The energy target will be up to 1 TWh, unchanged from what the ISO outlined at its June 5 engagement. 

IESO decided to pursue a separate LLT procurement in response to stakeholder feedback that energy storage resources such as compressed air and pumped hydro require longer planning cycles than the four-year lead times for resources offering in the pending Long Term 2 (LT2) procurement. Energy proposals for LT2 are due Oct. 16, and capacity proposals are due Dec. 18. (See IESO Officials Deny Favoring Gas Resources in Upcoming Procurement.) 

The ISO issued a request for information last fall to guide its design of the LLT solicitation and summarized its findings in an Aug. 29 report to the Ministry of Energy and Mines. 

Requirements

To participate in the LLT procurement, resources must require a lead time of five or more years and have an operating life of 40 years, versus 20 years in LT2.  

Technologies for which IESO is less familiar — such as emerging long duration energy storage (LDES) — may need to prove they meet the lead-time requirement with an independent engineer report detailing the project scope, permitting path and supply chain constraints. 

Although the LLT RFP is intended for new resources, IESO is considering including hydropower redevelopment projects — large-scale replacements of existing equipment that IESO said “would be similar in scope to a new build facility.” 

“Following redevelopment, the expected operational life of the facility would be comparable to that of a newly constructed facility,” the ISO said. 

Reservoir hydro projects (those with storage capability that are not pumped hydro) will be eligible to participate in the energy stream only because they would be unable to offer full contract capacity between 7 a.m. and 11 p.m. on business days, as required for capacity resources. 

Pumped storage and other LDES resources will be eligible to submit in the capacity stream only. 

IESO plans an engagement in October to discuss hydro repowering, expansions and upgrades of hydro and other resource types in its procurements. 

Questioning the Need for LLT Procurement

Jonathan Cheszes, president of Compass Greenfield Development, questioned the need for the LLT solicitation, saying the eight- to 12-hour requirement for capacity resources is “functionally consistent” with that in the LT2 capacity procurement.  

“If you need eight to 12 hours of capacity, then why not ask for eight to 12 hours of capacity? … Why limit what technologies can participate?” he asked. 

IESO’s Ben Weir said the LLT RFP is an effort to procure resources with attributes — such as a 40-year life span — that can’t compete in LT2.  

“There’s not much point in signing a 40-year contract with a battery, because it’s not going to last 40 years … the way we intend to use it,” Weir said. 

Cheszes suggested the LLT procurement was premature.  

“If you’re going to get eight to 12 hours out of LT2 … maybe see what the pricing comes in at before” seeking a solicitation for LLT resources, he said. 

“You raise an absolutely valid concern,” responded Dave Barreca, IESO’s supervisor of resource acquisition. “Please believe me that this is top of mind for us. … We are thinking very hard about ratepayer value and prices and how to manage that for this RFP, given that … the field of competition is quite narrow.” 

IESO’s proposed solicitation for long lead-time resources would include long duration energy storage technologies such as compressed air energy storage. | Pacific Northwest National Laboratory

“Forty years [is] a long time,” Cheszes responded. “Just imagine what batteries are going to cost 20 years from now. … And whatever [the] technology [will be, it] won’t be lithium ion, right? It’ll be something totally different. So, you know, locking in 40 years — there’s some pluses, but there’s a bunch of minuses as well.” 

Weir said ISO officials will hold engagements monthly for the rest of 2025 to develop the RFP, with proposals expected in the fourth quarter of 2026 and contract awards in the first half of 2027. The timing of the RFP and the target sizes will be finalized after receiving guidance from the ministry, Weir said. 

Weir said IESO may accept a percentage of all proposals submitted — perhaps 80% — similar to what the ISO did in its second medium-term solicitation (MT2). (See IESO Purchasing 3,000 MW of Energy and Capacity.) 

“This is just a way to maintain competitive tension if the numbers of proposals received are lower than we expect,” he said. 

Rated Criteria

IESO is seeking more information on potential projects in prime agricultural areas (PAAs) to inform how it sets its “rated criteria” — non-price factors used to evaluate proposals — for the procurement.  

Some stakeholders said the ISO should not use rated criteria based on locations, such as for proposals located in northern regions or outside of PAAs. 

IESO said its criteria will “be reflective of policy decisions made by the Ministry of Energy and Mines.” 

The ministry also will weigh in on whether IESO should offer price incentives — in addition to rated criteria points — for projects involving Indigenous communities. 

Round Trip Efficiency

IESO is considering minimum round-trip efficiencies (RTEs) — and incentives for exceeding them — because LDES are expected to have lower RTEs than battery storage.  

Barreca said resources considering participating in the LLT RFP have offered a wide range of RTEs with a “middle” of about 60%. That “is quite different than what we’ve seen … in the lithium-ion batteries that we’ve procured” in the first long-term procurement, he said. 

Outages

The ISO plans to use the same rules for planned outages as under LT2. Energy resources should incorporate planned outages into their imputed production factors to avoid non-performance charges. Capacity resources will be permitted a planned outage of up to one month during April, May, October or November. 

Resources will be permitted one long-term outage — a maximum of six months — during the second half of their contracts. 

Environmental Attributes

IESO is considering allowing suppliers to retain the proceeds from sales of “environmental attributes” during the first 20 years of the contract, with the supplier sharing the attributes with IESO in the second 20 years. 

Although suppliers are unlikely to place much value on the attributes for 2051-2070, Barreca said, “there is a good chance that there will be some value there” that could be recovered for ratepayers. 

“We are certainly open to the alternative, which is that you do have forecasts for what those are going to be worth, and you are willing to put those values into your proposal prices,” he added. 

Defining LDES

Open-loop pumped storage hydropower systems connect a reservoir to naturally flowing water via a tunnel, using a pump to move water to higher elevations and a generator to create electricity. | DOE

In addition to inviting participation by compressed air energy storage and pumped hydro storage, IESO will consider emerging technologies such as liquid air energy storage and compressed gas “that are able to demonstrate a sufficient level of technology readiness.” 

Stakeholders told IESO it should clarify its definition of commercially proven LDES technologies and allow participation from LDES technologies with a technology readiness level of eight or higher, indicating it is ready to move from development to commercialization, per the U.S. Department of Energy. 

Although some stakeholders pushed IESO to increase the minimum duration requirement to 10 or 12 hours, the ISO said it expects participating LDES resources “to be in the eight- to 12-hour duration range, which can realize the most reliability benefits at this time.” 

Barreca said IESO’s planning team is conducting research to understand the value of increasing the minimum duration. 

“We’ll need to make a call in terms of whether we think the extra value would be worth the extra price to make that a minimum requirement,” he said. “There is more study required to go to the 24-hour or … multiday storage. That will be a different procurement.” 

Non-performance Charges

The ISO rejected requests that non-performance charges for energy producing resources be based on a five-year rolling average versus the three-year average used in LT2. The three-year average “allows for effective accounting of anomalies that may impact production, such as irregular weather patterns,” IESO said.  

Barreca said the ISO is sticking to a three-year average “primarily because this is a competitive RFP, not a standard offer program, and there are quite a number of variables that a proponent has to work with to find their optimal risk profile.” 

Price Escalation

IESO still is determining how it will escalate prices during the contract term. 

Some potential suppliers said IESO should provide 100% inflation indexing from the contract date to the commercial operation date (COD) — similar to that in the LT2 RFP — and 60% indexing from COD until the contract end date. 

Barreca said the 100% indexing in LT2 “was a direct response to the geopolitical environment at the time.” 

“We have a little bit of runway ahead of us to see what happens there,” he added. “I think we are going to wait just a little bit longer and see how the world evolves between now and then.” 

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Stakeholder Forum: Surplus Interconnection Can Maximize Capacity in ISO-NE

By Alex Lawton

We all appreciate the idea of squeezing out every last drop and making the most out of what you have. Our power grid should be no exception.

Yet in New England, rules governing how new resources connect to the regional grid limit full use of our system’s potential. Precious “surplus” capacity can and should be leveraged to interconnect new, low-cost clean energy technologies to deliver more reliable, affordable power.

Capacity surplus interconnection service (SIS) is a solution hiding in plain sight that would allow the region to harness more capacity resources. At its core, reforming capacity SIS is about optimizing every megawatt of deliverability at each point of generator interconnection.

Throughout the system, there often is a discrepancy between how much capacity a generator is allowed to offer to the grid (i.e. an interconnection service limitation) versus how much they’ve committed to actually offer via the capacity market, i.e., the “capacity surplus.”

Alex Lawton

Optimizing SIS could solve several problems for grid operators and policymakers amidst soaring electricity costs, rising demand, shifts in the resource mix and heightened emphasis on grid reliability. A reformed capacity SIS option would allow new capacity resources to interconnect to the system in a fraction of the time and at much lower cost, which has significant benefits for consumer bills. Interconnection historically has been protracted, expensive and risky for new generation and storage projects, adding to the cost to develop projects that customers pay for through rates.

SIS circumvents these problems because it allows new capacity resources to bypass long and expensive reliability studies if they are willing to respect the existing capacity limitations at the point of interconnection. Respecting these limits also ensures these new resources avoid costly system upgrades.

This more efficient path to connect to the grid will lower development costs and benefit ratepayers through bringing more capacity resources online faster to balance supply and demand. More capacity also supports resource adequacy and improves system reliability, keeping the lights on.

Other regions already have revitalized their capacity SIS rules to capitalize on these benefits. For instance, surplus reforms in MISO allow greater flexibility and speed for generators requesting surplus whilst ensuring that interconnection limitations are respected. As a result, MISO’s surplus process has garnered 3.6 GW of surplus service requests since 2021.

While capacity SIS technically is available in New England, outdated rules make it practically unusable for generators and prevent the region from harnessing capacity SIS opportunities. These barriers can be addressed with relatively modest revisions.

The first core issue is a restrictive condition that capacity resources must be “continuously available” on a permanent basis, which is impractical because it locks in a fixed quantity of surplus when in fact surplus availability constantly ebbs and flows based on performance audits as well as capacity accreditation. The fix: allow surplus resources the option for dynamic, periodic service.

Correcting capacity SIS deficiencies is timely specifically because of how it relates to capacity accreditation. ISO-NE is undertaking a major overhaul of its capacity market, including transitioning to a prompt and seasonal market and adopting a probabilistic approach to accredit resources based on their marginal value.

This new approach to capacity accreditation means accredited values may change significantly over time. As more renewables and advanced energy technologies enter the market, and as legacy plants receive derates for their imperfect performances during extreme weather events, accreditation values for many resources will drop. The key implication is that over time, the less capacity each generator can actually commit via their accredited limit, the more surplus headroom will open since the interconnection service limit — what generators are allowed to offer — stays the same. Ensuring capacity SIS rules are tied to accreditation reforms therefore will allow maximum use of surplus capacity on a continuous basis as accreditation values evolve.

The second core issue for surplus concerns what happens if an original generator retires, leaving just a surplus unit at the point of interconnection. Instead of allowing the surplus unit to maintain the interconnection limitation that applied to the original generator, which would enable the surplus unit to scale to that size, and avoid interconnection pitfalls, surplus units must go to the back of the line in the interconnection queue, with few exceptions.

Given the rising trend in generator retirements, a streamlined repowering process that allows surplus units to take over the interconnection rights in full and quickly begin injecting power into the grid could prove critical to maintaining electric system reliability.

In New England alone, the grid has the potential to unlock roughly 35 GW of new resources via surplus service — an amount higher than our region’s all-time peak demand. While that may be a high-end estimate, consider that according to the ISO’s 2025 CELT Report, there already is roughly 3 GW of capacity headroom on the system during winter time.

Once capacity accreditation reforms take effect in 2028, if results are similar to the previous impact analysis, approximately seven additional gigawatts suddenly could become available for the capacity commitment period in 2028.

Timing capacity SIS reforms now would dovetail with ongoing market reforms and address the urgent need for efficient new capacity resource entry. Recognizing this, industry stakeholders in New England have pushed capacity SIS reforms as a top priority for 2026.

This is a great opportunity for ISO-NE to follow through on the commitment it made in its FERC Order 2023 filing transmittal letter, promising to advance discussions on further interconnection reforms and measures that accelerate timelines.

The onus is on the ISO to undertake the initiative, gather stakeholder perspectives, and update its governing documents accordingly. If the ISO pursues these changes, New England’s grid has the opportunity to squeeze every last drop of surplus capacity to make the most out of our existing grid.

Alex Lawton is the wholesale markets director at Advanced Energy United.

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Six Reports Paint Picture of Slowing Energy Transition

Several new reports and updates give snapshots and predictions about the changing direction of the U.S. energy sector. 

Some of the organizations behind the updates identify as neutral and nonpartisan, but others are openly critical of the shift that began when Americans chose Donald Trump and his “Drill Baby Drill” message at the polls nearly a year ago. 

But while the reports each have a different focus and tone, all reach similar conclusions: Major changes are afoot, and they will have significant effects. 

    • After four years grading the top U.S. utilities at a collective D in its annual “Dirty Truth Report,” the Sierra Club gives them an F in its 2025 edition for delivering dirtier power at a higher cost. 
    • Rhodium Group in its annual “Taking Stock” report estimates the U.S. energy sector’s 2035 greenhouse gas emissions will be 26 to 35% lower than in 2005; only a year ago, Rhodium estimated a 38 to 56% reduction over the same period. 
    • The U.S. Energy Information Administration calculates that energy-related per-capita carbon dioxide emissions decreased in every state from 2005 to 2023 — 30%, on average — but forecasts a 1% increase in total U.S. CO2 emissions in 2025 due to increased fossil fuel consumption. 
    • In its latest update, Climate Action Tracker downgrades its rating for the U.S. from “insufficient” to “critically insufficient” due to the “most significant rollback of policies” it has ever analyzed. 
    • E2 reports in “Clean Jobs America 2025” that employment in the clean energy economy grew 17% from 2020 to 2024, far outstripping the rest of the energy industry and the U.S. economy as a whole, but says policy changes threaten future growth. 
    • The “2025 Production Gap Report” by Stockholm Environment Institute, Climate Analytics and International Institute for Sustainable Development looks at 20 countries and finds widespread plans to increase fossil fuel production. But it reserves a particularly blunt assessment for the world’s largest oil and gas producer: “The United States offers the starkest case of a country recommitting to fossil fuels, with plans to scale up its oil and gas production, arrest the decline of coal, slow clean energy development and electrification, and turn away from international cooperation on energy and climate change.” 

Details and Conclusions

The Sierra Club’s goals are lofty indeed — 100% coal retirement by 2030, 100% clean energy by 2035 and zero MW of new gas capacity planned by 2035. 

It said the utilities it studied had committed to only 29% on coal and 32% on renewables and are planning 118 GW of new gas, all while mounting a greenwashing campaign and raising rates faster than inflation. 

The Sierra Club faults the U.S. utility sector for planning to add 118 GW of new gas-fired power generation through 2035, a 20% increase in gas capacity. | Sierra Club

The Sierra Club gave out a handful of B’s in the 2025 edition of the “Dirty Truth Report” — Orlando Utilities Commission, Xcel Energy and Consumers Energy were ranked highest at 73, 69 and 65% — but together, the 75 utilities had an aggregate score of 15%, the lowest since the first edition of the report, in 2021. 

Sierra Club asserts that despite the dual pressures of load growth and vanishing federal support for clean energy, utilities must accelerate their decarbonization, not slow it down. 

In “Taking Stock 2025,” Rhodium prefaces its prediction of slower progress on greenhouse gas reductions with the root cause: 

“The first seven months of the second Trump administration and 119th Congress have seen the most abrupt shift in energy and climate policy in recent memory. After the Biden administration adopted meaningful policies to drive decarbonization, Congress and the White House are now enacting a policy regime that is openly hostile to wind, solar and electric vehicles and seeks to promote increased fossil fuel production and use.” 

Rhodium Group has modeled a series of scenarios for U.S. greenhouse gas emissions that vary based on fossil fuel prices, economic growth, clean energy technology and LNG export capacity. | Rhodium Group

Rhodium predicts that the rate of decline of GHG emissions will slow but does not attempt an exact prediction because so many variables are in play — fossil fuel prices, the growth of the U.S. economy, the cost of clean energy technology and the growth in U.S. LNG export capacity. 

There also is an “incredibly dynamic” policy environment, continued demand for clean technologies and persistent non-cost barriers to renewables, it adds. 

Rhodium assumes the 31 regulatory policies EPA Administrator Lee Zeldin has targeted for “reconsideration” will be removed. 

The EIA said the sharp reduction in energy-related CO2 emission reductions so far this century can be attributed primarily to reduced combustion of coal for power generation; increased use of natural gas, which burns cleaner; and the rise of emissions-free wind and solar generation. 

U.S. energy-related CO2 emissions dropped 20% from 2005 to 2023 while the population grew 14%, a 30% per-capita decrease.  

In 2016, transportation surpassed electric power as the largest energy-related CO2 source in the U.S., EIA said. 

The U.S. Energy Information Administration reports that every state reduced its carbon dioxide emissions between 2005 and 2023, with an average decrease of 30%. | EIA

The Climate Action Tracker (CAT) rated 40 countries and found none had policies in place to meet the goals of the 2015 Paris Agreement. Eight nations are “almost sufficient”; the U.S. and nine others are “critically insufficient”; and the other 23 fall in between. 

“The Trump administration is pursuing an agenda to systematically repeal federal climate targets, policies and funding for climate change mitigation, blocking progressive actors,” the report said, “while encouraging the production and consumption of fossil fuels at home and abroad, completely reversing the previous administrations’ course on climate action.” 

Pro-climate policies continue in some U.S. states, but the nation as a whole has stepped away from net-zero aspirations, CAT said. 

“It is shocking how rapidly and how systematically the Trump administration has moved to roll back efforts to reduce greenhouse gas emissions, while aggressively expanding support for the production and consumption of fossil fuels, in defiance of clear market signals,” said the assessment’s lead author, Finn Hossfeld of the NewClimate Institute. 

E2 tallied more than 3.5 million workers in 50 states in its 10th annual analysis of U.S. clean energy employment, 522,000 of them in jobs created since 2020. It said 82% of net new energy sector jobs in 2024 were in clean energy. 

“This trend was expected to continue as clean energy accounted for larger and larger shares of energy industry jobs and the nationwide workforce,” the authors wrote. “But recent policy decisions to revoke incentives, cancel permits, and target the industry with new red tape and legal hurdles threatens future growth and, increasingly, the health of the U.S. economy at large.” 

E2 offered no specific job-loss predictions of its own but said $22 billion worth of projects and factories have been canceled at a cost of 16,500 jobs, and it said other organizations have predicted more than 830,000 jobs economywide could be lost by 2030 due to U.S. energy policy changes. 

“Clean Jobs America 2025” runs 42 pages, most of them filled with geographic- and industry-specific data drawn from the U.S. Bureau of Labor Statistics via the U.S. Department of Energy’s 2025 U.S. Energy and Employment Report. 

Derik Broekhoff, coordinating lead author of “2025 Production Gap Report,” said: “As our report makes clear, while many countries have committed to a clean energy transition, many others appear to be stuck using a fossil-fuel-dependent playbook, planning even more production than they were two years ago.” 

The 2025 report finds that governments worldwide plan to produce a 120% greater volume of fossil fuels in 2030 than would be consistent with limiting global warming to 1.5 degrees Celsius, the target specified in the Paris Agreement. 

But this last point is a bit academic for the U.S.: Trump withdrew the nation from the Paris Agreement early in his first term and withdrew it again on the first day of his second term. 

None of the new reports and updates, whether critical or merely analytical, seem to have made any impact on the driving force behind the U.S. energy policy shifts that are influencing the data in those reports. 

Speaking before the United Nations General Assembly on Sept. 23, Trump called climate change “the greatest con job ever perpetrated on the world,” provoking grumbles and murmurs from his audience. 

“If you don’t get away from the green energy scam, your country is going to fail,” he said. 

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SPP Considers Deferring 765-kV NTCs to 2026

SPP says accelerating load projections will result in a 2025 transmission plan that dwarfs the previous year’s record $7.65 billion portfolio — so much so that it is considering deferring some projects until 2026. 

Staff said during a Sept. 23 education session on the 2025 Integrated Transmission Planning assessment that they may recommend delaying construction permits for five 765-kV projects, totaling more than $5 billion in building costs, to the 2026 ITP. 

Having only received approval for its first 765-kV project in February 2025, Southwestern Public Service’s 354-mile transmission line crossing the New Mexico-Texas border, SPP staff have experienced firsthand the vagaries of the facilities’ high costs. 

The project initially was projected to cost $1.69 billion. SPS revised the estimate to $3.62 billion in June. It took several months and more meetings and discussions with stakeholders before the Board of Directors eventually approved the revised cost estimate in September. (See SPP Board Approves 765-kV Project’s Increased Cost.) 

“We realize that these projects are very costly … we do expect to continue to show some additional cost sensitivities,” transmission-planning manager Kirk Hall said during the Markets and Operations Policy Committee’s education session. “We’ve talked a lot about the costs of the portfolio and obviously, affordability is top of mind. We’ve heard that loud and clear from stakeholders. We realize this is a significant investment.” 

“You can add as many projects as you want, and you are going to get some benefit, but at some point, that amount of reliability is not affordable to customers,” Oklahoma Gas & Electric’s Brad Cochran said, referring to the discussions over the SPS project. “You guys did a good job of putting some deferrals in there, but we need to make sure that not only [are we] making the system reliable, but we’re making it affordable so that customers can actually pay their bills.” 

SPP said the draft portfolio costs $19.1 billion but provides about $80 billion in benefits, a benefit-cost ratio of between 5.8 and 9.5. That doesn’t include reliability benefits or the cost of outages. 

Having identified the need for 765-kV transmission in the 2024 ITP, staff developed the EHV overlay and shared it with the board, state regulators and members in September. (See SPP, Members Developing 765-kV Transmission Overlay Plan.) 

Hall said staff will vet their deferral recommendation with the Transmission and Economic Studies working groups before MOPC’s October meeting. 

SPP told the committee that the 2025 portfolio is the result “of our most comprehensive ITP process in history.” Staff began with more than $20 billion in projects identified to meet all needs. It may end up with between $14 billion and $18 billion in projects that are issued notifications to construct, more than double the 2024 portfolio. 

Casey Cathey, SPP’s vice president of transmission, said the hefty portfolio is necessary. He recalled a time less than 10 years ago, when SPP was “excited” by 1.2% load growth year over year.  

“We’re seeing more than double that today, and we’re seeing a lot higher, accelerated growth in the future,” he said.  

Cathey told MOPC that the 10-year firm load projections for 2033 that drove the record 2024 portfolio are expected to occur six years earlier in the latest forecasts. He pointed to voltage and transfer issues the grid operator faces, three load sheds in 2025, three winter peaks in the past five years and load-responsible entities forecasting new large loads that will require more transfer capacity: “We currently peak at 56 GW, and adding the amount of load that we have on the horizon … is, quite frankly, breaking the system. We will need to build transmission. Generation alone cannot solve our challenges.” 

The RTO expects future loads to increase. Staff referenced President Donald Trump’s executive order to “pursue bold, large-scale industrial plans” that “vault” the U.S. “further into the lead” on critical manufacturing processes and the Department of Energy’s Speed to Power initiative.  

According to the DOE, data centers used 58 TWh in 2014. That number increased to 176 TWh in 2023, 4% of all U.S. electricity. By 2028, the agency expects data centers to need between 325 and 580 TWh, which would be 6 to 12% of the nation’s annual energy. 

Data centers account for 23% of SPP’s large loads in the ITP (2.5 GW of 11 GW), but oil and gas electrification in the Permian Basin and the Dakotas is responsible for double that. Combined, projected large loads are equivalent to 20% of the grid operator’s current peak. 

“There is heavy pressure to ensure that we’re not only reassuring critical manufacturing but also doing what we can to provide bold infrastructure plans for large loads,” Cathey said. “We’re looking at this and seeing what opportunities we might have as we continue to plan the system out, not only for 765 kV but, just ultimately, the overall transmission infrastructure that we need.” 

The grid operator plans to release the ITP draft report Sept. 24. 

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Speculative Data Centers Highlight Need for Effective Forecasting, Experts Say

Utilities face significant forecasting risks from large loads, prompting the industry to develop strategies to eliminate counting of speculative projects, experts said during a Western Interstate Energy Board webinar. 

Natalie Frick, deputy department leader of energy markets and policy at the Lawrence Berkeley National Laboratory, and Shana Ramirez, director at Energy and Environmental Economics, discussed the challenges of large loads during a Sept. 12 webinar. 

Citing data from the Electric Power Research Institute, Frick noted that all 25 utilities participating in a study on load forecasting reported challenges incorporating data centers into load forecasts. 

About half of the utilities in the study included the full requested data center capacity in their load forecast, a third included a derated capacity and six utilities did not include any of the data center requests in their forecast at all, Frick said. 

“All of the utilities that they interviewed identified that they’re facing challenges with incorporating data centers into load forecasts, in particular because of the speculative nature of the service requests that they’re receiving,” Frick added. 

There is no agreed-upon approach for load forecasting, but speculative load interconnection requests can skew the numbers across the board, Frick’s presentation slides showed. 

Georgia Power forecast a 107% compound annual growth rate for commercial large load summer peak load in the 2025 interconnection request process. But several projects have pulled out, and net load reductions are concentrated across data center projects, “particularly those that were in the earlier stages of advancing through the interconnection process,” Frick said. 

Dominion Energy forecast $1.5 billion in data center capital spending between 2025 and 2027. After staff further reviewed the interconnection requests, they removed $853 million in data center expenditures “because they identified that those were speculative,” Frick said. 

“They didn’t think that … those customers had enough skin in the game to really include them in the forecast,” she added. 

Also, there is no “standard large load tariff,” Frick said. 

“Regulators can design the tariffs to meet their state energy goals, and those could be a variety of things,” she noted. “They could be seeking to improve or strengthen resource adequacy, affordability, attracting large load customers and also air pollutant emissions reductions. And so those are all kind of some of the motivations behind these tariffs.” 

Ramirez highlighted that large load growth exposes utilities to nonpayment risks, as well as potential stranded assets and credit challenges, underlining the need for effective risk mitigation strategies. 

Ramirez said there is a spectrum of what utilities are doing to mitigate those risks, ranging from “very lenient” to “very strict.” 

Dominion recently proposed collateral of $1.5 million per MW for large load customers that would be included in their rate costs. 

This is “much higher than what we’re seeing in other utility jurisdictions that probably have more risk, like Evergy Kansas, Evergy Missouri, where they’re just asking for two years of minimum bills as collateral,” Ramirez said. 

Ramirez said there are some “best practices” utilities can implement. The practices should enable cost recovery, support responsible growth and promote fair treatment of all customers, according to the presentation. 

“They should be flexible, transparent, consistent, scalable, adaptable and standardized, and [they] should align the financial security requirement with evolving risks,” Ramirez said. 

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Stakeholder Forum: The Craziness of Natural Gas Bans

By Kenneth W. Costello

Political efforts to curtail gas supply and demand have met with limited success. Methane rules, drilling restrictions on public land and opposition to new pipelines have only incrementally slowed the growth of natural gas in the United States. But the obstinate anti-fossil-fuel lobby and its government allies want much more: moratoriums on new gas service and bans on natural gas usage and appliances.  

Bans by municipal jurisdictions with (presumably) the legal authority to do so have been in the news for some time. The City of Berkeley initiated municipal efforts in July 2019 to electrify (especially via electric heat pumps and electric stoves) by prohibiting natural gas in new buildings. (Incidentally, the initiative was struck down by the courts.) 

Since then, various municipalities and states have sought to restrict the use of gas in new buildings. For example, as of early 2024, dozens of local governments in seven states and the District of Columbia had imposed or passed ordinances for natural gas restrictions. New York became the first state to pass legislation imposing statewide natural gas restrictions affecting the state’s local governments. Some cities have even considered banning or restricting natural gas appliances from existing homes and businesses, as well.  

Kenneth W. Costello

The primary purpose of these efforts is to mitigate climate change, however infinitesimal in the whole, by making buildings zero-carbon. A ban is much more extreme than just creating a tax to discourage consumption of a product or service. With a tax, the decision is left to consumers on how much of a product or service to purchase. A tax can counter a negative externality that is unaccounted for in the decisions of either suppliers or consumers, such as pollution or second-hand smoke; a gas ban obliterates consumer choice for meeting space and water heating needs, not to mention a flame for superior cooking and taste. 

More fundamentally, such prohibition violates consumer freedom to purchase a wanted product or service like natural gas in place of an inferior one, namely electricity. Cheapness and quality are sacrificed on the altar of an environmental fixation that is debatable.  

In economic terms, a gas ban fails miserably, with the benefits virtually zero and the costs potentially high. Thus, the benefit-cost (B-C) ratio is close to zero or the C-B ratio is infinite; or as public policy, a ban is off the charts as being exceptionally socially destructive.  

Here is why: Less than 9% of carbon-dioxide emissions in the U.S. come from direct use of natural gas in homes and buildings. The U.S. emits about 15% of world CO2 emissions. Thus, converting all buildings to all-electric, and assuming that all electricity is produced from “clean” sources (it is not), reduces worldwide emissions less than 1.5%, which according to climate models, would have less than a detectable effect on global climate, temperature, sea level or otherwise.  

A ban can look good politically by giving the false impression that a severe problem is receiving immediate, absolute attention. And a ban certainly is less widespread than a carbon tax or a budget gap from new taxpayer subsidies. But at least these two approaches preserve consumers’ option to choose their energy source, rather than preclude them from doing so with a ban. 

The observation that a gas ban descends predominantly from a quasi-religious opposition to fossil fuels is credible given the lopsided cost-benefit calculus. Climate activists regard natural gas as competing with renewable energy in power generation and for electricity in end-use applications. Their position seems to be that “getting rid of the competitor” would make it easier to have more renewable energy and clean electricity.  

It is only because of special interests that local and state governments would even consider prohibiting consumers from choosing natural gas as an energy source to meet their space, water heating and cooking needs. After all, in most parts of the country where gas is available, it is the most economic and desired source of energy.  

Gas bans are little more than symbolic, reflecting a stance of “we have to do our part,” or perhaps more accurately “whatever it takes to combat climate change,” even if bans resoundingly fail a cost-benefit test. 

Good public policy balances the economic and environmental consequences in enhancing the public interest. Because a gas ban — command-and-control policy at its worst — has virtually no effect on global climate and inevitably will increase cost and reduce quality for consumers, one would have to look hard to find a governmental action on energy that is so intrusive, imbalanced and detrimental to society’s welfare. 

One cannot avoid concluding the craziness of banning or even restricting a product like natural gas that has greatly benefited, and will continue to do so, both energy consumers and the economy. A ban on natural gas is throwing out the baby with the bathwater. 

Kenneth W. Costello is a regulatory economist and independent consultant who resides in Santa Fe, N.M. 

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Entergy Uses Ark. Energy Emergency Laws to Justify Gas Plant Plans

Entergy Arkansas says a recently enacted Arkansas law strengthens the case for its plan to build a new natural gas plant, a proposal that has drawn criticism from the state’s attorney general and regulatory staff.  

The utility applied to build the 754-MW Jefferson Power Station near Redfield, Ark., in early August, but staff with the Arkansas Public Service Commission and state attorney general’s office asked the PSC in early September to deny the utility’s proposal.  

The two agencies cited underdeveloped studies, a neglected analysis of alternatives, uncertain costs and a lack of ratepayer protections (25-047-U). The proposed plant would be adjacent to the utility’s White Bluff coal-fired power station, which is slated for retirement in 2028. Entergy envisions the gas plant would begin operation in 2029. 

In a Sept. 19 round of filings, Entergy Arkansas’ rebuttal to state officials invoked acts 373 and 940, both passed by the Arkansas legislature in 2025.  

Act 373, also known as the Generating Arkansas Jobs Act, makes it easier for electric utilities to finance new construction projects, while Act 940 adds review for retiring dispatchable generation and emphasizes a reliable, adequate and affordable power supply with the PSC fostering development. Both laws contain emergency clauses.  

John Bethel, director of public affairs at Entergy Arkansas, said the Jefferson Power Station is exactly the type of resource the state legislature envisioned and will be “critically important” as the utility’s largest gas plant.  

Bethel said the plant is “undoubtedly necessary for [Entergy Arkansas’] long-term ability to provide adequate supplies of reliable, affordable and dispatchable power to all customers.”  

In accordance with the two laws, he said, Entergy is prioritizing speed to market for new, dispatchable generation to serve economic development. He added the utility was able to secure in-demand components for the plant “at a time when it is very difficult to procure new gas resources of this kind.”  

Entergy hasn’t publicly disclosed the cost of the plant, citing an incomplete engineering, procurement and construction agreement. The utility has redacted total price estimates in public filings. 

Entergy also has proposed that the Cypress Solar project — consisting of a 600-MW solar array and a 350-MW battery energy storage system — be paired with the natural gas project. The utility estimates that both projects would add $4.87 to an average residential customer’s monthly bill.  

Kandice Fielder, Entergy Arkansas’ senior manager of resource planning, said no one has disputed the utility’s need for the new capacity. She said Entergy’s analyses show that adding the gas plant would “yield substantial net benefits to customers” by using land the utility already owns and White Bluff’s interconnection rights.   

Fielder said more than 80% of project costs would originate from two competitive solicitations Entergy Arkansas conducted.   

‘Methodological Flaws’

Jeffrey Bower, a consultant with Daymark, in early September filed testimony on behalf of the Arkansas PSC contending that Entergy failed to meet the commission’s resource planning guidelines because it didn’t compare the self-built resource to “market opportunities.” He also said that Entergy didn’t propose any cost containment or consumer protections or compare the new gas plant with a conversion of White Bluff to burn an alternative fuel.  

“The attempts by the company to compare the project to alternative options are either inadequate or contain methodological flaws,” Bower said. He noted that Entergy appeared to assume EPA regulations eventually requiring carbon capture technology would be repealed even though they’re not yet dismantled.   

Bower asked the PSC to order Entergy to supplement the application with more analysis and protections for ratepayers.  

But Bethel said Bower’s stance “must be revisited” given that the legislature has charged the Arkansas PSC with eliminating obstacles to developing a “diverse” generation fleet that includes “cost-effective dispatchable electric generation.” 

Bethel also said Entergy may consider converting White Bluff’s coal units into a natural gas peaker plant. However, that conversion would not be enough of a substitute for the Jefferson Power Station. He said ordering a comparison of the coal plant conversion to the new gas plant “is a red herring because the resources are not directly comparable.”  

Arkansas Attorney General Tim Griffin similarly opposed Entergy’s proposal. Scott Norwood, an energy consultant who filed testimony on behalf of Griffin’s office, said Entergy hasn’t shown the Jefferson plan would come in at a reasonable cost or “is the best available resource for meeting [Entergy’s] system capacity need in 2030.” 

Norwood also said that the utility did not explore the alternative of converting White Bluff from coal to gas, which “would have a far lower cost.” He added that Entergy’s other economic analyses of the plant are “based on unreasonable cost assumptions that serve to overstate the benefits.”  

Meanwhile, in its Sept. 22 report, The Dirty Truth, the Sierra Club faulted Entergy for overcommitting to natural gas and backpedaling on sustainability goals.  

Entergy in 2019 committed to reducing its emissions by 50% by 2030, followed by a 2021 commitment to 50% carbon-free generating capacity by 2030. However, in late 2024, the utility said its capacity goal would be “delayed for an as-yet undetermined period beyond 2030” and said its emissions timeline could slip based on growing demand. Entergy said it recognized that “some of our new generation resources will be cleaner but not carbon-free.”  

The utility said it remains committed to its long-term carbon target of net-zero emissions by 2050.  

The PSC has scheduled a public hearing for the Jefferson plant Oct. 30 and expects to issue a final order near the end of January 2026.  

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Meta Files with FERC to Create Its Own Power Marketer: Atem Energy

With the age of hyperscalers ramping up, Meta is the latest major tech firm to ask FERC for market-based rate authority as it sets up its own internal power marketer: Atem Energy (ER25-3440).  

Meta, which owns Facebook and Instagram, is one of many firms developing artificial intelligence applications that have been a major contributor to the resumption of overall power growth after a couple of decades of stagnation. 

Atem Energy is a Delaware-based company that has been formed to act as a power marketer to sell energy, capacity and certain ancillary services at wholesale in the United States. The firm’s MBR application does not specify where it will market power. 

Meta is not the first big tech firm to seek MBR authorization: Alphabet’s Google has had it since 2010 (ER10-2835), Amazon since 2015 (ER15-1905) and Microsoft since 2021 (ER21-964). Companies in other sectors have been at it even longer, notably Walmart, which set up its in-house power marketer, Texas Retail Energy, in 2002. 

A major company setting up its own power marketer to secure power supplies comes with some benefits, but significant costs as well, Electric Advisors Consulting’s Frank Lacey said in an email. 

“In the plus column, you can design an electricity product tailor-made to your needs, including renewable attributes, risk management strategies, billing allocations and other,” Lacey said. “You can also avoid the profit margins built into other suppliers’ products. 

“On the flip side of that coin, you have to build out an energy team, presumably with some trading and risk management expertise,” he said. “You have to be registered with FERC to sell electricity at market-based rates. You need to be a member of each RTO you have facilities in and bear those costs, including credit requirements.” 

If Meta wants to become a state-regulated retailer to supply its facilities, it needs to register with their regulatory commissions and set up data exchanges with the relevant utilities, he added. 

“You have to bear the risk of your own energy hedges and non-hedged positions, and as an RTO market participant, you own a share of the marketwide risk should any market participants go bankrupt,” Lacey said. “If the company has the resources to do all of this, it might make sense. On the other hand, I would think a company like Meta would have enough horsepower to attract a lot of attention from the existing suppliers in the market.” 

Neither Atem nor its upstream ownership at Meta own any facilities that are for the generation, transmission or distribution of electric power. Meta CEO Mark Zuckerberg owns more than 10% of its shares, which triggers additional requirements, but he does not “directly or indirectly own or control a 10% or greater voting interest” in any generator or other energy assets in the United States, the application said. 

The lack of existing assets in the power markets means Atem lacks horizontal or vertical market power, which satisfies the requirements for FERC to grant MBR authority, the application said. 

The application seeks authority to sell ancillary services at market rates in CAISO, ISO-NE, MISO, NYISO, PJM and SPP. Atem asked for an effective date of Nov. 16, 2025, for its MBR authority. 

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New England Energy Experts Talk Renewable Development Under Trump

BOSTON — Energy experts and officials stressed the importance of proactive transmission planning, interconnection reform and increased demand-side flexibility at Raab Associates’ New England Electricity Restructuring Roundtable on Sept. 19.

Speakers at the event reflected on the challenges the One Big Beautiful Bill Act (OBBBA) and the Trump administration’s executive actions have created for clean energy development in New England, but they generally expressed optimism around the region’s ability to withstand the federal headwinds.

“There will be pain, there will be companies that close, there will be less deployment as a result of the changes at the federal level,” said Nathan Phelps, managing director of regulatory advocacy at Vote Solar.

However, “solar will not fall off a cliff” because “the price of solar has come down a lot, and it continues to be an attractive investment,” Phelps said.

The OBBBA dramatically expedites the expiration of federal tax credits for wind and solar developers, and new projects must either begin construction by July 5, 2026, or come online by Dec. 31, 2027, to qualify for the full tax credits established by the Inflation Reduction Act. (See U.S. Clean Energy Sector Faces Cuts and Limitations.)

In New England, the looming tax credit phaseout has caused a mad dash for solar developers to try to lock in credits for later-stage projects, which may boost development in the short-term. Meanwhile, projects unable to begin construction in time for the deadlines likely will face increased risks of cancellation or major delay.

While the longer-term effects of the shift in federal policy are less clear, the Trump administration’s antagonism toward offshore wind in particular threatens to undermine the buildout of a strong regional supply chain and workforce, which could have effects extending well beyond Trump’s second term. (See Tax Credit Phaseout Threatens Projects, Jobs in New England.)

In the wake of the Trump administration’s stop-work order on Revolution Wind, “it’s really hard to have any confidence around what we can expect from the federal level,” Phelps said.

Alicia Barton, CEO of Vineyard Offshore, emphasized the importance of offshore wind for meeting load growth in the coming decades.

“I don’t think we have a choice — the region needs offshore wind,” Barton said.

She declined to comment on the halt on Revolution Wind, which is being developed by Ørsted, but said Vineyard Wind, which is being developed by Vineyard Offshore and Avangrid, still aims to achieve commercial operations by the end of the year.

“We are still constructing, we are still moving forward,” Barton said, adding that Vineyard Wind has created 3,400 jobs, including 1,400 union jobs.

On Sept. 22, after the roundtable, a U.S. District Court judge issued an injunction allowing construction to resume on Revolution Wind. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)

Interconnection Reform

Speakers also discussed how reducing the soft costs of renewable development — including costs and delays associated with siting, permitting and interconnection — could help mitigate the effects of federal policy changes.

On interconnection, “the most important near-term thing is implementation of Order 2023,” said Caitlin Marquis, managing director at Advanced Energy United.

FERC Order 2023 requires transmission operators to adopt first-ready, first-served cluster processes for interconnection. ISO-NE’s first cluster study under the new rules will begin in October.

“ISO-NE deserves a lot of credit for holding a robust stakeholder process to implement Order 2023,” Marquis said, while emphasizing that interconnection reform must go further than Order 2023 compliance to better integrate interconnection planning into the transmission planning process.

From left: Digaunto Chatterjee, Eversource; Caitlin Marquis, Advanced Energy United; Rob Gramlich, Grid Strategies LLC; Mike Judge, Massachusetts Executive Office of Energy and Environmental Affairs; Janet Gail Besser, moderator | © RTO Insider 

Marquis also highlighted the potential benefits of processes that allow new resources to share interconnection service with existing ones. She noted that ISO-NE has a surplus interconnection service option in its tariff but that stakeholders seek more flexibility.

At the state level, the administration of Massachusetts Gov. Maura Healey (D) has “made good strides” toward a more proactive approach for resource interconnection but is seeking to “consolidate some of the siloed processes into a more comprehensive planning process,” said Michael Judge, undersecretary at the Massachusetts Executive Office of Energy and Environmental Affairs.

He said state officials hope to replace the Capital Investment Project process, a provisional program intended to enable fixed distribution interconnection costs, with a proactive interconnection planning process incorporated into the utilities’ five-year electric-sector modernization plans.

Rob Gramlich, president of Grid Strategies, praised increased transmission planning initiatives taking place across New England. He noted that ISO-NE rated poorly in a pre-Order 2023 interconnection “report card” but that the Order 2023 compliance changes should help address some of the issues. (See Transmission Report Card Grades MISO ‘B,’ Southeast ‘F’.)

“Transmission planning is the key solution here,” he said.

Demand Response

Multiple speakers stressed the need to focus on demand response and flexibility.

For policymakers looking to decarbonize at the lowest possible cost, “one resource is way more important than all the others, and that’s the demand side,” said Paul Hibbard, principal at the Analysis Group and former chair of the Massachusetts Department of Public Utilities.

Hibbard said unlocking the full potential of demand response will require “fundamental changes” to rate design and programmatic spending.

“The technological hurdle to this is not a big one, it’s really getting the price incentives up and running and the infrastructure in place,” he said, adding that states must begin this work as soon as possible given the “painfully slow” pace of ratemaking.

Massachusetts’ electric utilities aim to finish deploying advanced metering infrastructure across their service territories by the end of the decade, which should enable increased retail price incentives to reduce demand during peak periods.

“Electrification depends on it, affordability depends on it, and ultimately the commonwealth’s decarbonization policy depends on it,” Hibbard said.