A California state Senate committee voted unanimously in favor of the Pathways bill, bringing the Golden State closer to allowing CAISO to cede oversight of its energy markets to an independent regional organization (RO).
Members of the state Senate Energy, Utilities and Communications Committee on April 21 voted 17-0 in favor of Senate Bill 540, dubbed “Pathways,” sending the proposed legislation to the Senate Judiciary Committee for a hearing April 29.
The bill is the product of the work of the West-Wide Governance Pathways Initiative, the nearly two-year effort to support the expansion of CAISO’s Western Energy Imbalance Market (WEIM) and soon-to-be-implemented Extended Day-Ahead Market (EDAM) to entities outside California by shifting governance of the markets from the ISO to a proposed independent RO.
Democratic Sens. Henry Stern and Josh Becker introduced the bill in February. During the April 21 hearing, Becker noted the legislation comes as SPP prepares to launch its own day-ahead market, Markets+, which already has attracted participants. (See Pathways ‘Step 2’ Bill Introduced in Calif. Legislature.)
“Why do we need to do this now? The urgency is that if we don’t act quickly, we risk having less ability to trade with other regions and impact the clean energy resources available across the West,” Becker said. “Regions are getting tired of waiting for us and are considering joining Southwest Power Pool’s Markets+. If they do, they will stop trading with California and also in this WEIM I mentioned earlier, and have less need to make other bilateral trades with California.”
Becker said participation in the RO is voluntary, adding that California retains its right to set its own energy policy goals and doesn’t have to join unless “specific, stringent guardrails are met.”
Reached for comment about Becker’s statement, SPP spokesperson Derek Wingfield told RTO Insider: “Markets+ creates additional opportunities for Western entities and will not inhibit trade among them, including entities in California.”
Stern, meanwhile, contended Pathways would allow California to tap into a wider market of clean energy resources, saying “if we don’t reach beyond our borders and allow for other cleaner renewables to be able to come in and balance our grid depending on the time of day, we’re gonna have to find that power somewhere. And right now, we are literally paying for it, and we’re not just paying for it with taxpayer dollars, but it’s in our lungs, it’s in environmental injustices everywhere.”
Representatives from the International Brotherhood of Electrical Workers, Natural Resources Defense Council, Environmental Defense Fund and others supported the bill during the hearing.
Opposition, Concerns
However, lawmakers also heard from opponents, including the Center for Biological Diversity, the California Solar & Storage Association and Californians for Green Nuclear Power.
Bill Julian, former legislative director of the California Public Utilities Commission, opposed the bill on behalf of himself and former CPUC President, Loretta Lynch.
Lynch, in a previous meeting, contended many of the arguments favoring Pathways rely on hypothetical scenarios in which EDAM would consist of participants from all Western states. This is unlikely, Lynch said, noting that several entities already have decided not to join EDAM. (See Pathways Initiative Receives Praise, Skepticism at Calif. Hearing.)
Though the committee voted unanimously to pass the legislation, some lawmakers voiced concern about the lack of certain provisions in the bill.
For example, Democratic Sens. Benjamin Allen and Aisha Wahab expressed concern about California’s ability to withdraw from the RO under the legislation.
Allen pointed to comments by groups like The Utility Reform Network (TURN) that have argued the bill’s language is not strong enough to protect from the risk of penalties against the state or utilities if California withdraws.
Committee member Susan Rubio urged Becker to explore further consumer protections.
Becker noted that the groups behind the bill are looking at amendments and plan to move forward with some suggestions, even some from opposing parties like Lynch.
“Certainly, you have my commitment to work with you and make sure that by the end of this process there’s a bill that we’re all comfortable with,” Becker said. “And then, as just a reminder, we’ll have at least two years with the legislature able to weigh in before we join.”
The Pathways bill states that CAISO can decide whether to join the RO-governed market on or after Jan. 1, 2027.
FERC has approved most of NYISO’s proposed plan to comply with Order 2023, denying several of its proposed variations to the commission’s pro forma rules and directing the ISO to submit an additional compliance filing in 60 days (ER24-1915, ER24-342).
Issued in July 2023, the order directed grid operators to revise their generator interconnection procedures to a “first-ready, first-served” cluster study process. It revised the commission’s pro forma procedures while allowing for independent entity variations to account for regional differences.
For NYISO, this meant altering several of the order’s time frames to align with its current Class Year study process, which already used a clustered approach, with queue position playing a limited role. For example, the ISO asked for 596 days to complete the overall study process, slightly more than the order’s maximum of 585, and proposed that its customer engagement window be 70 calendar days, instead of the order’s prescribed 60.
FERC accepted most of these in its April 17 order because it found they “accomplish the purposes” of Order 2023 and would give both NYISO and its interconnection customers flexibility.
While several parties protested the proposed 596-day time frame, the commission said “NYISO’s cluster study process has a unique study structure and requirements due to its proposed single, two-phase study process, which already incorporates restudies and does not have a separate facilities study. Thus, the timeline of the proposed NYISO cluster study process is appropriately compared to the timeline of pro forma study process including the pro forma LGIP facilities study timing, contrary to the contentions of” the protesters.
The commission, however, denied the ISO’s proposal to not allow interconnection customers to use third-party consultants to perform study work. While it argued “that study elements need to be sequenced and managed in a particular order, NYISO does not explain why a third-party consultant could not perform its study within that time frame,” the commission ruled. The variation would not “accomplish the purposes of the cluster study to increase efficiency and provide greater certainty to interconnection customers,” it said.
FERC also denied NYISO’s proposal to apply penalties only at the end of the process, and not at the end of Phase 1. The commission said this did not provide a sufficient incentive for NYISO to complete Phase 1 in a timely manner.
And FERC denied NYISO’s proposal to use a 300-day affected-system study timeline, saying it would bring the ISO out of step with neighboring regions that adhere more closely to the pro forma 150-day timeline. FERC told it to either revise the timeline to 150 days in its compliance filing or justify its proposal.
Finally, FERC rejected NYISO’s method for allocating the costs of several studies as outside the scope of Order 2023, but without prejudice, giving the ISO the opportunity to file it as a separate proposal.
MISO and PJM will not take on customary interregional planning studies this year, deciding they have enough on their plates with a new and in-progress joint transfer study.
The grid operators announced they would devote their attention throughout 2025 to their interregional transfer capability study (ITCS), a new type of study that might yield projects that allow for a greater volume of transfers. (See Smaller Projects Expected from Maiden MISO-PJM Joint Tx Study and OMS, OPSI Pen 2nd Letter to MISO and PJM to Compel Meaningful Interregional Planning.) The two decided against undertaking a more traditional coordinated system plan, which could result in more expensive interregional market efficiency projects, or their established, smaller targeted market efficiency project study.
MISO and PJM arrived at the conclusion after conducting an annual issues review designed to look for transmission opportunities. The process is required under their joint operating agreement.
The RTOs said there’s a possibility their ITCS changes the way the two manage future interregional studies. They said their transfer study could lay the “foundation for assessing future coordinated planning needs.” MISO and PJM are working from a blended, long-term model that combines the RTOs’ assumptions to identify system needs in the transfer study, a first for two major North American RTOs.
“By focusing our efforts on the ITCS, we aim to gain a clearer understanding of emerging transfer limitations and deliverability issues across the seam. The insights gained through this study will help guide future planning activities and determine whether additional interregional analysis or project development is appropriate in subsequent years,” MISO and PJM said in an April 18 emailed statement to their stakeholders.
The two said they would update stakeholders as the transfer study progresses and if “planning needs arise that warrant further coordination.”
MISO and PJM so far have identified more than 30 shared reliability, transfer and economic issues that could form the basis for upgrades under the ITCS.
In an emailed statement to RTO Insider, MISO said the goal remains to develop a draft portfolio by the end of 2025. MISO said it and PJM plan to open a monthlong stakeholder comment period at the end of April to solicit solutions.
MISO and PJM previously said they would focus on equipment upgrades and projects that can use existing rights-of-way in the first transfer study. They said the study, combined with FERC Order 1920, could open the door for longer-term interregional planning and greenfield projects.
MISO and PJM historically have approved one interregional market efficiency project in 2020 and four sets of the smaller targeted market efficiency projects aimed at relieving congestion since 2017. They haven’t completed an interregional transmission planning study since 2022.
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 makeup 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 the National Association of Regulatory Utility Commissioners.
“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 D.C. Public Service Commission.
“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 and 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.”
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.
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.
“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.
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.
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.
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.
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 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.
“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.)
“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+.
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.
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.
