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April 25, 2025

Commissioner Willie Phillips Announces his Resignation from FERC

FERC Commissioner Willie Phillips, who chaired the agency for two years, announced April 22 that he was leaving the agency just over a year before his term was set to expire, after pressure to resign from the White House.

In news first reported by POLITICO, the White House asked Phillips to step down. The move gives President Donald Trump the power to nominate a new commissioner, shifting its partisan balance to three Republican appointees and two Democrats, the standard make-up of a fully staffed FERC that gives the party in the White House a majority.

FERC Chair Mark Christie released a statement, noting the two had known each other for years before becoming federal regulators as they both were on state utility commissions that were active in the Organization of PJM States, Inc. (OPSI) and at NARUC.

“Willie has been a good friend for whom I have tremendous respect and affection,” Christie said. “He is a dedicated and selfless public servant. As I have said many times, he did an outstanding job as chairman of FERC. He and I worked together on many contentious issues to find common ground and get things done to serve the public interest. We will miss him here at FERC.”

Christie wished Phillips continued success on “whatever career path he chooses” after leaving the commission.

Phillips posted his own statement on LinkedIn, saying it was time for to move on after being a regulator for 12 years, which includes his tenure at the Public Service Commission of the District of Columbia.

“As my time at FERC comes to a close, I’m proud of all we’ve accomplished to advance a more reliable and affordable energy future for all Americans,” Phillips said. “Our grid faces growing challenges — from surging demand driven by data centers, to resource adequacy, capacity markets and the urgent need for transmission reform. These complex issues demand bold, innovative solutions, and I look forward to continuing to work on them in the next chapter of my journey.”

The other three FERC commissioners all released statements praising Phillips for his work on the commission, but his departure was criticized by longtime agency watcher and Public Citizen Energy Director Tyson Slocum.

“Commissioner Phillips’ decision to voluntarily leave his seat a year early hands control of FERC to the White House, where Trump’s radical plans to abuse national security and emergency powers will now likely no longer feature meaningful FERC opposition,” Slocum said. “Phillips had an opportunity to ensure an independent check on Trump’s abuses, but he apparently decided he has better things to do than ensure the public interest is protected.”

While the president can name the chair at FERC, current legal precedent holds that commissioners can be fired only for cause.

The chairs of other regulatory agencies that fall under that precedent, including the Securities & Exchange Commission, the Federal Communications Commission and the Federal Trade Commission, all stepped down when Trump took office this January. The chair stepping down if the opposite party won the presidential election used to be the norm at FERC, but it started breaking down before Trump took office in 2017.

A spat between President Obama and the Senate Energy and Natural Resources Committee left FERC with only three Democratic members when Trump took office and without a quorum when he demoted Norman Bay from chair, who resigned in response. Then after President Joe Biden took office, two of Trump’s former chairs — Neil Chatterjee and James Danly — both served out their full terms.

Chatterjee posted on X when the news broke that Phillips’ departure was disappointing, and he noted that the differences between commissioners at FERC usually are not partisan. Phillips pushed through new LNG export facilities when the Biden White House issued a pause on approvals from the Department of Energy, and he was the lone dissenter on a data center co-location deal last year when Republican colleagues voted to deny it. (See FERC Rejects Expansion of Co-located Data Center at Susquehanna Nuclear Plant.)

FTC Chair Lina Khan stepped down in January, but last month Trump fired two other Democratic appointees to the agency who are challenging that in court.

Speaking at the Colorado Legislature in March shortly after Trump fired him, FTC Commissioner Alvaro Bedoya said he was not focused on the status of the law, or respect for Supreme Court precedents.

“I think we need to be focused on the billionaires over President Trump’s shoulder at his inauguration, and what this attempt will do for them,” Bedoya said. “Because I think above all else, we need to be asking ourselves, who will win from this attempt to illegally remove us?”

Those included big tech executives like Tesla and X’s Elon Musk, Meta’s Mark Zuckerberg and Amazon’s Jeff Bezos, all of whom were subject to court orders or litigation from FTC cases, he added.

Trump has not made any moves on the two Democrats left on FERC, and doing so now would leave the agency without a quorum and unable to move on key policy priorities like ensuring data centers can reliably connect to the power grid or expanding LNG exports.

“What could happen is that if the president has the authority to remove members of the FTC, I would think there is nothing that would constrain the president from moving members of FERC if the president so desired,” former Chair Bay said at the WIRES Group Spring Meeting on April 3.

Bay also made the point that when he was on the agency, the split votes were more likely to happen between Democrats than across party lines.

“That was the world I came from, but I think that was really important for FERC authority, for its legitimacy, for the regulatory stability and certainty provided to industry,” Bay said. “And, so, what I hope does not happen at FERC is that you get a revolving door of commissioners based upon changes in presidential administrations.”

State Briefs

CONNECTICUT 

Gillett Confirmed for 2nd PURA Term

Marissa Gillett was confirmed by a 21-0 Senate vote for a second four-year term as the Public Utilities Regulatory Authority’s chair. Gillett, who has led the authority since 2019, was confirmed with none of the chamber’s 11 Republicans participating due to a planned walkout. The Senate also voted to confirm nominee David Arconti. 

More: CT Mirror 

ILLINOIS 

Byron Nuclear Center to Receive $355M Upgrade

Constellation Energy announced it plans to invest $355 million in the Byron Nuclear Power Station to increase the site’s output and extend its life of operation. The upgrade, set to begin in 2026 and finish in 2029, will replace six low-pressure turbines and two high-pressure turbines. The new turbines will generate an additional 80 MW and raise the facility’s output to 2,427 MW. 

More: Shaw Local News Network 

INDIANA 

Gov. Braun Signs ‘Construction-in-progress’ SMR Bill

Gov. Mike Braun signed a bill into law that enables public utilities to petition state regulators to recover costs for developing small module nuclear reactors. The law allows the state’s investor-owned utilities to recover the costs of developing SMRs from ratepayers before receiving a certificate of public convenience and necessity. 

More: Indianapolis Star 

Indiana Michigan Power Eyes Purchase of 870-MW Gas Plant

Indiana Michigan Power (I&M) has asked the Utility Regulatory Commission for permission to buy the Oregon Clean Energy Center. The existing 870-MW natural gas plant is one component of the utility’s Future Ready plan as it tries to meet power demand through 2044. Power demand is expected to more than double from approximately 2,800 MW in 2024 to more than 7,000 MW in 2030. I&M said it anticipates a decision from the URC on the filing in early 2026. 

More: Power Engineering 

MASSACHUSETTS 

DEP Delays Enforcement of Clean Truck Requirements

The Department of Environmental Protection announced a delay in its enforcement of minimum electric truck sales requirements. Under the Advanced Clean Trucks regulation the state adopted following California’s lead in 2021, medium- and heavy-duty vehicle manufacturers are required to produce and sell a gradually increasing percentage of zero-emission vehicles starting in model year 2025. 

The DEP said some manufacturers said the sales requirements “are too difficult to meet” and municipalities have said only a limited supply of clean trucks are available to comply with the standards. The department, which previously indicated it would be flexible about enforcement of some provisions, said it “will exercise enforcement discretion by not taking enforcement action against manufacturers that do not meet their Model Year 2025 or Model Year 2026” sales requirements as long as those manufacturers continue to provide internal combustion vehicles to distributors. 

More: State House News Service 

Massport Hires Climate Chief

The Massachusetts Port Authority has hired Jill Valdes Horwood as its first chief climate and resilience officer. The job includes helping the agency, which owns and operates Logan International Airport, get to its goal of net-zero greenhouse gas emissions by 2031. 

More: CommonWealth Beacon 

OHIO 

Power Siting Board Denies Solar Application

The Power Siting Board unanimously denied Stark Solar a certificate to construct, operate and maintain a 150-MW solar farm in Stark County. The board said there were many benefits to the project, but the benefits do not outweigh negative impacts to residents near the project. It cited opposition from local governments and residents as reasons for its denial. The company, or other intervenors in the case, could appeal the decision. 

More: Canton Repository 

PENNSYLVANIA 

EV, Hybrid Owners to Pay ‘Road-user’ Charge

Electric and plug-in hybrid vehicle owners will have to pay a fee each year to help with road maintenance beginning May 1. The annual fee is $200 for 2025 for full electric vehicles and $50 for plug-in hybrids. In 2026, that amount jumps to $250 for EVs and $63 for hybrids. After that, the fee would be reset based on the prior year’s consumer price index. 

The fee is expected to generate $16 million in 2025, which would be deposited in the state’s Motor License Fund that helps pay for construction, maintenance, repair and safety improvements on highways and bridges. 

More: Penn Live 

TEXAS 

Senate Approves Fines for Deceiving Solar Customers

The state Senate voted 22-8 to approve a measure that would give a state board the authority to fine residential solar companies as much as $100,000 for deceiving customers. 

A San Antonio Express-News analysis of consumer complaints filed with the Office of the Attorney General found that more than 50% said they were making payments on systems that were unfinished or faulty or that never worked. Another 28% said their systems were generating much less power than promised and usually not enough to offset the cost. 

The bill now heads to the House. 

More: Houston Chronicle 

VIRGINIA 

Balico Application for Pittsylvania Data Center Denied

The Pittsylvania County Board of Supervisors denied Balico’s application to rezone 750 acres for a data center and power generation project. Balico tried to withdraw its application; however, that move also was denied by the board. Balico will need to wait a full year before it can submit another proposal. 

More: Danville Register & Bee; Cardinal News 

Mecklenburg County Blocks Future Large-scale Solar Development

The Mecklenburg County Board of Supervisors voted unanimously to remove utility-scale solar as a future allowed land use. County Administrator Alex Gottschalk said the county was an early adopter of utility-scale solar but “the cons have, to date, far outweighed the pros in most people’s minds.” The supervisors will allow three pending projects to continue their permitting process, although they can approve or deny the projects as they see fit. 

More: Cardinal News 

WASHINGTON 

NextEra Energy Plans Grant County Solar Project

NextEra Energy Resources announced plans for the Dry Falls Solar project in Grant County. The facility would generate up to 400 MW while being complemented by 1,600 MW of battery storage. The proposal has been submitted to county commissioners, while the company hopes to begin construction this summer. 

More: Columbia Basin Herald 

WYOMING 

PSC OKs Rocky Mountain Power Rate Hike

The Public Service Commission approved a rate hike for Rocky Mountain Power. The PSC unanimously accepted a settlement between Rocky Mountain Power, the Wyoming Industrial Energy Consumers group and the Office of Consumer Advocate. The deal reduced the utility’s original request for a $123.5 million (14.7%) increase to a $85.5 million (10.2%) increase. The average residential bill will climb by about $14/month. 

More: WyoFile 

Federal Briefs

EPA Exempts Coal Plants from Biden-era Toxic Chemicals Rule

The EPA has granted 66 coal-fired power plants a two-year exemption from federal requirements to reduce emissions of toxic chemicals such as mercury, arsenic and benzene. A list posted on the EPA’s website lists 47 power providers that are receiving exemptions from the Biden-era rules under the Clean Air Act, including a regulation limiting air pollution from mercury and other toxins. The exemptions also apply to four plants operated by the Tennessee Valley Authority. 

More: The Associated Press 

USDA Cancels $3B Climate-friendly Farming Program

The U.S. Department of Agriculture has canceled a $3 billion program for climate-smart farming projects after a review found it did not align with the priorities of the Trump administration. 

The Partnership for Climate-Smart Commodities allocated $3 billion to 135 projects in every state that encouraged soil health, carbon sequestration, reduced methane emissions and other climate-friendly practices, according to the USDA website. The USDA determined that most of the projects provided too little money to farmers and too much to administrative costs. 

More: Reuters 

Report: $8B in Renewable Energy Investments Canceled in Q1

The first three months of 2025 saw nearly $8 billion in investments canceled and 16 new large-scale factories and other projects abandoned or downsized in the renewable energy industry, according to E2’s latest Clean Economy Works monthly update. 

The $7.9 billion in investments withdrawn since January are more than three times the total investments canceled over the previous 30 months combined, the report said. Still, companies continue to invest, as businesses in March announced more than $1.6 billion in investments for new solar, EV and grid and transmission equipment factories. 

More: Solar Builder Magazine 

Company Briefs

BGE Names Olivier New CEO

Baltimore Gas & Electric has named Tamla Olivier as its new CEO, effective May 1. Olivier joined Exelon about 15 years ago and has been the senior vice president and COO of Pepco Holdings — another subsidiary of Exelon — since 2021. Current CEO Carim Khouzami will move to a position at parent company Exelon. 

More: The Baltimore Banner 

Microsoft, Fidelis Partner on Carbon Capture Project

Fidelis announced it is partnering with Microsoft on a proposed $800 million facility at the Port of Greater Baton Rouge. 

Microsoft signed a contract with Fidelis’ portfolio company AtmosClear to remove 6.75 million metric tons of CO2 over a 15-year period as part of a larger effort by the tech giant to offset its greenhouse gas emissions, Fidelis said. It’s unclear where the CO2 will be sequestered, though several companies in the region are seeking permits for wells to inject and store it in rock formations deep underground. 

Fidelis said a final investment decision on the project is expected in 2025. Construction would begin in 2026, and commercial operations would start in 2029.  

More: The Advocate 

Schneider Electric Unveils Data Center Consulting Service

Schneider Electric has announced the launch of EcoConsult for Data Centers, a consulting service designed to help data center and IT managers achieve operational efficiency and maximum uptime. 

Schneider Electric said its EcoConsult service is a global network of more than 250 consultants, 430 service centers and 6,500 service representatives that helps ensure consistent, reliable and high-quality service worldwide. 

About 36% of U.S. data centers are more than 10 years old and lack a facility-wide proactive asset management strategy, according to Schneider. Their service aims to provide a roadmap toward ensuring maximum uptime, reduction in total cost of ownership and life extension of the infrastructure. 

More: Schneider Electric 

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.

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.

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. 

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+. 

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.  

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.