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April 27, 2025

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SPP MOPC Briefs: April 15-16, 2025

Members Pass Last of HITT’s 2019 Recommendations

HOUSTON — SPP’s Markets and Operations Policy Committee has endorsed the last of 21 recommendations made by a task force that reviewed the RTO’s transmission and market operations in the last decade.

The proposed tariff change (RR665) would establish “subregions” for the cost allocation of future byway (between 100 and 300 kV) upgrades.

“It’s been a long time coming,” Evergy’s Derek Brown, a supporter of the revision request, said during MOPC’s April meeting. “We just need to know the size of the subregions, which we now have.”

SPP said the tariff change could be implemented next year, once it receives approval from the Board of Directors, state regulators and FERC.

“I’ll just share Evergy’s opinion that we should try and move faster than that, if possible,” Brown said. “The policy has been approved for a long time now. We have some of the largest portfolios we’ve ever seen that we just went through the last few years, and we have another large one, potentially, in the 2025 [Integrated Transmission Planning assessment]. Cost allocation has a big impact on those discussions.”

The change, as developed by the Cost Allocation Working Group’s state regulatory staff, would decouple SPP’s Schedule 9 (zonal rates) and Schedule 11 (highway/byway) transmission pricing zones and create larger Schedule 11 subregions of existing zones. Two-thirds of the cost of byway upgrades would be allocated to the subregion where they are connected, with the remaining 33% allocated to the SPP footprint.

Similar to 300-kV and above highway projects, new base plan upgrades larger than 300 kV would be allocated RTO-wide.

The change must be approved by the board and Regional State Committee when they meet May 5.

MOPC approved the proposed tariff change with 75.99% approval. Six of 17 transmission owners and seven of 55 transmission users voted against it.

SPP’s board created the Holistic Integrated Tariff Team (HITT) in March 2018 to conduct a comprehensive review of the grid operator’s cost-allocation model, transmission planning processes, Integrated Marketplace and real-time operations. After a year of discussion, the 15-person HITT published a report with 21 recommendations. (See HITT Shares Draft Report with SPP Stakeholders.)

The tariff change was hung up for several years by work on another HITT recommendation to adopt a policy creating an appropriate balance between cost assessed and value attained from energy and network resource interconnection service products and generating resources with long-term firm transmission service.

“Not everybody got what they wanted on this, but this really is bringing about what was intended; what HITT wanted to do,” said Golden Spread Electric Cooperative’s Mike Wise, who was a HITT member. “I remember how long it took to get through [the other recommendations], and finally when we did, we breathed a sigh of relief. And then we started working immediately on [RR665].”

2025 ITP: Waiting on Study Request

SPP’s manager of transmission planning, Kirk Hall, told MOPC that the 2025 Integrated Transmission Planning assessment will be the most complex study to date.

He based his comments on a potential 9-GW generation shortfall; exponential load growth that has resulted in 57,000 non-converged contingencies (too many needs for one Microsoft Excel workbook); large loads interconnected with substations that have substandard transmission; and other factors.

“People have asked me, ‘What do you think the portfolio is going to look like this year?’ And I don’t really know, but I think it’s going to be somewhere between diddly-squat and a gazillion,” he said to laughter. “Somewhere in the middle. We’re just not quite there yet.”

Hall said staff were “smack dab” into the 2025 window for detailed project proposals (DPPs), which closed April 20.

SPP’s Casey Cathey explains revisions to the ITP assessments. | © RTO Insider 

“The transmission planning team is going to come in Monday morning, bright-eyed and bushy-tailed, and ready to start validating,” he said. “We’re anxiously awaiting those DPPs coming in.”

The 2025 study has completed its needs assessment but is in yellow status because the DPP submission window was extended. Hall said mitigation steps are being taken and staff are planning on-time approvals in the October MOPC cycle.

The 2026 ITP, which begins the transition into SPP’s Consolidated Planning Process (CPP) assessments, is also underway and developing its models. The 2027 ITP’s scope efforts should begin by late summer, Hall said.

Following the quarterly ITP update, MOPC endorsed a pair of motions recommended by the Transmission and Economic Studies working groups: scope changes that update the resilience language, and staging resilience projects. Those projects that also have economic, reliability, policy or operational needs will be staged based on the earliest need date identified; resilience-only projects will be staged as determined by model extrapolation and interpolation methodologies.

In other transmission-related issues, MOPC also:

    • endorsed a tariff change (RR673) that would eliminate a requirement to have met definitive interconnection system impact study (DISIS) requirements before submitting an interim service request. Instead, transmission customers can make that request when a DISIS open season is delayed.
    • accepted the Project Cost Working Group’s recommendation that 12 upgrade projects exceeding their estimated in-service date thresholds by more than 90 days be deemed reasonable and acceptable. Members also endorsed the baseline used to evaluate future in-service delays.

GI Queue Backlog on Track

SPP’s effort to relieve the generator interconnection queue backlog is on track, with four study clusters expected to reach the GI agreement stage in 2025, Natasha Henderson, senior director of grid asset utilization, told the committee.

Henderson said that while the 2017 and 2018 clusters are in the GIA stage, transmission customers in the 2022 cluster will receive their GIAs within three years of submission.

Natasha Henderson, SPP | © RTO Insider

The key cluster is the 2026 DISIS, which SPP hopes will be the first of its CPP. The new study process is expected to be brought before MOPC in July and the board in August. Assuming timely FERC approval, it could be active in 2026.

“The timing actually aligns so that we can either open the 2026 DISIS, or those same generators could go into the CPP,” Henderson said. “Either way, this is the time frame in which we would anticipate opening the 2026 DISIS window [for study requests].”

She said the timing could also benefit members of SPP’s RTO expansion into the Western Interconnection, set to go live in April 2026.

Excluding the record 2024 DISIS (102 GW), SPP staff are currently studying 325 projects representing 65.8 GW. Solar, wind and batteries account for all but 10% of the queue. Henderson said 24 GW have GIAs but have not reached their commercial operations date; another 5 GW have CODs in 2025, she said.

More than 150 projects have already withdrawn from the 2021, 2022 and 2023 clusters, taking with them 33 GW of capacity. Those withdrawals can shift upgrades and associated costs. They will be reassessed in the next planned study.

SPP Waiting for FERC’s Response on Z2

SPP says a FERC response is imminent for its plans to resettle invoices for transmission upgrades under tariff Attachment Z2, a process that has bedeviled the RTO since 2016. (See “Grid Operator Waiting for FERC Order to Resettle Z2 Funds,” SPP Markets & Operations Policy Committee Briefs: Oct. 15-16, 2024.)

“We, as well as many parties, have asked for an order soon, sooner rather than later, because of the significant interest that is accruing on those Z2 refunds,” General Counsel Paul Suskie told MOPC. “We continue to work hard to be proactive and addressing issues, answering questions and providing information in a transparent way.”

Under Z2, transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year.

SPP’s Paul Suskie updates MOPC on the Z2 resettlement status. | © RTO Insider 

However, software problems delayed the attachment’s final implementation for eight years before 2016, during which the RTO did not invoice for the upgrade charges. FERC approved a waiver request to settle more than 365 days in arrears, but in 2019, the commission reversed course and said SPP should have settled Z2 from only September 2015 forward. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

In January 2022, the grid operator filed with FERC an update to its proposed refund plan, submitted in 2019. SPP made an informational update to the commission in September 2024. FERC has made it clear SPP can’t process refunds without an order, Suskie said.

When the order comes, SPP plans to send out refund invoices with FERC interest for the March 2008-August 2015 operating days, accrued to the current invoice date. Once the resettlement system is deployed in about a year, invoices would be issued for the September 2015-January 2020 operating days. Additional resettlements from February 2020 would be run monthly in the current settlement system, along with normal current day Z2 settlements, until they catch up to the operating month.

“At this point, we’re waiting for a FERC order so that we can quickly issue the refunds and collect the money and issue the refunds, and then begin the process of building the models in the system so that we can start resettling 2015 to present,” Suskie told RTO Insider. “Once FERC gives us an order, we’re thinking it’ll take us about four years to resettle it.”

8 Tariff Changes

MOPC’s consent agenda included eight NPRRs that would:

    • RR658: prevent the uneconomic dispatch of demand response resources by creating an energy offer curve price floor equal to the net benefits threshold price for DR resources.
    • RR661: introduce a new “TCR model” definition in the transmission congestion rights (TCR) tariff language by clarifying the congestion-hedging team’s ability to adjust NERC-defined flowgates in the modeling process to match the day-ahead market topology and improve TCR funding.
    • RR662: remove Form EIA-411 from the Integrated Marketplace protocols.
    • RR663: develop inverter-based requirements based on reliability needs for SPP governing documents.
    • RR666: clarify deadlines for market participants submitting project-related data for commercial model changes and provide a commercial changes submission due date column.
    • RR667: add language clarifying that opportunity costs for hydro resources are excluded when obligations are imposed outside of the Integrated Marketplace. This does not include commitments ordered by a transmission provider or local transmission.
    • RR669: update the ITP Manual with SPP’s brand standards, correct small typographical errors and add consistent formatting throughout the document.
    • RR671: remove the annual violation relaxation limits analysis’ date requirement to create a more flexible timeline.
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PJM Stakeholders Discuss How to Increase Storage Development

A panel of storage developers, regulators and RTO representatives discussed the roadblocks holding back the growth of battery storage installations in PJM during a meeting of the RTO’s Public Interest and Environmental Organization User Group.

Claire Lang-Ree, an advocate for the Natural Resources Defense Council and moderator of the April 16 panel, said storage presents an opportunity to work toward state environmental goals while also providing capacity at a time when PJM is signaling a possible shortfall in 2030. While batteries share a similar effective load carrying capability rating to gas generation, she said, they aren’t affected by a shortage of turbines and have one of the fastest development timelines of any resource type.

“Really if we need resources to come online and provide capacity quickly, battery storage is uniquely positioned to do that,” she said.

She said storage also could allow generators to deactivate without requiring reliability-must-run (RMR) agreements, which are triggered when reliability violations are identified should a resource go out of service. PJM traditionally has resolved those needs with transmission projects, which consumer advocates and environmentalists have said take years to complete, sharply increasing rates while the RMR agreement is in effect and keeping fossil generation online longer.

Increasing Capacity Prices Create New Market Potential for Storage

Convergent Energy COO Don Jenkins said high capacity prices in PJM’s 2024/25 Base Residual Auction have helped make batteries more economical. But the core challenge continues to be the amount of time it takes to get construction started.

“Where we really run into the biggest roadblocks or delays is that permitting or interconnection process,” he said.

CAISO Storage Sector Manager Sergio Dueñas Melendez said long-term bilateral capacity contracts also can give investors the stability needed to invest in storage development, which has helped fuel the growth of batteries in California. The state directed utilities to develop storage procurement targets and worked with the public utilities commission, CAISO and utilities to resolve roadblocks to getting batteries online.

While the approach in CAISO is simplified by its structure as a one-state grid operator, Melendez said there are several PJM members with their own climate goals, who can develop their own procurement plans or coordinate with each other.

Grant Glazer, MN8 Energy senior manager of regulatory and market affairs, said the uncertainty of future capacity prices can make it difficult to underwrite storage as projects increasingly look to target revenues beyond PJM’s ancillary service markets.

New Market Products Could Capture Unrecognized Storage Capabilities

Much of the panel centered around whether new market designs or products are needed to reflect the capabilities storage has to offer.

PJM Chief Economist Walter Graf said batteries offer valuable flexibility when ramping capability is needed, but the only lever dispatchers often have is out-of-market commitments. When uplift is paid to resources for those services, all other flexible resources — like batteries or demand response — that also provide those services are undercompensated for services they provide.

Glazer said MN8’s top market design priorities are allowing storage resources to include opportunity costs in their energy bids, a seasonal capacity market and new ancillary service products — namely uncertainty and ramping reserves.

When storage resources are mitigated to their cost-based offers, Glazer said they cannot include opportunity costs and therefore lose the ability to manage their state of charge. This can cause a storage resource to discharge once it becomes profitable, even if prices are expected to be higher later in the day. It also can expose them to potential capacity performance (CP) penalties if they discharge before anticipated periods of high-strain conditions begin and a performance assessment interval is initiated. He argued that both forgone energy costs and CP risk should be allowed in energy market opportunity costs.

Jenkins said this was on display in ERCOT on April 7, when batteries were deployed earlier in the day only for there to be a spike in prices later in the day associated with thermal generators going offline. Had there been a mechanism for price signals to storage and dispatchers to recognize there would be a jump in demand in the near future, he said the dispatch of those resources could be better optimized.

Melendez said CAISO has “mitigated the challenges of mitigation” by introducing a default energy bid that includes opportunity costs which considers the highest price of the day-ahead market, the duration of the resource and the potential revenues a battery could miss out on.

The hold exceptional dispatch instruction also allows CAISO to tell a storage resource to reach a certain state of charge and maintain that for future needs, including opportunity costs in the process. It has proved useful, but the growing number of resources is cumbersome for operators to manage, leading staff to explore how it can be streamlined.

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APS, PNM Closer to Order 2023 Compliance

Two Southwestern utilities — Arizona Public Service (APS) and Public Service Company of New Mexico (PNM) — are closer to compliance with FERC Order 2023 but still have work to do in response to orders the commission issued April 17.  

FERC accepted in part compliance filings from APS (ER24-330) and PNM (ER24-1393), while directing the utilities to submit further compliance filings.  

Issued in July 2023, Order 2023 revised FERC’s pro forma generator interconnection rules to help clear backlogged interconnection queues across the U.S. It was followed by a clarifying order, Order 2023-A, in March 2024. (See FERC Updates Interconnection Queue Process with Order 2023.)   

The orders require transmission providers to transition from serial interconnection processes to studying interconnection requests simultaneously through cluster studies. 

APS Filings

APS submitted an initial filing for Order 2023 compliance in November 2023. FERC accepted it in part but told the utility to submit a filing with further revisions to address requirements in 14 areas. 

In its subsequent filing, APS proposed adopting without modification the pro forma interconnection procedures and agreements for large and small generators (LGIP, LGIA, SGIP and SGIA). 

In doing so, APS met requirements for the LGIA deposit, affected system study process and modeling, affected system pro forma agreements, co-located generating facilities, availability of surplus interconnection service, and modeling and ride-through. 

But APS’ filing also had “unexplained variations” from FERC’s pro forma LGIP, LGIA, SGIP and SGIA. In those cases, a transmission provider that’s not an RTO or ISO must explain how its proposals are consistent with or better than the Order 2023 provisions. 

Some of the variations in APS’ filing appear to be typos or minor mistakes, FERC said. 

Other variations were deemed to be consistent with or better than what Order 2023 prescribed. On the issue of study deposits, APS proposed a $105,000 deposit that it said better reflected its historical study costs than a FERC-tiered system with deposits ranging from $35,000 plus $1,000 per MW to $250,000. 

“We find that [APS’] proposed approach should reduce the number of instances in which an interconnection customer submits an upfront study deposit that ultimately exceeds its actual study costs and APS must then refund those excess amounts,” FERC said in its order. 

On the topic of allocating cluster study costs, APS changed the allocation method in its initial filing to a method that’s consistent with Order 2023. APS will allocate half of cluster study costs per capita among interconnection customers in the cluster and the other half of costs pro rata by megawatt. 

In other areas, FERC said APS’ proposal partly met Order 2023 requirements but needed further modification. Those include proposals related to site control, commercial readiness and the transition process. 

APS’ next filing is due in 60 days.  

PNM Filing

PNM submitted its Order 2023 compliance filing in March 2024, with amendments in May 2024 and March 2025.  

Similarly to APS, PNM tackled a long list of requirements by proposing to adopt without modification FERC’s pro forma LGIP, LGIA, SGIP and SGIA provisions. That included requirements related to commercial readiness, LGIA deposit, co-located generating facilities and availability of surplus interconnection service, among others. 

FERC also spotted typos and minor errors in PNM’s filing that need fixing.  

On requirements for the transition process, FERC accepted PNM’s proposal that any interconnection customer assigned a queue position “as of 30 calendar days of the commission-approved effective date of this LGIP” will retain that queue position and may choose to proceed with a transitional cluster study. 

FERC said the provision will give PNM’s “existing interconnection requests the option to participate in the transition process.” 

“We reiterate here that the provisions of Order No. 2023 are not intended to interfere with the timely completion of in-progress cluster studies,” FERC said in its order. 

FERC found that PNM had partly complied with requirements in other areas, including the cluster study process, study deposits and site control. 

FERC directed PNM to submit two filings: one within 60 days and the other 60 days before opening the initial interconnection request cluster window. 

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SPP Appoints New Director of Seams and Western Services

SPP has appointed Jim Gonzalez as its new senior director of seams and Western services, in what will be a highly visible position in the RTO as it continues to develop Markets+ ahead of its expected launch in 2027. 

Gonzalez will take over a role held by Carrie Simpson since 2022, who in March was promoted to SPP’s vice president of markets. (See SPP Brings Back Ex-staffer to Develop Western Services.) 

“Jim has played a key role in the development and administration of SPP’s market services for over a decade,” Simpson said in an April 21 release announcing the appointment. “His extensive knowledge and leadership will be invaluable to SPP’s work in the West.”  

According to the release, Gonzalez “will direct the ongoing development and implementation of Markets+ … and other electricity services in partnership with SPP’s stakeholders,” as well as serve as the staff secretary for the Markets+ Participant Executive Committee (MPEC), the policymaking group representing the market’s participants. 

“I’m thrilled to be part of such a great team,” Gonzalez said. “SPP and its stakeholders have done a tremendous job developing affordable, reliable energy services, and I’m ready to build on that success to bring a market that delivers substantial value to the Western Interconnection.” 

According to his LinkedIn profile, Gonzalez joined SPP in 2008 as an engineer, worked his way through the ranks into management positions in real-time operations and currently is the RTO’s technical director of market policy and operations. He holds a bachelor’s degree in electrical engineering from the University of Arkansas. 

“Gonzalez is an expert in market and system operations and has held various positions at SPP contributing to market development and the reliability of the electric grid,” SPP said in the release. 

Gonzalez likely will lead the effort to tackle what industry participants expect to be a key challenge for the West as Markets+ is rolled out in parallel to CAISO’s Extended Day-Ahead Market (EDAM): how to deal with the politically complicated and physically noncontiguous seams running between the two markets. 

EDAM supporters have raised strong concerns about market seams. Markets+ backers — including the Bonneville Power Administration and Powerex — have played down the significance of the issue, calling it “manageable” while acknowledging the two market operators will have to address challenges. (See Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says.) 

SPP has pointed to its own experience in managing the seams between its market and those of its neighbors. (See SPP’s Experience with Seams Could Help Markets+.) 

But others have taken a more cautionary view. 

“This is a special situation that you’re going to have in the in the West,” Richard Doying, vice president at Grid Strategies, said during the April 9 meeting of the Regional Issues Forum, a stakeholder body for CAISO’s Western Energy Markets. “It will be difficult to deal with, just because we don’t have any good historical precedents for how we would deal with this — and that is, we have currently a noncontiguous market footprint.” 

“We don’t have any existing markets where the markets are disconnected and they’re in their own isolated zones without physical transmission connected,” Doying said of Markets+. 

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NERC Responds to Industry Critique on IBR Standards

In reaction to industry concerns over its proposed ride-through requirements for inverter-based resources, NERC submitted a filing April 18 “providing additional clarity” on stakeholders’ concerns to FERC. 

NERC submitted PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers) and PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) to the commission in November 2024.  

Commissioners issued a notice of proposed rulemaking the following month that indicated it would pass both standards, with an added requirement that NERC provide two informational filings after they go into effect relating to PRC-029-1 and its provision for exemptions to voltage and frequency ride-through requirements for existing or “legacy” IBRs. (See FERC Approves NERC Assessment, Seeks Comment on IBR Standards.) FERC proposed that the filings be due 12 and 24 months after the conclusion of the standards’ exemption request period. 

The commission called for stakeholder comments. NERC replied March 24 requesting that it be required to submit a single filing 18 months after the exemption period ends. (See Stakeholders Call for Further IBR Standard Revisions.) The ERO’s most recent filing responded to issues raised by other industry respondents. 

NERC began by addressing comments from the American Clean Power Association (ACPA), the Solar Energy Industries Association (SEIA), Ørsted Wind Power America and the Western Interconnection Regional Advisory Body. According to NERC, these groups suggested the process for developing PRC-029-1 “did not allow full stakeholder engagement.” 

These claims arose from the unusual circumstances of the standard’s development, beginning in August 2024 after the standard failed to receive industry approval in a formal ballot round. With a deadline from FERC approaching, NERC’s Board of Trustees voted for the first time to exercise its authority under Section 321 of the ERO’s Rules of Procedure to streamline the normal development process.  

The board ordered NERC’s Standards Committee to hold a technical conference to gain industry input, then revise the standard and submit it for a formal ballot. This revised standard received a 77.88% weighted segment value supporting passage in October 2024. 

NERC recounted this history in its response, arguing it had “provided reasonable notice and opportunity for public comment, due process, openness and balancing of interests” during development, including the use of “a commission-approved process,” as it referred to Section 321.  

The ERO affirmed the final standard had been revised with input from the technical conference, contrary to the stakeholders’ claim, and that NERC submitted the standard to the board along with a report of minority issues raised during development. NERC concluded the standard development process was “in full accordance with Section 215 of the Federal Power Act.” 

The organization also discussed concerns raised by stakeholders about the proposed exemptions, which NERC said were considered by some to be “too narrow and limited” and by others to “impermissibly [favor] legacy IBR owners.”  

Among the first group were the ACPA and SEIA, which sought to have the exemptions expanded to include resources that have executed an interconnection and primary design, procurement and/or construction agreement by the effective date of the standard.  

The latter included the Louisiana Public Service Commission, which feared “transmission owners and operators are expected to mitigate an event consisting of an unknown number of IBRs disconnecting at any time in the future, in an unanticipated manner.” 

In response, NERC reminded FERC that its order to develop IBR ride-through standards required it to allow exemptions for IBRs “that are unable to modify their coordinated protection and control settings to meet the [standard’s] requirements.” It said the exemptions in PRC-029-1 were “consistent” with the order, which “expressly limited NERC’s discretion.” 

NERC acknowledged commenters’ concerns that the detail required in PRC-029-1 “may prove difficult or … impossible” for legacy IBRs to meet. But it said the idea of finding operational limits “is neither new nor novel” and suggested there are multiple ways to identify relevant issues. For this reason, NERC concluded its “limited and documented exemptions are consistent with” FERC’s directives. 

In response to Ørsted, Union of Concerned Scientists and other commenters that suggested PRC-029-1 should align with the IEEE 2800 standard for interconnection and interoperability of IBRs, NERC argued the IEEE standards are “adopted voluntarily … and are applied for their own business benefit.” By contrast, NERC said its responsibility is to reduce risks to grid reliability and safety. 

The ERO said the standard drafting team did consider the ride-through terms and tables in IEEE 2800. However, the team concluded that the IEEE standard contained clauses that “drafted in a manner that is enforceable within the current structure of NERC’s Compliance Monitoring and Enforcement Program.” IEEE 2800 also is not a publicly available standard, NERC continued, making it harder for responsible entities to access it. 

Finally, NERC said PRC-029-1 “was developed specifically to address the commission’s directives” and therefore is more stringent than the IEEE standard. Because of this added stringency, NERC said there is no conflict between PRC-029-1 and IEEE 2800.  

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EEI Names Drew Maloney as Next CEO

The Edison Electric Institute has selected Drew Maloney as its new CEO effective July 1, when he will succeed interim CEO Pat Vincent-Collawn.

Maloney will be the permanent replacement for Dan Brouillette, a former Secretary of Energy who stepped down last fall after less than a year at the helm of the investor-owned utility trade group. He had a brief tenure compared to former CEO Tom Kuhn, who ran EEI from 1990 through 2023.

“Drew Maloney’s extensive public policy expertise, financial and energy sector work and trade association leadership will be a tremendous asset to EEI member companies and the millions of customers we serve,” said EEI Board Chair Maria Pope. “His proven record in Washington, D.C., navigating some of the most complex policy landscapes by building effective coalitions, will be invaluable as our industry works to meet increasing electricity demand with a focus on keeping customer bills as low as possible.”

Maloney has been CEO of the American Investment Council since 2018. The AIC represents “the private investment industry” that includes private equity and major investors in the power sector. His work there included efforts to promote investment in energy production and critical infrastructure, EEI said.

Before working at the AIC, Malone was Assistant Secretary of the Treasury for Legislative Affairs during President Donald Trump’s first term. From 2012 to 2017 he was a vice president at Hess Corp., which was involved in the power industry early in his tenure before it sold that part of its business to focus on oil. Before working at Hess, Maloney was CEO of Ogilvy Government Relations, where part of his job was to promote investment in energy production and, according to lobbying disclosures, PJM was one of his clients.

“As AI transforms our industries, manufacturers return to our shores and daily life becomes more electrified, the strength and resilience of America’s energy grid is more critical than ever,” Maloney said in a statement. “EEI’s member companies make up an innovative and dynamic industry, and I am excited to work with them to lay out and execute policies to support critical infrastructure investment, accelerate the deployment of domestic energy sources and keep energy affordable and reliable for customers.”

Working with the Trump administration and Congress, Maloney said EEI can advance and strengthen energy independence and economic prosperity. Maloney holds a law degree from the Catholic University of America and earned a bachelor’s degree at Randolph-Macon College.

TXNM Energy CEO Vincent-Collawn has pulled double duty, serving as interim CEO of EEI since November while also continuing to run the utility holding company with operations in Texas and New Mexico. She has a long involvement with EEI’s board, becoming the first woman to chair the board of the trade group for a one-year term from 2017 to 2018.

“On behalf of the EEI board, I also want to thank interim President and CEO Pat Vincent-Collawn for her successful stewardship of the organization,” EEI Chair Pope said.

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New Hampshire OCA Raises Concern about National Grid Asset Condition Projects

The New Hampshire Office of the Consumer Advocate (OCA) has expressed concern that there is “reasonable grounds to object to at least some of costs” of two asset condition projects proposed by National Grid and argues the transmission owner should justify why the reliability needs addressed in its proposals should not be addressed through a competitive procurement process.  

The OCA letter, published April 18, is the latest in a series of complaints by New England states and consumer advocates about a lack of transparency and oversight into the planning and approval processes for asset condition projects.  

National Grid proposes to rebuild, reconductor and install optical ground wire on two lines in northeastern Massachusetts for about $271 million. For both projects, National Grid proposes to expand the scope of work beyond the most critical needs, in part to prevent more projects addressing reliability issues expected to arise over the next 10 years. 

Incumbent transmission owners typically have the authority to determine when and where asset condition projects are needed to address aging or deteriorating infrastructure and pass the costs on to ratepayers through formula rates. Asset condition projects are not subject to competitive solicitations for proposals. 

However, because the issues addressed by the proposals overlap with reliability issues identified by ISO-NE’s Boston 2033 Needs Assessment study and 2050 Transmission Study, the OCA argued the issues may require competitive procurements.  

“It remains unclear why a competitive solution process is not being used for these projects,” the OCA wrote. “It appears that the only reason a competitive process is not happening is because National Grid has chosen to treat these projects as [asset condition projects] and the ISO has disclaimed any responsibility for testing that choice.” 

The OCA highlighted ISO-NE tariff language that states that “where the solution to a Needs Assessment will likely be a Market Efficiency Transmission Upgrade, or where the forecast year of need for a solution that is likely to be a Reliability Transmission Upgrade is more than three years from the completion of a Needs Assessment, the ISO will conduct a solution process based on a two-stage competitive solution process.” 

The OCA said there appears to be enough time to pursue competitive procurement because the projects are not scheduled to begin construction until the second half of 2028 and are categorized by the Boston 2033 Needs Assessment as non-time-sensitive. 

“The objection isn’t necessarily to the projects themselves. … The system might genuinely need this to happen,” said Matthew Fossum, assistant consumer advocate at the OCA. “My concern is that this could allow National Grid to sidestep a competitive process that could meet the needs at a lower cost.” 

The National Grid proposals are not the only asset condition projects to draw scrutiny in the past year. In August 2024, the New England States Committee on Electricity (NESCOE) expressed concern about a “lack of compelling evidence to support the scope” of a $385 million asset condition project in New Hampshire. (See New England States Raise Alarm on Eversource Asset Condition Project.) 

Meanwhile, in March, NESCOE called for a “holistic, regional planning process” to ensure a proposal by Eversource to replace nearly all its underground transmission cables in the Boston area is conducted as cost-effectively as possible. NESCOE estimated the project’s costs could be in the $8 billion to $9 billion range “based on recent similar cost estimates.” 

At the urging of the states, the region’s transmission owners have taken steps in recent years to increase transparency around asset condition spending, including standardizing the format of informational presentations made to the ISO-NE Planning Advisory Committee, allowing stakeholder feedback and creating an asset condition project database. 

However, states and consumer advocates continue to argue there’s inadequate oversight for the projects, which make up a growing portion of the region’s transmission costs. In a March filing to FERC, NESCOE urged the commission to adopt “NESCOE’s long-standing request to implement an Independent Transmission Monitor” (EL25-44). (See New England Officials Discuss Tx Oversight and Rising Energy Costs.) 

Fossum said it was concerning that National Grid took nearly five months to respond to his request for more information on the projects, and he said the response he received was “essentially a non-answer.”  

National Grid declined to comment for this story, but wrote in a response to the OCA on April 15 that the expanded scope of the two asset condition projects will provide a longer-term solution “with the added benefits of also addressing future reliability needs.” 

It also included a response from ISO-NE, which said “asset condition projects will move forward independent of whether there are any [ISO-NE-]identified needs on the facility, resulting from Needs Assessments, Public Policy studies or Longer-Term Transmission Studies.” 

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Counterflow: Stop the Insanity, Trump 2.0

Last week, I wrote about a couple of breathtakingly foolish executive orders. I ran out of breath before getting to a third executive order that is competitive in this category. 

Steve Huntoon |

This one commands the U.S. Department of Energy to develop a complete methodology/model of the electric power grid within 90 days and, among other things, prohibits the retirement of any generation resource deemed critical to regional system reliability. The DOE is required to analyze current and “anticipated” reserve margins by region. (Reserve margin meaning a surplus of electric supply over electric demand.) Let’s think about this. 

“Anticipated” electric demand will increase over time. 

“Anticipated” electric supply will not increase over time because the prescribed methodology will “accredit” only generation resources that currently exist. This guarantees that anticipated reserve margins will be deemed deficient, thus mandating DOE orders under Section 202(c) of the Federal Power Act prohibiting virtually all generator retirements. 

This phenomenon is illustrated by a NERC map (Figure 2 on Page 8) projecting that by 2034, the entire country except Texas, New England and Florida will be deficient. Again, this is caused by ignoring new generation. 

Generators retire when they become uneconomic. The upshot of the executive order is to keep the uneconomic generators around, discouraging new economic generators from being built that would relieve the deficiency. So the reserve margin deficiency will never end. The perfect self-fulfilling prophecy! 

If you’re thinking you’ve seen this movie before, you’re right! In Trump 1.0, the use of Section 202(c) was urged by coal magnate Robert Murray to help his coal sales by keeping uneconomic coal plants open. I wrote multiple columns discussing that insanity, such as this one.  

To his credit, DOE Assistant Secretary Bruce Walker — a Trump appointee — said back then: “We would never use a 202 to stave off an economic issue [emphasis added]. That’s not what it’s for.” 

I guess “never” has a short lifespan these days. DOE was, of course, right in Trump 1.0. Section 202(c) is for short-term true emergencies — not to keep uneconomic generators around. And any order is required to be “temporary,” whereas these 202(c) orders would be the opposite of temporary. Did I mention the costs of subsidizing uneconomic generators, and the question of who should pay such subsidies? 

Honorable mention for Trump 2.0 insanity goes to the Trump administration ordering that construction stop on a fully licensed wind project.  

And another honorable mention goes to Trump’s statement that pro bono resources extorted from law firms would be donated to the coal industry: “We’re going to use some of those firms to work with you on your leasing and your other things.”  

Peabody Energy had not occurred to me as a worthy pro bono recipient, but what do I know? 

What I do know is that the upshot of what I covered here and in the prior column is to create unprecedented uncertainty for the electric industry. Stability, transparency and the rule of law have been America’s biggest competitive advantages for our industry and all others. Now we lose those.  

Rational investments can’t be made when: 

    • Fundamental elements of a regulatory construct may disappear next year, in five years or maybe never.
    • Nobody knows who’s really in charge of what.
    • Uneconomic generation may be kept around and subsidized indefinitely.
    • Past decisions might change on a whim and all decisions might be reversed on judicial review.
    • Previously granted licenses/permits are effectively revoked on a whim.
    • Resources are extorted from one industry to subsidize a favored segment of another industry.

The collapse of economic investment in our industry doesn’t have winners and losers. Only losers. If you have a say in regulatory and legal policies for our industry, please don’t be shy. 

P.S. If you might indulge me an update about Kilmar Armando Abrego Garcia, the 4th U.S. Circuit Court of Appeals has said in an order authored by Judge J. Harvie Wilkinson, a conservative Reagan appointee: “The government is asserting a right to stash away residents of this country in foreign prisons without the semblance of due process that is the foundation of our constitutional order.” 

Huzzah! 

Columnist Steve Huntoon, a former president of the Energy Bar Association, practiced energy law for more than 30 years. 

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Around the Corner: The Promise, Uncertainty and Unparalleled Risk of Data Center Load

Recent headlines and projections related to emerging data center load are astonishing. In February, Dominion Energy reported over 40 GW of data center contracts in its Virginia service territory as of December 2024, an increase of 88% from its July number. To put those numbers in perspective, Dominion’s record peak load in 2024 was just over 23 GW.

Meanwhile, that same month PPL Corp. stated it had received 54 GW of requests across its Pennsylvania and Kentucky service areas. PPL’s 2024 peak demand was 7 GW. Through the same period, Texas utility Oncor highlighted 228 transmission-level interconnection requests for 119 GW, almost four times larger than the 31 GW of demand it currently serves.

Numerous other utilities also are seeing significant numbers, with Exelon reporting data center load of 16 GW, and some single “hyperscaler” projects well over 1 GW. For example, Meta’s $10 billion hyperscale endeavor with Entergy in northeastern Louisiana is sized at 2 GW.

This activity is part of a global race to expand artificial intelligence capabilities while growing the underlying data center infrastructure. The investments clearly will be enormous, with profound implications for many utilities, especially those close to communications cables (it’s the confluence of numerous high-speed cables that makes Dominion’s northern Virginia region the data center capital of the world). However, it has become increasingly apparent that access to existing communications infrastructure is not as important as it once was. Today’s imperative is to access electricity as fast as possible, which means more utilities eventually will be affected.

The Overriding Mandate for Power

Leading chipmaker Nvidia’s CEO Jensen Huang highlighted the primacy of power in his March GTC keynote, stating:

Peter Kelly-Detwiler |

“Remember that one big idea is that every single data center in the future will be power limited. Your revenues are power limited. You could figure out what your revenues are going to be based on the power you have to work with. This is no different than many other industries. And so, we are now a power limited industry. Our revenues will associate with that.”

It’s all about accelerated access to the electron, so data companies are willing to go wherever electricity is available. That explains why Meta is working with Entergy to build three 750-MW gas generators in a remote and impoverished province in northeastern Louisiana. It’s also why Texas is a hot spot for new data load — the state has the land, and more importantly, it’s one of the easiest places in the country to develop new generating assets.

The Risks to Utilities and Ratepayers

After decades of relatively flat — or even negative — growth, many utilities understandably like what they see: enormous, high load factor demand from some of the most well-capitalized companies on the planet. At first blush, data load looks like a perfect antidote to stagnating utility revenues. However, this value proposition brings with it a significant level of risk. To understand where that risk lies, it helps to break this issue into discrete elements:

    • The Interconnection Requests and “Phantom Load” — The data industry power imperative is simple: Get access to energy as quickly as possible to maintain competitiveness. To get that power, large players may deal with utilities directly, or they may buy existing projects put together by other developers. In either case, they are incentivized to develop multiple applications across numerous locations.
      • If Project A wins, they withdraw Projects B and C. This approach is similar to the supply interconnection queue, in which fewer than 20% of projects initially entering the queue ultimately flow power. The fluid nature of the industry also results in constant changes. For example, in March, Microsoft withdrew 2 GW of projects in Europe and the U.S., and then in April, it pulled back from three Ohio projects worth $1 billion.
      • In addition to the big hyperscalers, numerous other players are active, including speculative developers looking to grab land, access power and flip their projects to third parties. The result is an inflation of the interconnection numbers that may be quite significant.
    • Contract Lengths and Temporal Mismatches — Recent contractual structures approved by utility commissions typically include a ramp period of four to five years, followed by a period of 12 to 15 years at full load. Contracts often are structured as take-or-pay agreements, meant to inoculate ratepayers during the length of the contract period, but only for the initial contract length. The problem is the contract durations align poorly with generation and transmission infrastructure with lifespans that often exceed 30 or 40 years. If data center loads were not so large, this risk would not be as considerable. Given their magnitude, if data center load shrinks or disappears, stranded asset risk could be quite considerable.
    • Competition & Consolidation — In the U.S. alone, more than a dozen entities have developed over 40 large language models that consume huge amounts of data and electricity. If the past battle for search engine supremacy or the lessons of general economic theory are anything to go by, we can expect many of these actors to fail or be consolidated in the future, creating attendant risk for both the utilities holding the supply contracts and their captive ratepayers.
    • Constantly Evolving Technologies — Data center technologies are highly dynamic and are becoming increasingly efficient. In cooling, which consumes roughly 35% of data center load, liquid and two-phase cooling promise to cut energy consumption dramatically, by as much as 90%. Meanwhile, performance of the cutting-edge chips from Nvidia demonstrates remarkable gains. The next-generation chip — to be delivered by 2027 — will yield performance gains of 900 times that of its chip introduced in 2022. Supported by AI itself, future chip efficiencies will improve.
    • Approaches to Training the Large Language Models — The traditional “brute force” approach to training AI models has been to combine powerful chips with huge amounts of electricity to crunch data — in some cases as much as a trillion parameters in a single training model. However, news out of China this spring suggests that in some instances there may be a better way that involves far few chips and significantly less energy. DeepSeek and Baidu’s Ernie X1 reportedly focused more on algorithms and software efficiency, so that they used fewer chips and far less energy. Neither has provided solid information with regard to their metrics, so verification is difficult, but there could be far better ways to achieve AI-related outcomes.
    • The biggest question related to efficiencies is simple: If the training models get less expensive, and the applications become more cost-effective, will society simply end up applying more artificial intelligence in more sectors of our economy? We thus would use less energy in our training models and more in “inference,” the application of the models to the real work in reasoning and making decisions. It’s simply too early to say.

The Challenge and Opportunity, and the Need for More Rigor

All of these issues point to today’s indisputable reality: The entire industry is morphing so quickly that nobody really knows what it will look like just a year or two from now. Given how rapidly the industry is growing, the hundreds of billions of dollars of investments that will take place just this year alone, and the rapid evolution of the models and underlying technologies, projecting the future is impossible. But we do know that big is big. The sheer magnitude of the potential investments required for both AI and general data center load suggests the opportunities for the utilities are unparalleled, even as the risks have rarely — if ever — been greater.

Utilities and grid operators are beginning to recognize these risks and approach some of these issues with more deliberation. In April, for example, ERCOT in its Long-Term Hourly Peak Demand and Energy Forecast highlighted 86 GW of data center load in 2031 as identified by Transmission Service Providers (TSPs). That number was based on both signed contracts and attestations from TSP executives. However, ERCOT significantly reduced its data center load forecast to 24,200 MW, “based on observation of behavior and characteristics of these loads, including average project delay, load profile by type and average project realization.” That’s still admittedly a very crude approach, but better than taking the numbers at face value.

PJM’s Independent Market Monitor recently commented on data loads and their potential impacts on markets, transmission and reliability, suggesting the grid operator should create a formal interconnection process — including milestones — similar to the one for supply. “Every new generator and every large load addition should go through this process,” the Market Monitor commented, adding, “There are no short cuts.”

Utilities also need to dramatically improve their interconnection processes. They need to better understand all aspects of this rapidly expanding and evolving industry — function, purpose, key value propositions, technologies and business models — and the attendant risks and opportunities for utilities and ratepayers.

The data and utility industries come from completely different cultures, technologies and ecosystems. They now suddenly are being thrust together to create what eventually will be a central nervous system that will affect the entire planet. As such, they need to do a lot more work to better understand each other, optimize their approaches and de-risk the outcomes.

Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.

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PJM MRC/MC Preview: April 23, 2025

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 11: Energy & Ancillary Services Market Operations resulting from the document’s periodic review. The changes include updating hyperlinks, correcting grammar, and specifying that data centers and crypto mining fall into business segment load. (See “Committee Endorses Manual 11 Periodic Review,” PJM MIC Briefs: April 2, 2025.)

C. Endorse proposed revisions to Manual 37: Reliability Coordination drafted through its periodic review. The changes are focused on administrative updates and clarifying the default baseline voltage limits.

Endorsements (9:10-9:30)

  1. Black Start Base Formula Rate (9:10-9:30)

PJM’s Glen Boyle will present a proposal to rework how resources providing black start service are compensated. The new formula would be based on a five-year average of the RTO-wide net cost of new entry (CONE) for the 2025/26 delivery year, which would be adjusted using the Handy Whitman index in following years. PJM has argued the change will reduce the volatility of black start compensation and prevent existing providers from ceasing their participation. (See “PJM Presents 1st Read of Proposal to Rework Black Start Compensation,” PJM MRC/MC Briefs: March 19, 2025.) 

The committee will consider endorsing the proposed solution and corresponding tariff revisions. Same-day endorsement will be sought at the Members Committee. 

Issue Tracking: Black Start Base Formula Rate 

Members Committee

Endorsements (10:50-11:05)

  1. Black Start Base Formula Rate (10:50-11:05)

If endorsed by the MRC, PJM’s Glen Boyle will present the proposal to rework black start compensation to the Members Committee. 

The committee will consider endorsing the proposed solution and corresponding tariff revisions. 

Issue Tracking: Black Start Base Formula Rate