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December 6, 2025

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NEPOOL Members Offer Amendments on ISO-NE Capacity Reform Project

NEPOOL members have proposed several amendments to the first phase of ISO-NE’s capacity market overhaul prior to the scheduled Markets Committee vote on the RTO’s proposal in November.

The amendments presented to the committee Oct. 16 include proposals to allow generators to submit capacity offers reflecting physical limitations during hot weather; adjust the methodology for calculating the capacity offer price threshold (COPT); and extend the length of time resources can hold onto interconnection rights while undergoing major repairs.

The first phase of ISO-NE’s Capacity Auction Reform (CAR) project is centered around shifting the Forward Capacity Market to a prompt design and updating the resource retirement process. The second phase is focused on accreditation changes and instituting a seasonal market. Both phases are intended to take effect in the 2028/29 capacity commitment period. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)

Ambient Air De-list Bids

Bruce Anderson of the New England Power Generators Association (NEPGA) argued that ISO-NE should extend existing rules and practices allowing generators to submit capacity offers reflecting reduced generating capabilities at temperatures above 90 degrees Fahrenheit.

The RTO’s current proposal requires all qualified resources to offer all available capacity in annual auctions and would not maintain the option for generators to de-list capacity during periods of high temperatures.

“Without carrying forward the exemption, a resource will unnecessarily be required to submit a cost workbook for megawatts it is physically unable to produce at those high ambient temperatures,” Anderson told the committee.

To address the issue, NEPGA has proposed adding language allowing participants to “identify and submit a price-quantity pair(s) in a capacity offer specifically attributable to and up to the megawatt amount that the lead market participant expects will not be physically available due to ambient temperature effects.”

Several members of the generation sector expressed support for the amendment, while some stakeholders said it ultimately will be important to address temperature effects in the accreditation phase of the CAR project.

Chris Geissler, director of economic analysis at ISO-NE, said the RTO does not yet have a firm position on the amendment and still is considering the proposal. He added that ISO-NE’s existing proposal to not carry forward ambient air exemptions was motivated by a desire for more consistency across different segments of capacity.

Capacity Offer Price Threshold

Ben Griffiths of LS Power proposed a transitional methodology for calculating the COPT for the 2028/29 commitment period that he said would help address issues related to outdated price inputs.

The price threshold is intended to protect against market power; participants offering above the threshold price are required to submit a cost workbook to the Internal Market Monitor.

ISO-NE plans to maintain its methodology for calculating the threshold as it transitions to a prompt auction. Under the existing methodology, the 2028/29 threshold would be based in part on the prices from the last Forward Capacity Auction, which will have been held about four years prior to the first prompt auction.

Griffiths said he’s concerned this will lead to an outdated threshold value, especially after capacity shortfall events over the past two summers caused some generators to accrue costly performance penalties, which has caused some participants to speculate that capacity costs will increase in the future to account for these risks.

He proposed that ISO-NE set the threshold for the 2028/2029 commitment period at “at a fixed price of $4.984/kWm,” which “represents the simple average of observed clearing prices in the summer 2025 ARAs [annual reconfiguration auctions] and theoretical common value component estimates derived from the same auctions.”

The common value component equals “the expected value of scarcity revenues under [Pay-for-Performance],” Griffiths noted in a memo published prior to the meeting.

He said the close alignment of the ARA and common value component prices “supports a strong case for using this value.”

Responding to the proposal, Geissler said the RTO’s current proposal is to extend the existing methodology for the threshold. However, he said ISO-NE is amenable to considering transitional changes to address a time lag in the data, especially if there is broad stakeholder support.

Geissler said ISO-NE plans to consider changes to the threshold during the accreditation phase of CAR. However, if the RTO cannot finish the accreditation phase in time for the 2028/29 commitment period, and it identifies issues related to stale data used in the COPT, the RTO would look to address the issue prior to the auction, he said.

Also at the meeting, Andy Gillespie of Calpine reiterated his proposal for ISO-NE to base the threshold strictly on the common value component. He acknowledged that this could lead to a threshold value significantly higher than the clearing price of past FCAs but stressed that the threshold should be a forward-looking metric.

“This method is based on ISO-based, forward-looking, objective data” and is “often cited by ISO as the basis for calculating PFP opportunity cost,” Gillespie said, adding that the methodology could “be used regardless of auction format or accreditation methodology.”

Geissler said ISO-NE is not supportive of a broader change to the COPT methodology, which it considers to be outside the scope of work for the first phase of the CAR project.

3-year Rule

Griffiths also advocated for a change to ISO-NE rules that automatically deactivate resources that do not run for three straight calendar years. He expressed concern that recently proposed changes to the RTO’s repowering rules could cause resources facing extended repairs to lose their interconnection service.

Three- to seven-year wait times for turbines and transformers “make compliance with the strict three-year clock unrealistic for facilities facing catastrophic outages,” Griffiths said.

While resources could seek a waiver from FERC to ISO-NE’s three-year rule, “FERC’s waiver process is uncertain and ill-suited to this situation,” he argued.

Griffiths proposed introducing “a bounded extension” of up to six years for resources making “good-faith restoration efforts.”

To be eligible for such an extension, resources should have to demonstrate “due diligence, including at-risk expenditures, in pursuit of permitting, licensing and construction necessary to restore the resource to commercial operation,” he proposed.

Several stakeholders said they are open to the change but would want to ensure there is language to prevent resources from using the extension simply to hold onto interconnection rights and prevent other resources from entering the market.

ISO-NE agreed the issue warrants additional discussion but said it should be done outside of the CAR process.

Griffiths also offered an amendment to clarify ISO-NE’s authority over the interconnection rights of state-jurisdictional resources that have been inactive for more than three years. He advocated for new tariff language “to protect jurisdictional integrity” and to “enable equal treatment for state resources under the proposed deactivation language.” ISO-NE, however, said that is outside the scope of the CAR project.

Accreditation Updates

Also at the meeting, ISO-NE outlined its plans to calculate seasonal forced outage rates in the new accreditation framework.

Equivalent forced outage rate on demand (EFORd) is intended to quantify resources’ likelihood of having an outage when called upon and is a key input into resources’ overall accreditation value, noted Steven Otto, manager of economic analysis at ISO-NE.

The RTO plans to calculate EFORd values based on data from the previous five years. For resources that lack enough data, it plans to use class averages from the New England generation fleet to fill in any gaps, Otto said.

“Conceptually, the mechanics of seasonal EFORd calculations will be identical to the existing mechanics for annual EFORd calculations, except that the calculation will be done for a given season with historical data only from that season,” Otto said.

He added that “for most resources, the differences between their annual and estimated seasonal EFORd values are small.”

Maximum Capability

ISO-NE also discussed its methodology for calculating resources’ maximum capability, which “represents a resource’s physical supply capability and reflects changes in a resource’s capability due to changes in its physical attributes.”

To generate accreditation values for each resource, ISO-NE plans to multiply resources’ maximum capability by their marginal reliability impact ratio, which compares the reliability benefits of the resource to a hypothetical “perfect” capacity resource.

Maximum capability would be calculated seasonally in the summer and winter. In the summer, it would equal each resource’s maximum recorded hourly net output from the past three years when temperatures are over 80 F. Winter maximum capability values would be based on maximum hourly output when temperatures are below 32 F.

ISO-NE also plans to allow resources to schedule an audit to determine their maximum output.

For active demand resources, the maximum capability will be based on maximum hourly performance in the winter and summer from the previous three years. The temperature constraints would not apply to these resources, as they do not self-schedule, and are not guaranteed to run at their full capacity at a certain temperature in any given season, ISO-NE said.

The maximum capability for energy efficiency resources would be based on performance estimates from ISO-NE’s efficiency database.

ISO-NE said the three-year lookback period for maximum capability values should give resources that run infrequently enough time to demonstrate their full performance capabilities while also capturing recent performance trends.

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FERC Orders MISO to Describe Merchant HVDC Planning Considerations

FERC has ruled that MISO must name a point in development and describe how it will consider merchant HVDC lines in its transmission planning; however, the commission declined to order a more complete incorporation of the Grain Belt Express HVDC line in MISO’s recent transmission planning.

The directive to MISO was the sole issue FERC granted from Invenergy Transmission’s 2023 complaint, which sought to force MISO to consider the Grain Belt Express in its transmission planning (EL22-83).

FERC said Invenergy successfully argued that MISO’s tariff is unfair “insofar as it does not address when and how [merchant] HVDC transmission projects are incorporated into MISO’s transmission planning models.” The commission told MISO to decide on a juncture and explain how it would account for merchant HVDC lines in transmission planning and add it to the planning protocol section of its tariff within 90 days.

Elsewhere in its Oct. 16 order, FERC decided that Invenergy did not meet its burden to prove that MISO fumbled on its planning practices regarding the proposed 800-mile, 5,000-MW line.

Invenergy argued that MISO has an obligation to incorporate “advanced-stage” merchant transmission facilities in its base case analysis performed under the annual MISO Transmission Expansion Plan (MTEP) and in long-range transmission planning.

The company claimed MISO is forcing ratepayers to foot the bill on regionally planned transmission projects that could be redundant alongside planned merchant HVDC projects. Invenergy said MISO should not be able to ignore merchant transmission in its MTEP and long-range transmission planning exercises when MISO’s tariff prescribes that MISO should assess a “quantifiable benefit” of an “enhancement to the MISO transmission system.”

Invenergy had asked FERC to order MISO to edit its tariff so that it incorporates all advanced-stage merchant transmission projects in its annual and long-term transmission planning. It also asked FERC to direct MISO to perform an after-the-fact sensitivity analysis for MISO’s two long-range transmission portfolios that considers Grain Belt.

MISO said it performed such a sensitivity analysis for the second long-range portfolio and found no reason to change any of its project recommendations. FERC accepted MISO’s analysis and declined to mandate more studies.

Invenergy said MISO’s second long-range portfolio contains a 765-kV line in Missouri that duplicates some of Grain Belt’s capabilities. It said MISO planned the line over 2024 even though Invenergy had a transmission connection agreement with MISO. Invenergy also said MISO’s first long-range transmission portfolio from 2022 included three projects at a combined $1.46 billion in northern Missouri that would return just 40 cents for every dollar spent on them once Grain Belt is transporting power.

Invenergy argued that MISO’s interpretation of its tariff “leads to an absurd result and unjust and unreasonable rates” and that MISO’s decision not to account for Grain Belt betrays optimized transmission planning.

FERC said Invenergy did not demonstrate that MISO’s evaluation of the trio of projects was incompatible with its tariff requirements. The commission also noted that MISO assesses the benefit-to-cost ratio on a portfolio basis and doesn’t produce ratios for individual projects. FERC also pointed out MISO does not assess a line’s ability to cancel out lower voltage upgrades of 230 kV or below, per its long-range transmission planning procedures.

Commissioner Lindsay See, while concurring with the order, put MISO on notice that additional analyses are a smart move to prove the worth of several billion-dollar transmission portfolios.

“When billions of dollars in infrastructure projects are at stake, more confidence in the accuracy of MISO’s planning and cost-benefit assumptions is not too big an ask. Judiciously using sensitivity analyses to help ratepayers get the most value for their money may be one tool well worth its weight,” See wrote.

See said it’s unclear whether MISO “is providing stakeholders and the MISO Board with the best information possible to assess true grid needs” when it unveils a long-term transmission portfolio. She cited the pending North Dakota-led complaint questioning the value of MISO’s $22 billion, mostly 765-kV second long-range transmission portfolio. (See MISO States Split on FERC Complaint to Unwind $22B Long-range Tx Plan.)

Invenergy representatives have said for years in MISO public meetings that the RTO’s transmission planning modeling is deficient because it didn’t factor in Grain Belt Express operations. (See “The Grain Belt Express Question,” Members Call for More Tx Expansion Following MISO’s $20B LRTP Blueprint.)

MISO did not include impacts from the Grain Belt Express merchant HVDC line in any of its 30-plus annual models under its 2024 Transmission Expansion Plan. MISO said Grain Belt Express did not sign its transmission construction agreement until about three weeks after the Feb. 1 cutoff date for members to submit projects for inclusion in MTEP 24 planning models. (See FERC OKs Grain Belt Express Connection Agreement with MISO; Invenergy Displeased with 2030 Target.)

MISO said it would include only approved segments of Grain Belt in its MTEP 25 planning modeling. Some MISO stakeholders have said Grain Belt Express stands to deposit substantial wind energy from Kansas into MISO.

Earlier in 2025, the U.S. Department of Energy Loan Programs Office revoked a $4.9 billion conditional loan commitment for Grain Belt. (See DOE Pulls $4.9B in Funding for Grain Belt Express.) Invenergy has vowed nevertheless to move ahead with the project.

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Stakeholders Ask MISO to Pause ’25 Queue to Get a Handle on 4-Year Backlog

Stakeholders asked MISO to consider putting a hold on processing generation project proposals entering the interconnection queue in 2025 to focus on the bottlenecks formed from the 2021 and 2022 queue classes.

At an Oct. 16 Interconnection Process Working Group meeting, multiple stakeholders told MISO it may be prudent to wait to kick off studies on the 2025 queue cycle until it’s further along with the study of projects that entered three and four years ago.

New Leaf Energy’s Adam Stern said MISO has done a lot recently in terms of interconnection queue rule changes and wondered whether MISO can juggle all four queue cycles, its new automated study process and its more stringent requirements for developers.

“I think what we’ve heard recently is that the older clusters are still moving slowly because of their size and they’re subject to old rules,” Stern said.

He said MISO might consider pausing to pay “more attention to the older clusters” and clear out the backlog before turning attention to the 2025 entrants.

As of September, MISO’s interconnection queue contained 1,127 projects at 215 GW, down from more than 300 GW earlier in 2025. MISO leadership said to expect more withdrawals in the coming months due to the federal phaseout of renewable energy tax incentives. (See MISO Interconnection Queue Drops to 215 GW on Tax Incentive Phaseout.)

MISO’s 2023 cycle is down to 102 GW from the 123 GW of projects that entered. The whopping 171 GW of projects that entered in 2022 is down to just 75 GW, while the 77-GW 2021 cycle has been reduced to 38 GW. The grid operator skipped acceptance of a 2024 cycle while it tried to get a handle on study delays and design a megawatt-capped queue that could sort out projects over one year instead of three to four years.

MISO closed its application window Oct. 7 for the 2025 cycle and has begun reviewing the project applications for completeness. The cluster of projects will raise queue totals.

MISO staff at the meeting said the RTO’s prerogative is to work as quickly as possible to process the cycles simultaneously. However, Aneta Godbole of MISO’s resource utilization team asked if stakeholders wanted a future discussion on MISO possibly filing a FERC waiver to hit pause on the 2025 cycle.

Savion’s Abhishek Dinakar seconded the request for MISO to clear the backlog and finish the 2021 and 2022 queue cycles before focusing on the 2023 and 2025 cycles.

“It’s kind of an unworkable amount of uncertainty” in the analyses,” EDF Renewables’ Anton Ptak said of the RTO simultaneously trying to complete studies on four queue cycles, when cycles contain projects that are contingent on higher-queued projects’ grid upgrades.

Ptak said MISO should put as much effort as possible into finishing the legacy queue cycles.

“That’s critically important,” he said.

Clean Grid Alliance’s David Sapper said it makes sense to clear the older cycles. But he said he worried the “vibe” he’s getting from MISO is that it sees the 2021 and 2022 queue cycles as so complex and problematic that the RTO ultimately would conclude the answer is opening another queue express lane.

“I worry that it’s just setting up us for more” generation projects in the expedited queue lane, Sapper said.

MISO’s Kyle Trotter said MISO has no plans to continue the queue fast lane once it hits its 68-project limit.

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Nonprofits Warn of Potential TVA Privatization Ahead of Board Hearings

Environmental and social justice organizations have expressed concerns the Tennessee Valley Authority (TVA) could be headed toward privatization with a slate of board candidates assembled by the Trump administration.

The  nonprofit group Appalachian Voices is urging senators to question the four TVA board nominees’ intentions as to the sale of TVA’s publicly owned assets to private companies. The Senate Environment and Public Works Committee has a hearing Oct. 22 to consider board nominees. The nonprofit said it is concerned the potential new board composition could “sell TVA to the highest bidder.”

The Senate committee is due to consider:

    • Mitch Graves of Memphis, Tenn., a health care CEO who has served as a board member for Memphis Light, Gas & Water and maintains investments in multiple energy companies.
    • Jeff Hagood of Knoxville, Tenn., an attorney who has experience in criminal defense, injury litigation and representing university sports coaches and student athletes.
    • Randy Jones; Guntersville, Ala., an insurance executive who also serves on the Guntersville Electric Board.
    • Arthur Graham of Jacksonville, Fla., a member of the Florida Public Service Commission through Jan. 1, 2026, and a former city council member. If installed on the board, Graham would be the first TVA board member to live outside of states that contain TVA service territory.

Trump’s fifth nominee to the TVA board, businessman Lee Beaman of Nashville, Tenn., is not included on the agenda for the upcoming hearing and is expected to be considered later. Beaman is the former owner of a network of Nashville-area car dealerships and is a prominent Republican fundraiser.

For months, the nine-seat TVA Board of Directors has lacked a quorum. It contains just three members: Chair Bill Renick, Bobby Klein and Wade White. TVA requires five board members to establish a quorum and make decisions.

The Trump administration fired Biden-era appointees Michelle Moore, Joe Ritch and Beth Geer in the span from late April to mid-June.

The Trump administration previously proposed selling off parts of the TVA. During Trump’s first term, his team twice floated the idea to privatize some of TVA’s assets in budget requests for fiscals 2019 and 2020. At the time, the White House Office of Management and Budget reasoned that the private sector is better positioned to own transmission assets and that government ownership causes “sub-optimal investment decisions” and “unnecessary risk to taxpayers.”

Congress rejected both attempts.

So far in his second term, Trump hasn’t proposed the sale of TVA assets in a formal budget proposal. However, Appalachian Voices said it suspects the administration will pursue sales directly through the TVA board and CEO.

Appalachian Voices, along with Energy Alabama, the Sierra Club, Third Act Tennessee, Sunrise Nashville and multiple union organizations, hosted two virtual rallies Oct. 16 to urge the public to oppose TVA privatization.

In a press release, Appalachian Voices said it was apprehensive that the slate of candidates could sell off TVA’s assets. The group called the roster “largely unqualified” and said TVA needs “expertise on its board of directors, not pro-privatization auctioneers.”

“We urge senators to use this hearing and other conversations with the TVA board nominees to ensure they intend to keep TVA in the people’s hands, and to reject any nominees who don’t prioritize the interests of the people of the Tennessee Valley over billionaires and corporations,” Bri Knisley, director of public power campaigns at Appalachian Voices, said in a statement.

The Revolving Door Project, an executive branch appointee watchdog, said the Trump administration seeks to “stack the TVA governing board with a slate of nominees seemingly poised to do the bidding of his billionaire allies and corporate donors alike.” The group added that the Trump has “reinvigorated concerns over TVA’s privatization.”

TVA didn’t outright answer RTO Insider’s request for comment on possible privatization. Instead, the federally owned utility provided a fact sheet noting that it has fully self-financed through revenue from its electric sales since 1999 and does not contribute to taxpayer expenses.

“In fact, every year, TVA is a source of cash to the federal government, paying annual dividend-like return payments on the original investment in the power system,” TVA said. “The TVA model also results in savings every year for taxpayers across the country. TVA provides services that would otherwise be the responsibility of other federal agencies, such as river system management, flood control, navigation, land management and other related regional, multistate functions — without taking any annual appropriated funding.”

TVA said its management of reservoirs and recreation areas “serve as a driver for nearly $12 billion in total economic activity and more than 130,500 jobs.” It also said it “prevents more than $300 million in flood loss each year.”

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NERC Preparing Workshop on FERC IBR Order

NERC is seeking comments on the agenda for a virtual workshop Nov. 5 in which the ERO will review its response to FERC Order 909, including a standards development project that aims to meet the commission’s directives by 2026.

The commission issued the order in July, approving new reliability standards establishing frequency and voltage ride-through requirements for inverter-based resources. (See FERC Approves IBR Ride-through Standards.) One of those standards, PRC-029-1 (Frequency and voltage ride-through requirements for IBRs), allows owners of legacy IBRs — resources already in operation when the standard goes into effect — 12 months after the effective date of the standard to request an exemption to its ride-through requirements.

Reacting to comments by industry stakeholders on its proposal to accept the standard (RM25-3), FERC directed NERC to clarify, within 12 months of the order’s effective date, what evidence it would accept to demonstrate hardware limitations for legacy IBRs. Also due in 12 months was a determination of whether any additional exemptions should be made for HVDC-connected IBRs with choppers — used in offshore wind projects to protect converters during grid faults — and other IBRs with long lead times “between adopting IBR specifications and placing the IBR in service.”

NERC’s workshop will outline the history of the project for industry stakeholders and solicit input on the issues entailed. Discussion panels are planned on documentation obligations for legacy IBRs and equipment limitations of IBRs with choppers that prevent them from complying with the ride-through standards of PRC-029-1.

In the final panel, participants will discuss how long-lead-time projects should be identified; whether they should be defined in the standard or left to industry to determine; potential equipment limitations from such projects; and solutions or workarounds that could address those limits. Attendees will also have the chance to provide feedback through live polling.

NERC staff have also suggested the workshop can help inform industry of relevant issues as stakeholders consider the standard authorization request (SAR) for Project 2025-05, which will handle the FERC directive. At the Oct. 15 meeting of NERC’s Standards Committee, Director of Standards Development Jamie Calderon suggested extending the comment period for the SAR — which begins Oct. 29 — from 30 days to 45 days in order to give industry more time to consider the discussion at the workshop. (See related story, NERC Standards Committee Passes Revised Proposals.)

In its announcement of the workshop Oct. 15, NERC invited stakeholders to provide input on the agenda. Topics of interest to the ERO include factual data on the exemption process, equipment limitations of IBRs with choppers and long-lead-time projects. Comments should be submitted by email to Alison Oswald, manager of standards development; Lauren Perotti, assistant general counsel; or Sarah Habriga, standards development analyst.

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Hawley Asks Ameren if Ratepayers are Covering Data Center Costs

U.S. Sen. Josh Hawley (R-Mo.) has requested that Ameren explain whether its residential ratepayers are picking up the tab for grid upgrades necessary to accommodate data centers and other large industrial customers.

Hawley sent a letter to Ameren CEO Martin Lyons on Oct. 15 expressing concern that residential customers are shouldering cost hikes and facing shutoffs while Ameren “pursues expensive corporate projects.”

“Ameren is seeking dramatic rate increases in order to supply massive data centers and industrial users. Recent reporting indicates that Ameren cut electricity to thousands of Missouri households in September while simultaneously pursuing lucrative arrangements with corporate users,” Hawley wrote, adding that ratepayers should not be “forced to subsidize corporate projects while struggling to keep their lights on.”

Hawley was apparently referring to a report by KSDK in St. Louis that Ameren cut off power to 14,999 customers in September and 14,375 in August for nonpayment, according to Missouri Public Service Commission data. Meanwhile, Ameren told the PSC in late August that about 15 GW worth of load is under construction or being studied for interconnection in its service territory. It noted that included “organic load growth from residential, commercial and industrial customers, as well as new manufacturing and data center loads.”

The senator claimed that “Ameren’s current request before the Missouri Public Service Commission would raise electric bills for residential customers by roughly 15% — a staggering increase for families already squeezed by inflation.” He asked if this was because of the “considerable” power demands from new data centers. He also asked whether Ameren has analyzed how industrial contracts impact residential rates and if it has implemented protections to ensure that the infrastructure costs for large industrial customers are not passed on to residential customers.

“Has Ameren considered prioritizing rate stability for households before approving discounted contracts for data center clients?” Hawley asked. He added that he expected answers by Oct. 29.

Ameren Missouri does not have an open rate case. The PSC did grant the utility a $355 million rate increase in April, less than the $446 million it requested in 2024. The new rates took effect in June, with the average residential customer experiencing an approximate 11% increase (about $17.45) per month.

And Ameren has applied with the PSC to introduce new rates for data centers and other large loads. Commission staff have said that the utility’s plan lacks protections that would prohibit passing along the costs of new, expensive power plants to ratepayers and could raise electric bills by an estimated $22 million annually (ET-2025-0184).

“Captive ratepayers should not pay unreasonably for those upgrades, nor should existing ratepayers be caught having to pay for any potential stranded or under-utilized resources built to serve anticipated large load customers,” Missouri PSC Director of Industry Analysis James A. Busch said in testimony. Busch added that total electricity infrastructure costs could “easily exceed” $1 billion for just one large load customer.

PSC staff in September recommended that regulators reject the proposal.

In an email to RTO Insider, Ameren said it “obviously” disagrees with staff’s position and said it would file testimony to address the analysis. The company said its plan “aims to reasonably ensure large electric load customers pay their fair share of service costs, protecting other customers from unjust or unreasonable charges, in alignment with Missouri Senate Bill 4.”

That bill, which went into effect in April, contains a provision that large load customers cannot unjustly or unreasonably raise the costs of service for the remainder of a utility’s customer base.

Ameren also disputed Hawley’s worry that it would subsidize data center demand through residential bills.

“Data centers are required by law to pay rates that the Missouri Public Service Commission has determined reasonably cover their fair share of energy costs to serve them. Ameren Missouri is not offering these businesses any discounts. The infrastructure costs to connect large data centers to the grid are not passed on to other customers,” Rob Dixon, senior director of economic, community and business development, said in a statement to RTO Insider.

In previous testimony, Ameren Missouri Senior Director of Regulatory Affairs Steven Wills said the utility’s proposed large load tariff framework is “designed such that these large load customers are reasonably expected to pay their fair share over a long enough term to justify investment in long-lived generating assets.”

Under the plan, prospective customers with demand of 100 MW or more would enter into long-term electric service agreements for at least 15 years and be billed for a minimum of 70% of the contracted capacity listed in the agreement.

Wills said the terms of the large load agreements “ensure a reasonable level of revenues over a sufficient term to reasonably assure that other customers will not bear any unjust or unreasonable costs associated with the acceleration of new generation that will need to occur to integrate the loads onto the system.”

Ameren did not address Hawley’s inquiry as to whether it has analyzed how industrial contracts impact residential rates.

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State-backed Actor Breaches Enterprise Software Product Security

Networking software and hardware developer F5 has suffered a major security breach by a nation-state threat actor that gained “long-term, persistent access” to information on the widely used BIG-IP product, the company said in an Oct. 15 statement.

BIG-IP is a family of hardware and software products that provide a range of services to enterprise customers, including cybersecurity, network load balancing and automation. F5 claims its products are used by 85% of the Fortune 500.

In its statement, F5 said the attackers gained access to company systems including the BIG-IP development environment and engineering knowledge management platform. The company admitted in a regulatory filing the same day that the intruders stole files containing portions of the BIG-IP source code and information about undisclosed vulnerabilities that F5 was working to address.

Also in the stolen files was “configuration or implementation information for a small percentage of customers.” F5 said it is still reviewing the files and will communicate with affected customers as needed. According to the regulatory filing, F5 learned of the unauthorized access on Aug. 9 but was allowed to delay disclosure for 30 days by the U.S. Department of Justice on Sept. 12 on the grounds that the revelation would present a national security risk.

The infiltration of a product development environment by nation-state actors is reminiscent of the SolarWinds hack of 2020, in which attackers — now identified by the U.S. as belonging to Russian intelligence agencies — accessed the update channel for SolarWinds’ Orion network management software and pushed code that could be used to gain access to customers’ systems. After that event, FERC ordered the development of new standards requiring internal network security monitoring at electric utilities. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)

That similarity might be why F5 emphasized that it had seen “no evidence of modification to our software supply chain, including our source code and out-build and release pipeline.” It brought in independent cybersecurity research firms NCC Group and IOActive to validate this claim.

Those firms are also helping F5 with code review and penetration testing to identify and remediate vulnerabilities, the company wrote. Additional mitigation efforts underway include rotating credentials and strengthening access controls across all systems, hardening the development environment, and deploying improved inventory and patch management automation.

F5’s recommendations for its customers include immediately updating their BIG-IP software. The company issued downloadable updates in its quarterly security notification, but warned that only versions of software that have not yet reached their end of technical support phase will be patched. Other resources made available by F5 are threat hunting guides, hardening guidance with a verification tool, and threat monitoring tools.

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), responding to the disclosure of the breach, issued an emergency directive ordering federal agencies to inventory their F5 products and apply updates to the affected software by Oct. 22. CISA also directed agencies to harden all public-facing BIG-IP physical or virtual devices and disconnect those that are no longer supported.

In CISA’s first press release since the federal government shutdown began Oct. 1, acting Director Madhu Gottumukkala said that “the alarming ease with which these vulnerabilities can be exploited … demands immediate and decisive action from all federal agencies.”

NERC and the Electricity Information Sharing and Analysis Center (E-ISAC) wrote in an email to ERO Insider that they were “not aware of any industry impact arising from the F5 vulnerability at this time,” but in the interest of caution, the E-ISAC sent an all-points bulletin to its members Oct. 15.

“The threat of cyber and physical attacks targeting critical infrastructure is not new, and ensuring a secure and reliable bulk power system is a top priority for NERC,” ERO staff wrote.

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NOPR Would Get Pipelines to Offer More Information for Grid Operators

FERC has issued an official notice that proposes new standards for business practices that are meant to improve coordination between the electric and gas industries involved in interstate natural gas pipelines.

The proposal would incorporate the latest changes to Version 4.0 of the Standards for Business Practices of Interstate Natural Gas Pipelines adopted by the Wholesale Gas Quadrant of the North American Energy Standards Board (NAESB).

“Such coordination is essential to maintaining reliability for both the natural gas pipeline network system and the bulk electric system, especially during periods when both systems have coincident peak requirements,” FERC said in the NOPR. (The notice of proposed rulemaking is part of the FERC process required before issuance of a final rule.)

Better electric and natural gas coordination has been a priority for decades with FERC, NAESB and other entities making iterative changes as the interdependent, but much differently regulated industries, continue to evolve.

“I wouldn’t frame it quite like it’s never going to be done,” FERC Chair David Rosner said at the post-meeting press conference. “I would frame it more like — on Tuesday, we’re having our annual reliability conference, and if you look back at the arc of our reliability work, it’s constantly evolving. And so one thing that’s important to me is that we work with our expert staff and NERC and with our industry partners to make sure that as the world changes, as these sectors evolve, that we’re doing things that are smart and that are durable, and that make sense, and that solve problems ideally, before they become problems.”

The changes come out of a forum NAESB held at the request of former FERC Chair Rich Glick and NERC CEO Jim Robb “to identify actions that will improve the reliability of the natural gas infrastructure system as necessary to support the bulk electric system and to address recurring challenges stemming from natural gas-electric infrastructure interdependency.” NAESB set up its Gas-Electric Harmonization Forum to tackle those issues, issuing a final report in July 2023. (See NAESB Forum Chairs Push for Gas Reliability Organization.)

Other aspects come from FERC and NERC’s Winter Storm Elliott report, which included some recommendations on coordination that NAESB took up. The changes include one revised standard and two new ones.

The revised standard creates a central location on pipeline informational websites where they can post publicly available data such as scheduled quantity information. Now, pipelines will have a new information category: “Gas Electric Coordination,” which can help ISO/RTOs and other parties assess the data during extreme weather or emergency events.

The first new standard facilitates the posting of applicable scheduled quantity information for power plants that are directly connected to the pipeline as part of the “Gas Electric Coordination” category.

The second new standard supports the inclusion of geographic information of affected areas, locations and/or pipeline facilities by a transportation service provider when issuing a critical notice.

Commissioner Judy Chang filed a concurrence, lauding the work NAESB has done to improve gas-electric coordination with the new standards but urging continued work to improve communication between the sectors and to address remaining issues.

“The NAESB standards proposed here exemplify the type of brick-by-brick incremental improvements needed to address pressing gas-electric coordination challenges,” Chang wrote. “However, these proposed standards alone may not be enough to fully address the ongoing challenges.”

More information sharing will improve situational awareness for grid operators and generators, which will help when the systems are stressed. It might make sense to include information about gas scheduled for generators not directly connected to the pipeline system, she suggested.

“I further encourage continued collaboration between pipelines, suppliers, natural gas marketers and owners of upstream gas gathering systems to update pipeline operators and ultimately downstream gas users and electricity system operators of changes in system conditions, such as wellhead freezes, that could affect natural gas users and consumers,” Chang said.

She asked commenters in the NOPR process to suggest other changes that could improve coordination.

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AEP Closes on $1.6B Loan Guarantee for Transmission Projects

American Electric Power has closed on a $1.6 billion U.S. Department of Energy loan guarantee to help finance 5,000 line-miles of transmission upgrades.

AEP Transmission will perform the work in Indiana, Michigan, Ohio, Oklahoma and West Virginia. It estimates the preferred interest rate deal will save ratepayers $275 million over the life of the loan while supporting economic development and technology advancements in the communities and regions served by the lines.

These benefits were emphasized by DOE officials as they announced the loan guarantee, which is the first closed under the Energy Dominance Financing Program created by the One Big Beautiful Bill Act in July.

“Energy is central to human lives in the United States and around the world,” Energy Secretary Chris Wright said during a call with reporters Oct. 16. “It’s not one sector of the economy; it’s THE sector of the economy that enables all the other sectors.”

DOE said electric utilities that receive loan guarantees under the DOE program must provide assurance they will pass along savings to their customers.

AEP provided a list outlining the 127 projects in the package. They range from a rebuild of 0.13 line-miles on the Comville-Cyril line in Oklahoma to work on 345 and 349.8 line-miles on segments of the Desoto-Sorenson line in Indiana.

In his remarks, Wright roundly criticized the energy policies of President Joe Biden and the financial support they offered for clean energy and decarbonization efforts. DOE’s Loan Programs Office — which has been renamed the Energy Dominance Financing Office — was central to this, Wright said.

Accordingly, DOE (like other federal agencies) has been canceling programs and funding central to Biden’s green agenda since President Donald Trump began his second term. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States and Energy Grants Worth $24B Appear Poised for Cancellation.)

But the review of these Biden-era awards — including AEP’s $1.6 billion loan guarantee, which was announced conditionally Jan. 16 — is showing that “not all of them were nonsense,” Wright said.

“The ones that are in the interest of the American taxpayers, in the interest of the American ratepayers, and there’s a helpful role for government capital, we’re happy to support those,” he said.

“We don’t care about authorship,” he told a reporter. “You’re right, this one started under the Biden administration, but it’s a good project. We’re happy to move forward with that. But, boy, there’s a lot [of projects] that don’t check those boxes.”

One of those was the Grain Belt Express, an $11 billion, 800-mile HVDC project under development since 2010. (See DOE Pulls $4.9B in Funding for Grain Belt Express.)

A reporter asked why DOE was backing AEP but not Grain Belt.

Wright said the AEP package is “a lot of bang for the buck” that will allow for better flow of power over existing lines to support economic development and reduce costs in five states.

Grain Belt, by contrast, will be slower and far more expensive per mile because it is new construction. Beyond that, it is a fundamentally different concept.

“Ultimately, that’s a commercial transaction, and it involves some market risk. Is that arbitrage big today, is that arbitrage still going to be big? Is it going to fund and pay off the construction of that transmission line? … It probably will, but it’s a more commercial enterprise that’s just done with private entrepreneurs and private capital.”

Greg Beard, who has been running what was known as the Loan Programs Office, added: “That project had a lot of merchant risk that was yet to be solved, and a consideration was: What’s appropriate for taxpayer risk and what’s appropriate for private market risk?”

Wright said: “I love energy infrastructure. I have nothing against the Grain Belt Express, I suspect it will still be developed.”

AEP hailed the agreement in a news release and said it will work with communities and landowners on siting the upgrades. CEO Bill Fehrman said earlier in 2025 that AEP will meet load growth with a capital spending plan totaling at least $54 billion. (See AEP to Meet Load Growth with More Infrastructure.)

He reiterated the growth in the Oct. 16 news release: “AEP is experiencing growth in energy demand that has not been seen in a generation. As the first company to close a new loan with the Trump administration under this program, we are excited to get to work on these projects to improve the service we provide to our customers.”

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9-GW Power Gap Looms over Northwest, Co-op Warns

The Northwest faces a “pretty scary” situation, with a new study showing a potential 9-GW capacity shortfall by 2030, increased energy prices and building constraints, the Pacific Northwest Generating Cooperative’s (PNGC Power) CEO said Oct. 15.

Jessica Matlock, CEO at PNGC Power, told the Northwest Power and Conservation Council that a recent study by Energy and Environmental Economics (E3) predicts that accelerated load growth and aging power plant retirements will create a resource gap starting at about 1.3 GW in 2026 and expanding to almost 9 GW by 2030.

“That’s approximately the load of the state of Oregon,” Matlock said.

As is the case nationwide, data centers are the primary drivers behind the expected load growth. PNGC members already have 15 data centers seeking connection within their service territories, Matlock said.

“And we wonder, is that really going to materialize? Well, they actually already came in and bought all the property and got the permits from the county, and they’re breaking ground. So, it’s actually happening now,” Matlock said.

Matlock added that the data centers are the “mega ones. These are the big ones that you all hear the names of: Amazon, Meta.”

PNGC consists of 25 electric cooperatives spread across seven Western states. PNGC operates as a Joint Operating Entity, allowing the utilities to pool resources and share risks. PNGC also is Bonneville Power Administration’s largest preference customer, according to the co-op’s website.

“Traditionally, we get all our power from Bonneville, but it’s been clear that Bonneville is pretty tapped out of hydropower, and so the region is looking at this huge deficit,” Matlock said.

BPA’s power rate schedule consists of multiple categories of primary rates for federal energy sales, including Priority Firm Tier 1 rate, which represents most of BPA’s power sales. Tier 2 rates are for energy a utility obtains from the agency in addition to its contractual right to power at Tier 1 rates, according to BPA’s website.

The issue now, Matlock said, is BPA’s Tier 1 is fully allocated, and the agency must compete for power on the market “against tech companies and other IOUs … that have deeper pockets in Bonneville.”

In July, BPA published new rates in its final record of decision for the BP-26 rate period covering the 2026/28 interval. Under the new rates, customers’ power rates will increase by about 8 to 9% over the next three years, while transmission rates will jump by an average of nearly 20%. (See BPA Customers to See Increased Power, Transmission Rates.)

“It’s getting pretty scary,” Matlock said. “So, the price of Tier 2 power for Bonneville is going to go up, including Tier 1 power.”

BPA spokesperson Maryam Habibi noted that BPA has created a new methodology for post-2028 under new provider-of-choice contracts.

“We would set the Tier 1 amounts each customer is able to purchase under a calculation outlined in that new provider of choice policy through a process next year,” Habibi said. “We don’t yet know if we would need to augment our resources for Tier 1 or Tier 2.”

Meanwhile, generator resources in active development account for 3,000 MW of new capacity, 850 MW of which are coal-to-gas conversions and 350 MW are hydro upgrades, Matlock noted.

“The others are wind, solar, potentially biomass, a couple other different resources,” she added. “That is not going to get us to where we need to get to.”

Some states, like Washington and Oregon, have strict decarbonization policies, making it difficult to meet the new resource adequacy requirements many utilities will be subject to under the two day-ahead markets emerging in the West: SPP’s Markets+ and CAISO’s Extended Day-Ahead Market.

“For those states that are really confined to what they can develop — because you cannot develop natural gas in some of those — how are they going to meet these? We’re not sure,” Matlock said.

To meet the resource adequacy requirements with just renewable power “would require huge amounts of land.”

“We are developing solar and battery,” Matlock said. “That’s because we get additional capacity. We are continuing to talk to solar companies to develop that to shift to our Washington members. But the biggest problem for us to get this solar power to these members is the transmission system is too congested.”

She noted that PNGC is building a natural gas plant in northern Idaho from which it will ship natural gas to members in Washington state “to help keep the lights on.”

PNGC is exploring building transmission itself with the help of federal grants aimed at connecting data centers to transmission and then partnering with BPA on the buildout. The agency has paused certain transmission planning processes to clear the interconnection queue. (See BPA Transmission Pause Questioned During Workshop.)

“If we can’t get transmission to move solar, wind, natural gas, geothermal across the region to supply power to cities and towns, we are going to have a significant problem,” Matlock said.

Habibi said BPA does not build its own resources, but she noted that the agency has launched initiatives, such as the Grid Access Transformation project, which are “designed to improve access and streamline our processes for connecting resources.” She added that the new power contracts “add flexibility for customers to add new, non-federal resources. That flexibility does not exist today.”