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December 15, 2025

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IMM: MISO Should Penalize Gen that Falls Flat on Emergency Output

The MISO Independent Market Monitor has called on the RTO to develop a penalty system for generation that doesn’t rev up into emergency ranges as promised to assist a maxed-out grid.

The Monitor said it noticed some generators didn’t attempt to depart their economic output for emergency output during the May 25 load shed event in Greater New Orleans. (See MISO Says Public Communication Needs Work After NOLA Load Shed.)

MISO generation resources keep emergency maximums on file that are higher than their stated economic ranges. The RTO is allowed to access units’ emergency dispatch ranges after it has declared an emergency.

IMM Carrie Milton said that on May 25 in MISO South, 140 MW worth of emergency ranges were offered as available, but half of it ultimately didn’t show up.

At an Entergy Regional State Committee meeting July 29, Milton said MISO should create consequences for generation “not moving into the emergency ranges when they’re instructed to do so.”

MISO Executive Director of Market and Grid Strategy Zak Joundi said the RTO is tracking nonperformance of units and is pondering solutions to incentivize resources to dip into emergency ranges. He said MISO also may decide it needs to provide clearer notifications to units when red-alert-level output is necessary.

“We’re finding that there are gaps,” Joundi said of a MISO analysis of past emergency range performance.

Joundi said MISO will bring “a full narrative” to the Market Subcommittee soon. In response to MISO South regulatory staff questions, Joundi said he couldn’t offer a timeline on when the RTO might develop a process to correct generators’ behavior.

Ultimately, resources that get paid for capacity must deliver megawatts, Joundi said. “If not, there have to be consequences.”

Louisiana Public Service Commissioner Eric Skrmetta said it seemed like some resources “need a stick instead of a carrot.”

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DOE Extension of Michigan Coal Plant Cost $29M in 1st Month

The Michigan coal plant kept online by an emergency order from the U.S. Department of Energy cost $29 million to run in a little over a month. 

That’s according to Consumers Energy’s recent Securities and Exchange Commission filing, where the company notes a $29 million “net financial impact” of extending operations of the J.H. Campbell plant from May 23 to June 30. 

In May, Energy Secretary Chris Wright issued an emergency order under the Federal Power Act requiring J.H. Campbell to continue operating for 90 days through Aug. 20. The plant has about two more months — and it appears, several more millions of dollars — before Consumers can retire it as planned. 

DOE’s order did not include federal funding to keep the Campbell plant operational. Consumer advocates and environmental nonprofits expect that costs associated with the extension will be passed on to consumers in Michigan and neighboring areas in MISO Midwest. 

Consumers said in its filing that it has “continued to make J.H. Campbell available in the MISO market,” consistent with the department’s order. The utility also noted its pending complaint with FERC that seeks to alter the MISO tariff to develop a means to recover plant costs while the order is in effect. 

MISO declined to comment on whether it has dispatched J.H. Campbell in its markets since late May. The RTO said individual unit dispatch data is not available to the public. 

“MISO, Consumers and the joint owners [of the plant] are taking all appropriate action to comply with the DOE order,” spokesperson Brandon Morris said in a statement to RTO Insider. 

Consumers did not respond to RTO Insider’s questions on how often the plant has been used since the DOE order or how it is planning to recoup costs.  

Earthjustice, one of the organizations suing the DOE over its order along with Michigan Attorney General Dana Nessel, said ratepayers are poised to fund the utility’s expenses for the plant “plus a return on any capital investments.” (See Opponents Take DOE to Court over J.H. Campbell Retirement Delay.)  

“The Trump administration is raising people’s electricity bills with its promotion of coal at all costs. The illegal abuse of emergency powers to force an aging coal plant to keep burning coal has real costs for consumers, who the administration suggests should be forced to pay millions for this unnecessary dirty power plant that is polluting their air,” Earthjustice attorney Shannon Fisk said in a statement to RTO Insider. “Meanwhile, clean electricity sources that have almost zero operating costs, such as solar and wind, can get pushed out of the market when aging coal plants are forced to stay online.” 

The Institute for Energy Economics and Financial Analysis has pointed out that operation and maintenance for Units 1 and 2 at the plant totaled $45.80/MWh over 2023, higher than energy prices nearly all the time at the Michigan hub. The units are 63 and 58 years old, respectively. 

MISO’s Independent Market Monitor has repeatedly said the coal plant is not necessary for reliable summer operations in the footprint. 

At MISO’s Market Subcommittee meeting in July, IMM Carrie Milton explained that this year’s capacity auction — the first to feature a sloped demand curve — cleared more capacity than necessary to satisfy the RTO’s reserve margin requirement, making J.H. Campbell’s federal operating extension “absolutely unnecessary.” Milton said going forward, the sloped curve should send all the signals necessary for MISO members to plan new generation or decide whether to hang on to existing generation longer through retirement deferrals. 

MISO itself studied the retirement of J.H. Campbell three years ago and determined in March 2022 that it could shut down as planned without the RTO needing it to stay online as system support resource. 

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PPL Briefs Analysts on Efforts to Serve Data Centers in Pa., Ky.

PPL expects that the current surplus of generation in its Pennsylvania territory will be lost to demand growth from data centers in the next five years and said it has plans to help meet that growing demand with new generation. 

“We have made it a strategic priority at PPL to serve data centers across our service territories, as AI will be critical to America’s continued competitiveness and national security, as well as the execution of our utility-of-the-future strategy,” CEO Vincent Sorgi said on the company’s second-quarter earnings call July 31. “We are enabling speed to market for the data centers by being able to connect them to the grid faster than they can get the data centers built.” 

PPL sees about 14.5 GW of data centers in advanced stages of development that could come online by the early 2030s. Assuming those all come online, the net long position in PPL’s territory would disappear, and an additional 7.5 GW of supply would be needed. Sorgi said that while the numbers outside its territory are fuzzier for the firm, Pennsylvania could need an additional 12 GW. 

“Our current capital plan includes another $7 billion through 2028. That means we can connect data centers as quickly as developers can build them,” Sorgi said. 

Once the existing long generation is used up, PPL would shift to building out more generation, and it is backing a few horses there. The company has entered a joint venture with Blackstone to supply data centers using “energy services agreements” (ESAs), which was announced at a high-profile event in July. (See $92B in Power, Data Center Infrastructure Planned in Pa.) 

“Those ESAs will have regulated-like risk profiles that do not expose the companies to merchant energy and capacity price volatility as PPL is not getting back into the merchant generation business,” Sorgi said. “Therefore, construction of any new generation will require the successful execution of ESAs with hyperscalers. The joint venture is actively engaged with hyperscalers, landowners, natural gas pipeline companies, turbine manufacturers and land parcels to enable this new generation buildout.” 

Sorgi did not want to get into much more detail about the ESAs, as negotiations are ongoing, but he anticipated placing orders for new natural gas-fired turbines by next year. 

PPL is also still backing legislation that would let the utility rate-base new generation in Pennsylvania, which would represent a major shift in policy for an early and once enthusiastic adopter of restructuring and wholesale markets. (See Utilities Pushing for Return to Owning Generation in Pennsylvania.) 

A pair of bills that would authorize utility-owned generation are pending in the relevant committees in the Pennsylvania General Assembly: SB 897 and HB 1272. 

“Both the House and Senate bills would allow regulated utilities, like PPL Electric Utilities, to build and own generation again to solve a resource adequacy need,” Sorgi said. “And both pieces of legislation would also encourage utilities to enter into agreements with [independent power producers] to help de-risk their new generation investment. As a company, we are primed to act quickly once this proposed legislation becomes law.” 

A key difference between the deal with Blackstone and building its own generation is that the former would require PPL Electric Utilities to run an open request for proposals to get around affiliate rules, while the latter could happen without any competition. 

PPL’s subsidiaries in Kentucky — Louisville Gas & Electric and Kentucky Utilities — are also seeing load growth. The utilities have entered a deal in a pending certificate of public convenience and necessity proceeding to build new gas plants, among other investments. 

“The stipulation strikes the right balance between building new generation needed to support economic development in the state, including supporting anticipated data center load, and ensuring we maintain affordability for our customers,” Sorgi said. 

The utilities will build two new 645-MW combined-cycle natural gas plants, add selective catalytic reduction to Ghent Generating Station Unit 2 and extend the 300-MW Mill Creek coal plant Unit 2’s life from 2027 to at least 2031, with analysis required in their next integrated resource plan to consider keeping the plant open even longer. They also withdrew a request to build a new battery storage plant in the state, but without prejudice so that project could still be developed in the future, Sorgi said. 

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Industry, Regulators Grapple with AI Demand at NARUC Policy Summit

BOSTON — Growing power demand from data centers dominated conversations at the NARUC Summer Policy Summit, where industry members and Trump administration officials advocated for the rapid addition of fossil fuel resources and infrastructure to meet anticipated load growth.  

Speakers at the event framed the AI industry in terms of a global arms race and argued that regulators must be hyper-focused on enabling new resources to come online at a faster pace. 

“I think there is a definite need for the regulatory framework to become more reflective of the world that we live in,” said Corey Hessen, CEO of Homer City Redevelopment, which is developing a campus of gas-powered data centers on the site of a recently retired coal plant in Pennsylvania.  

“The world that we live in means that new load and new generation has a demand to come online faster than ever before, and that will mean that the utilities and regulators must work together to come up with a framework that’s representative of what those needs are,” he said. 

The NARUC meeting, July 27-30, featured noticeably little talk of decarbonization, reflective of rising power demand across the country and the dramatic shift in federal energy policy under the Trump administration. 

Pablo Koziner, chief commercial and operations officer of GE Vernova, said the company has seen a massive surge in orders for gas equipment in recent months.  

GE Vernova has reported a 55-GW backlog of industrial gas turbine bookings and under-reservation agreements, which it expects to continue to grow over the coming years. (See GE Vernova’s Gas Power Equipment Surge Continues.) The company also has a major backlog on electrical equipment orders, including switchgear and transformers. 

“We’re just experiencing a huge amount of this demand,” Koziner said, adding that data center demand outpaces supplier expectations, with data center developers willing to pay high costs for their power needs.  

“The question is: How much new capacity do you need to install to keep up versus how much you can unlock from existing infrastructure? And I think it’s a combination of both,” he said. “There are efficiencies that we can unlock, but there’s certainly a need for a lot more capacity to keep up.” 

In a recent report, Wood Mackenzie said it is tracking 134 GW of proposed data center demand across the country, with new data center proposals concentrated in Texas, Virginia, Pennsylvania and other states in the middle of the country.  

The research and consulting firm says constrained gas supply chains and rapidly rising costs of combined cycle gas plants will pose a significant barrier to scaling up power production over the next few years, with high costs likely exacerbated by the effects of the Trump tariffs. 

Meanwhile, the renewable energy industry is facing major headwinds associated with the One Big Beautiful Bill Act and Trump’s executive orders. Renewables could face significant cuts and project cancellations across the country despite rising demand and power costs. (See U.S. Clean Energy Sector Faces Cuts and Limitations.) 

While coastal states with higher energy costs have seen lower data center demand growth, these areas are unlikely to be immune to the effects of AI. Kim Harriman, deputy CEO at Avangrid, which owns electric utilities in Connecticut, Maine and New York, told RTO Insider that AI demand growth “is here, and we see it.” 

She noted that, over the long term, electrification of heating and transportation, the reshoring of manufacturing and housing development also likely will be significant drivers of demand in the region.  

Fossil Fuel Infrastructure

Representatives of the natural gas industry argued that rising power demand will require new gas infrastructure throughout the country, while Trump administration officials said it is essential to retain the nation’s coal fleet. (See Trump Officials Talk Regulatory Rollbacks at NARUC Meeting.) 

“The existing system alone is not going to be enough to meet this demand. We’re going to have to build out more infrastructure,” said Amy Andryszak, CEO of the Interstate Natural Gas Association of America. 

Mary Landrieu, co-chair of Natural Allies and a former Democratic senator from Louisiana, made the case for new gas pipelines while urging attendees to “drop our political ideologies.” 

Natural Allies is a group backed by gas pipeline companies, focused on promoting “the great asset of natural gas” to “Democrats primarily,” Landrieu said.  

Landrieu praised recent statements from Connecticut Gov. Ned Lamont (D) indicating he is open to new gas infrastructure, and she repeatedly emphasized the importance of an “all-of-the-above approach” to energy policy. 

Andryszak said opposition from “certain states” has been an impediment to building out gas infrastructure, and added she hopes “conversations around demand for more energy of all forms” will cause states that have opposed gas infrastructure to “rethink some of their policies.” 

Efforts to expand gas pipeline capacity into the Northeast have faced strong opposition from climate activists and Democratic politicians in recent years, while proponents of natural gas hope regulatory rollbacks and increased federal support for pipelines will help facilitate projects in the Northeast.  

In Massachusetts, where much of New England’s gas demand is concentrated, Gov. Maura Healey (D) has been relatively quiet on the issue of gas expansion but has not shut down the possibility of new gas infrastructure. 

Natural gas combustion and methane leaks from gas networks are key drivers of climate change. Leaked methane has a strong short-term warming effect on the climate, and scientists warn that an expanded reliance on natural gas is not compatible with efforts to decarbonize the economy and stabilize the climate. 

Even in the absence of regulatory hurdles, proposals to build new natural gas pipelines into New England face questions about funding, and industry experts have expressed skepticism about the likelihood of new gas infrastructure in the region due to a lack of counterparties to pay for the infrastructure. (See New Pipelines Unlikely for New England, Experts Say.) 

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FERC Approves NPCC’s $102K Penalty Against ORU

Consolidated Edison subsidiary Orange and Rockland Utilities (ORU) will pay $102,000 to the Northeast Power Coordinating Council for violations of NERC reliability standards as the result of a settlement approved by FERC. 

NERC submitted the settlement to FERC on June 30 in its monthly spreadsheet Notice of Penalty; it was the only settlement for the month. The commission said in a July 30 filing that it would not further review the settlement, leaving the penalty intact (NP25-12).  

ORU, with its subsidiary Rockland Electric, serves about 300,000 electric customers in New York and New Jersey. Two of the three violations in the settlement involved both companies and covered a period of almost 17 years, from 2007 to 2024. They all stemmed from NERC’s FAC family of facility ratings standards. 

The utility reported to NPCC on Oct. 9, 2020, that it had discovered potential violations of FAC-008-1 (Facility ratings methodology) and FAC-008-3 (Facility ratings), along with FAC-014-2 (Establish and communicate system operating limits). Because ORU and Rockland are in coordinated oversight with each other, the first two issues applied to both companies. 

For the FAC-008-1 violation, ORU said that its facility ratings methodology (FRM) “failed to include consideration for operating limitations, such as a topology change.” ORU conducted an extent-of-condition assessment and found no additional issues; however, when NPCC and ReliabilityFirst later completed a joint self-certification review in March 2023, they found that ORU and Rockland had failed to include several topics in the FRM, including: 

    • using a wind speed assumption that does not match ORU’s existing FRM; 
    • a mismatch of ambient temperatures used to establish normal, long-term emergency and short-term emergency ratings of copper tubular bus sections; 
    • insufficient summer and winter ambient temperature information; and 
    • a mismatch of substation configuration data. 

Regarding the infringement of FAC-008-3, ORU and Rockland determined from an internal compliance review that 17 facilities had ratings that were inconsistent with the FRM: four 345/138-kV transformers and 13 138-kV transmission lines. The changes resulted in derates of up to 40%, though 75% of the derates were less than 13%, and increased ratings of up to 17%. As for the FAC-014-2 violation, ORU reported that the system operating limits of 14 facilities had been incorrectly calculated during 64 breaker outages. 

All of the violations posed a moderate risk, according to NPCC, and no harm is known to have occurred. To mitigate the infringements, ORU and Rockland have updated their main FRM document with language addressing the use of operating limits when calculating facility ratings, provided training to responsible staff on FAC-008 compliance and created a new spreadsheet to organize ratings data.  

The utilities also revised all applicable facility ratings, implemented a new process checklist to be completed prior to energizing grid additions and modifications, and created a requirement for annual validation of all changes to or affecting facilities within the previous 12 months. 

Because ORU and Rockland are in RF’s footprint as well as NPCC’s, the REs will split the penalty payment based on relative net energy for load, with RF receiving $59,177. 

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Trump Officials Talk Regulatory Rollbacks at NARUC Meeting

BOSTON — The Trump administration’s proposed rescission of EPA’s 2009 endangerment finding classifying greenhouse gases as pollutants would be the “largest deregulatory action in the history of the country,” EPA Administrator Lee Zeldin said July 30.

Speaking at the Summer Policy Summit of the National Association of Regulatory Utility Commissioners, Zeldin touted the Trump administration’s “energy dominance agenda” and said deregulating the fossil fuel industry will help the U.S. compete with China and serve growing demand from artificial intelligence.

EPA’s endangerment finding is the legal basis of a range of federal regulations targeting climate-warming emissions, and its elimination could have major effects on emission-reduction efforts throughout the country. The agency issued the endangerment finding under the Obama administration after the Supreme Court ruled in 2007 that it has the authority under the Clean Air Act to regulate GHGs. (See related story, EPA Proposes Rescission of Endangerment Finding that Underpins All GHG Rules.)

Zeldin said the Obama administration took a “creative approach” when issuing the endangerment finding and said the finding has been undercut by recent Supreme Court cases, including the elimination of the Chevron doctrine, which gave deference to agencies in their interpretations of laws.

“We’re living in a bit of a different world in 2025 than 2009 because of all the Supreme Court cases,” Zeldin said. “The Supreme Court has made it pretty clear that agencies like the EPA shouldn’t just be filling in any vague language in the statute.”

Deregulating the oil, gas and coal industries will be essential “if you want to make America the AI capital world [and] if you want to unleash energy dominance,” Zeldin said.

He argued that regulatory rollbacks will help the country’s economy and national security, and added that “if you care about our environment, it improves our environment, because in the United States, we tap into our energy supply so much better than so many other countries do.”

In June, the administration proposed to repeal GHG emissions standards for new power plants and Biden-era updates to the Mercury and Air Toxic Standards. (See EPA Proposes Repealing Limits on Power Plant Greenhouse Gas Emissions.)

“We will actually have more deregulation in one year at EPA than the entire federal governments, across all agencies, across entire presidencies, primarily because of the stuff that was done in 2023 and 2024,” Zeldin added.

The Trump administration’s actions to deregulate the fossil fuel industry have drawn strong criticism from climate scientists and activists. Emissions from fossil fuel combustion are one of the core drivers of human-caused climate change.

Other Trump administration officials speaking at the NARUC event also emphasized the importance of bringing new generation and transmission infrastructure online to meet AI demand.

Peter Lake, senior director of power at the National Energy Dominance Council, said the U.S. is facing “an inflection point in the history of industrial technologies,” adding that “we’ve all heard about the amazing things that AI can do — the incredible benefits to health care; technology; communication; picking wine at dinner; … optimizing shopping for my girlfriend.”

Nick Elliot, director of the Grid Deployment Office at the Department of Energy, said the U.S. needs to rapidly scale up the development of gas resources to balance the system as load grows, adding that supply chain backlogs must be addressed to achieve this buildout.

He said DOE’s recent changes to National Environmental Policy Act procedures should help reduce development timelines throughout the U.S.

“We are looking specifically to try and streamline regulation as much as we can, to give developers as much visibility on timelines and process to get things online,” Elliot said.

Deputy Energy Secretary James Danly said market reforms are needed to incentivize new resources to come online at the necessary rate to meet anticipated demand. He noted that the PJM capacity auction clearing at the price cap earlier in the month indicates prices “probably should have been higher” and criticized “subsidy regimes that warp the price signals” and hurt development. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)

He expressed optimism about the changes to federal tax credits made by the One Big Beautiful Bill Act, calling the bill “an important part of getting energy policy correct.” (See U.S. Clean Energy Sector Faces Cuts and Limitations.)

The Trump administration believes “very much in the free market,” Danly said. He added that “capitalism is the engine by which America achieves great things, and this is the way we’re going to meet the needs that industries have for electricity, for gas [and] for energy of all types.”

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Colo. PUC Approves PSCo’s Markets+ Participation

The Colorado Public Utilities Commission voted July 30 to allow Public Service Company of Colorado to join SPP’s Markets+ day-ahead market, with commissioners split on whether the move is a step toward or away from full RTO participation. 

Commission Chair Eric Blank and Commissioner Tom Plant voted in favor of PSCo’s participation in Markets+; Commissioner Megan Gilman was opposed. The decision is the latest step in the development of the West’s two competing day-ahead markets: Markets+ and CAISO’s Extended Day-Ahead Market (EDAM). 

And the vote might not be the final word on the matter: At least one group — Advanced Energy United — said it plans to ask the commission to reconsider its decision. 

The vote follows a commission debate July 23 on the Markets+ issue. Blank made the case for allowing PSCo to join Markets+, while the other two commissioners voiced concerns. (See Colorado Commissioners Spar Over PSCo’s Markets+ Choice.) 

During the July 30 hearing, Blank argued that joining Markets+ is a step on a “continuum” moving toward full RTO participation. 

“Whether we get to a full RTO or not, as additional market services become available along the continuum, the benefits of the market increase more toward the higher end, potentially into the hundreds of millions of dollars per year of savings,” Blank said. 

He sees benefits arising mainly from better integration of Colorado’s two balancing authorities, through steps such as optimizing dispatch and unit commitment between them. PSCo operates one of the state’s balancing authorities and the Western Area Power Administration (WAPA) runs the other. WAPA’s Rocky Mountain Region plans to join SPP’s RTO West. (See WAPA, Basin Electric Commit to SPP’s RTO West.) 

Blank previously pointed to benefits related to resource adequacy, greenhouse gas accounting and wholesale market price transparency. 

Gilman said she expects PSCo to request a waiver allowing it to sidestep a state requirement to join an RTO by Jan. 1, 2030. And with the costs of joining Markets+ projected to exceed financial benefits until after 2030, Gilman said the company will be able to use those figures as an argument against joining an RTO. 

“Instead of appearing like a rational continuum or plan to progress, this appears to in some ways work against the goal of moving to a full RTO,” she said. 

Plant said after reviewing the issue for the past week, he agreed with Blank that a day-ahead market offers benefits as an interim step toward RTO participation. He highlighted the “transparency benefits of wholesale pricing, consistency of a market structure, [and] the benefits of efficiency of joining the two BAs.” 

PSCo Pleased

PSCo, an Xcel Energy subsidiary, filed its request to join Markets+ in February. (See PSCo Seeks to Join SPP’s Markets+.) 

The commission on July 30 also approved the company’s request to recover Markets+ associated costs through the electric commodity adjustment tariff. 

Xcel Energy spokesperson Michelle Aguayo said the company was pleased with the decision. 

“This milestone follows years of working with [SPP], other utilities throughout the West and interested stakeholders to build a market that provides for the efficient dispatch and commitment of our resources, helping integrate larger amounts of renewable energy to our fleet, and improve efficiency and reliability while reducing customer costs,” Aguayo said in an email to RTO Insider. 

The company plans to execute agreements to help fund and implement Markets+ “shortly” and join the market in 2027. SPP has set a deadline of Sept. 1, 2025, for balancing authorities to join Markets+ in time to participate when it goes live Oct. 1, 2027. 

Hurdles Ahead?

Others were disappointed by the commission’s vote. 

“Joining a smaller, more balkanized market undermines the very affordability and reliability of clean energy resources that the region depends on, and rushing into this decision, Colorado risks hitching its wagon to the wrong horse,” Brian Turner, regulatory director at Advanced Energy United (AEU), said in a statement.  

Other Markets+ trading partners are far from Xcel’s neighbors, Turner said, and instead of delivering benefits, the participation will just create more seams. 

Turner said PSCo’s proposal was approved without the required legal analysis. AEU plans to file an application for reconsideration within 20 days of a final decision being issued.  

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FERC Affirms Use of RTO Adder for CAISO Tx Developer

FERC has affirmed the ability of an independent transmission developer to include an RTO adder in its CAISO formula rate, rebuffing a request by the California Public Utilities Commission to reject the company’s use of the incentive.

But the federal regulator still declined to sign off on the increased rate proposed by NextEra Energy subsidiary Horizon West, instead referring the issue to settlement judge procedures to determine the reasonableness of the company’s return on equity (ROE) calculation.

“Based on our preliminary analysis, we find that Horizon West’s proposed rates may yield substantially excessive revenues, and thus suspend them for five months,” the commission wrote in its July 29 order (ER25-2395).

CAISO in 2024 selected Horizon West to build, own and operate two competitively bid 500-kV transmission projects included in the ISO’s 2022/23 planning process: the Imperial Valley-North of SONGS line and the Ironwood (formerly North Gila-Imperial Valley #2) line, intended to help California tap low-cost renewable resources in the Desert Southwest.

In its filing with FERC, Horizon West requested authorization to increase the base ROE in its formula rate from 9.7% to 11.98%, resulting in a total ROE of 12.48%, including a previously approved 50-basis point RTO participation adder, arguing the rate fell within a “composite zone of reasonableness” ranging between 8.81% and 13.56%.

The company also sought permission to update its formula rate template with a prior period adjustment to its true-up mechanism and authorization to replicate its transmission owner tariff — including the formula rate — for any affiliates or subsidiaries it creates in the future to develop CAISO transmission projects.

To support its case for the ROE increase, Horizon cited the expert testimony of Adrien McKenzie, a chartered financial analyst, who contended the proposed ROE would ensure the company could fund its 500-kV projects in light of increasing long-term capital costs stemming from increased interest rates.

“Horizon West asserts that its ROE must be reflective of the upward shift in investor risk perception and required rates of return for long-term capital to maintain Horizon West’s financial integrity and ability to attract capital,” FERC noted in its order.

McKenzie’s testimony also pointed to the growing investment risk for projects located in California, largely because of the state’s “inverse condemnation” law, which holds utilities strictly liable for costs and damages stemming from wildfires sparked by their equipment.

Protests

Horizon’s request prompted a flurry of protests.

The California Department of Water Resources (CDWR) and Northern California Power Agency (NCPA) contended the proposed ROE is excessive compared with other California utilities, saying no transmission owner has been granted an ROE at that level in nearly 20 years.

Other protestors argued that McKenzie “improperly” placed Horizon’s ROE at the high end of the middle third of the range of reasonableness despite FERC precedent putting average-risk utilities in the middle of that range.

The CPUC and the Six Cities group of Southern California publicly owned utilities contested whether the proxy group of utilities McKenzie relied on to calculate Horizon’s ROE “is comparable in terms of risk, capital structure and regulatory framework,” according to the order.

The CPUC also argued Horizon’s claim that it faces increased wildfire risk “is unsubstantiated due to the fact that it owns new transmission assets spanning limited areas and benefits from longstanding wildfire mitigation efforts in California,” FERC noted.

The order pointed out that CDWR and NCPA also raised concerns “that it is ratepayers rather than shareholders that will bear wildfire-related financial risks through insurance and regulatory cost recovery mechanisms, and that it would be imprudent for ratepayers to compensate shareholders for such risk.”

In its ruling, FERC said its “preliminary analysis” indicated Horizon’s proposed rates “may yield substantially excessive revenues” and found the filing “raises issues of material fact that cannot be resolved based on the record before us and that are more appropriately addressed in the hearing and settlement judge procedures.”

The commission likewise found that Horizon’s proposed revisions to its formula rate template “raise issues of material fact that cannot be resolved based on the record before us” and should be addressed in the settlement judge procedures.

Regarding the company’s request to replicate the formula for future affiliates, the commission said: “We find that there is no reason to open a new proceeding to re-litigate the justness and reasonableness of a formula rate that is identical to the one being accepted in the instant filing.

“We clarify, however, that the Horizon West affiliates or subsidiaries will each be subject to the resultant ROE that is determined through the hearing and settlement judge procedures ordered above, or any subsequent ROE that is ordered by the commission.”

Participation in CAISO Voluntary

But the commission outright rejected the CPUC’s argument that Horizon West should be ineligible for an RTO adder because the company’s participation in CAISO is involuntary due to its contractual obligation to turn over operational control of its transmission facilities to the ISO under its approved project sponsor agreement.

“Horizon West was formed ‘to develop, construct, finance, own, operate and maintain electric transmission facilities in the CAISO region,’” the commission wrote. “Horizon West thus voluntarily chose to pursue transmission projects within CAISO. Turning over operational control of its transmission facilities to CAISO once constructed is part and parcel of that process.”

The commission noted it has “previously granted RTO adders to entities seeking to participate in Order No. 1000-compliant competitive solicitations conducted as part of RTO/ISO regional transmission planning processes — which necessarily entails turning over functional control of facilities to the RTO/ISO — and CPUC does not provide a convincing rationale for us to depart from this precedent.”

FERC pointed out that, unlike Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison, which have been denied use of the RTO adder because California law requires them to participate in CAISO, “Horizon West is not required by state statute to join” the ISO.

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Trump Administration Takes Another Swing at Wind Power

The Trump administration is erecting another set of hurdles to onshore and offshore wind energy development and operations. 

The Department of the Interior on July 29 announced a four-pronged review that continues the president’s efforts to restrict some types of renewable energy, a darling of the previous administration and a rival to the fossil fuel sectors that he has embraced so firmly. 

Interior Secretary Doug Burgum’s Order No. 3437 has a title — “Ending Preferential Treatment for Unreliable, Foreign Controlled Energy Sources in Department Decision-Making” — that touches on multiple themes the administration has emphasized. 

It breaks down into four measures: 

    • Ending the Biden administration’s policy support (or “preferential treatment”) for intermittent (aka “unreliable”) energy sources such as wind and solar, which, despite growth of a domestic supply chain in the Biden years, still rely heavily on components manufactured in other countries, some of them considered rivals to the United States. 
    • Restoring the congressional mandate to consider all uses of public land and water by considering withdrawal of land with high wind energy potential to be sure grazing, recreation and other uses have balanced access. Also, Interior will terminate offshore Wind Energy Area designations made in the Biden administration. 
    • Strengthen stakeholder engagement for offshore wind development, particularly from tribes, the fishing industry and coastal communities. Offshore wind would have a disproportionate impact on these three constituencies, the order states. (It does not mention that these three groups consistently are among the strongest opponents of offshore wind.) 
    • Conducting a careful review of avian mortality associated with development of wind energy projects in migratory flight paths to determine if such bird kills qualify as incidental takings under the Migratory Bird Treaty Act. Interior then will determine the best way to permit such development, identify violations of statutes and assess penalties. 

Trump ran on a platform of support for fossil fuel and opposition to solar and wind — especially offshore wind. 

He has delivered on his campaign message, starting with a Day One directive limiting the offshore wind sector. (See Critics Slam Trump’s Freeze on New OSW Leases.) The reconciliation bill he pushed through Congress and signed July 4 directs the rapid phaseout of tax credits for wind and solar. (See U.S. Clean Energy Sector Faces Cuts and Limitations.) 

Trump’s July 7 executive order ratcheted up the bill language, directing his cabinet agencies to carry out its provisions as quickly and firmly as possible. (See Trump Executive Order Targets Renewable Energy Tax Credits.) 

A July 15 directive within the Department of Interior imposes byzantine requirements on any and all substantive review of wind, solar and supporting infrastructure on federal land, with successive approval required by two high-level deputies and then Burgum himself. (See Interior Dept. Places Solar, Wind Under Close Review.) 

Meanwhile, Interior has moved to a crisis mode on favored technologies such oil, gas, coal and uranium, aiming to wrap environmental reviews in as few as 14 days. 

This has led renewable energy and environmental advocates to conclude that the Trump administration is not “leveling the playing field” for the energy sector, as Burgum says in his July 29 news release, but instead tilting it toward fossil fuels — exactly the opposite of what fossil fuel advocates say the Biden administration did. 

The Trump administration makes no secret of its intent to swing the pendulum back. Burgum’s order states: “The previous administration’s destructive and ideological policies not only severely impacted our nation’s supply of reliable energy infrastructure and dispatchable energy but also made our nation increasingly reliant on foreign-controlled energy equipment.” 

Offshore wind trade group Oceantic Network criticized the “unprecedented requirements” being placed on wind projects. 

“The Department of Interior’s latest directives continue a false narrative on an established American industry that will prevent an important source of baseload power generation from reaching the grid when ratepayers are already feeling the effects of rising electricity prices,” it said in a July 30 news release. “Crippling affordable and reliable wind energy makes no economic sense and undermines the administration’s ‘all-of-the-above’ energy strategy. We urge the department to adopt policies which put all sources of American energy on an even playing field.” 

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Ameren Argues Exclusive Rights to MISO Illinois Competitive Tx Projects

Ameren Illinois argued to FERC that it should have dibs on sections of two competitive long-range transmission projects worth almost $2 billion from MISO’s second portfolio, claiming that Illinois’ “first-in-the-field” doctrine is tantamount to a right-of-first-refusal law.  

The utility told FERC that MISO is wrong to open the Illinois portions of two long-range transmission projects (the Woodford County–Illinois/Indiana State Line 765-kV line and substation project and the Sub T–Iowa/Illinois State Line–Woodford County 765-kV line project) to competitive bidding (EL25-105).

Ameren said Illinois’ “first-in-the-field” doctrine essentially grants it a right of first refusal to build, own and operate segments of the projects located in its service territory. FERC should instruct MISO to re-classify the projects, reverse its request for proposals and assign responsibility for some of the two lines to Ameren, it said in its petition for a declaratory order.  

“Despite Illinois’ ‘first-in-the-field’ doctrine and Ameren Illinois’ rights thereunder, due to uncertainty regarding whether Illinois qualifies as a state granting a right of first refusal, MISO improperly included the projects in its competitive developer selection process,” Ameren explained to FERC.  

MISO began soliciting proposals from qualified developers for the $984.6 million Woodford County line July 25. Proposals are due Jan. 6. 

MISO plans to begin accepting proposals for evaluation on the $940.1 million Sub T-Iowa/Illinois State Line–Woodford County 765-kV project Aug. 8 with a Jan. 20 deadline. The two lines are part of MISO’s second, nearly $22 billion long-range transmission portfolio. 

The highlighted sections of the MISO long-range transmission projects that Ameren argues it should have rights to. | MISO and Ameren

Ameren characterized portions of the pair of projects as “Ameren Illinois segments” that “will interconnect with Ameren Illinois’ existing facilities and provide electric services to, and otherwise significantly affect, Ameren Illinois’ existing wholesale and retail customers.” The company said the projects will lower prices for its customers, reduce overloads, alleviate congestion, allow new generation to interconnect and expand export capability.  

Ameren acknowledged that judicial precedent enforces the doctrine and it’s not a codified statute.  

The doctrine states that, where “additional or extended service is required in the interest of the public and a utility in the field makes known its willingness and ability to furnish the required service,” there is no justification in “granting a certificate of convenience and necessity to a competing utility until the utility in the field has had an opportunity to demonstrate its ability to give the required service.” 

It also says parties must demonstrate that the established utility is providing poor service or is unable to “provide adequate facilities” before one utility is allowed to “take the business of another already in the field.”  

The doctrine reasons that the “method of regulating public utilities in Illinois is based upon the theory of regulated monopoly rather than competition.” 

Ameren said it “clearly” meets the three-part threshold of the doctrine: It’s an existing public utility, it’s willing to head up the projects, and there’s no reason it’s unable to do so. It said FERC didn’t need to interpret state law to grant its petition. 

Six states in MISO (Indiana, Michigan, Minnesota, Mississippi, North Dakota and South Dakota) have enacted explicit ROFR laws that are in effect. MISO does not include Illinois on its list of states with ROFR laws.  

Other Long-range Projects in Competitive Stages

In addition to the Illinois segments, MISO has a full dance card in 2025 for overseeing competitive projects included in the second long-range transmission portfolio.  

MISO announced July 30 that it selected Republic Transmission to lead construction of the Reid Extra High Voltage Indiana/Kentucky State Line 345-kV project. The project was the first up for bids from the collection. 

MISO has two more projects open for bidding: the Wisconsin Southeast 345-kV project and the Bell Center-Columbia-Sugar Creek-Illinois/Wisconsin State Line 765-kV project. The grid operator is staggering its selection processes to make its competitive developer process more manageable.  

Through the end of the year, MISO plans to release two more requests for proposals for 765-kV projects from the portfolio: The Marshalltown-Lehigh-Sub T–Montezuma–East Adair project Nov. 25 and the East Adair–Minnesota/Iowa State Line–Arbor Hill–York Avenue project Dec. 11.