Texas Public Utility Commission staff are drafting a rule to codify a process for exemption requests from ERCOT reliability requirements and allow owners of generation, load or energy storage resources to appeal the grid operator’s decisions to the PUC (57374).
Allison Fink, a staff attorney, told commissioners at their open meeting May 8 that ERCOT does not have a process for market participants to request exemptions. She said the proposed rule would not affect any existing exemptions or future provisions in ERCOT’s protocols, operating guides or other binding documents unrelated to reliability.
Staff are drafting the rule after ERCOT’s Board of Directors and stakeholders and the PUC approved a change to the grid operator’s Nodal Operating Guide (NOGRR245) that imposes voltage ride-through requirements on inverter-based resources. The revision was bifurcated so a subsequent rule change could address more details around the exemption process, a sticking point during the stakeholder process. (See “Bifurcated NOGRR245 Approved; 2nd Change to Add Details,” ERCOT Board of Directors Briefs: Aug. 19-20, 2024.)
Resource entities had until April 1 to request exemptions if they can’t meet the new requirements.
ERCOT General Counsel Chad Seely told the PUC that staff are processing more than 90 exemption requests. “I think we’re going to have quality issues with the data that’s going to take some time to work out with the individual resource entities,” he said.
Seely and PUC Chair Thomas Gleeson agreed cost should not come before reliability when evaluating the requests. “Costs can have a role in how we evaluate the overall risk,” Seely said. “What we don’t want is to be required to consider costs when there’s an unacceptable reliability risk.”
“I think [cost is] useful information to [entities] if they’re trying to figure out how to mitigate these risks,” Gleeson said. “But under no circumstance do I want ERCOT making the tradeoff between the value propositions on cost and reliability. Their focus should be on reliability.”
Staff Working on EOP Compliance
Staff from the PUC’s Division of Compliance and Enforcement (DICE) told commissioners they are handling about 130 violation findings for entities that have not filed either an initial emergency operations plan (EOP) and executive summary, or annual updates (53385).
The commissioners directed staff in September 2024 to investigate about 300 entities that were not compliant with filing their EOPs. The directive came following a report on the power sector’s weatherization preparedness and companies’ EOPs after a review of 691 electric entities. (See “PUC Adopts EOP Report,” EHV Tx Lines Coming into Focus for ERCOT.)
DICE opened investigations into 262 entities but were able to identify 76 that had met an April 2022 deadline or filed at least one of the annual reports due in March every year. Using a “corrective action plan” — essentially deferred adjudication, staff said — DICE closed out all but three of the cases.
In Massachusetts’ latest step to transitioning away from natural gas, the state’s Department of Public Utilities (DPU) has ordered major changes to the state’s program for addressing pipe leaks, aiming to better align the program with its long-term decarbonization strategy.
Massachusetts’ gas system enhancement planning (GSEP) process was created by the legislature in 2014 to reduce methane leaks from the state’s gas network. The program has come under fire in recent years from climate and consumer advocates, who argue it encourages the utilities to invest in replacement pipes that risk becoming stranded assets as the state moves away from gas.
Massachusetts has taken an ambitious approach to transitioning away from gas following the election of Gov. Maura Healey (D) in 2022 and the appointment of DPU Chair Jamie Van Nostrand. In late 2023, the DPU ruled that decarbonization of the state’s gas network should center around electrification, citing concerns about the overall viability of replacing natural gas with renewable natural gas and hydrogen. (See Massachusetts Moves to Limit New Gas Infrastructure.)
In the 2023 order, DPU singled out networked geothermal as the emerging technology with “the most potential to reduce GHG emissions.”
In recent years, lawmakers and regulators have made several changes to the GSEP process to account for the state’s climate strategy. In 2022, the legislature directed the utilities to consider using advanced repair technology in GSEP investments, and in 2024 the DPU required the utilities to consider the use of non-pipeline alternatives (NPAs). In late 2024, lawmakers amended the GSEP statute to put a greater focus on decarbonization and avoiding stranded assets. (See Mass. Clean Energy Permitting, Gas Reform Bill Back on Track, Mass. Gas Working Group Finalizes Recommendations to Legislature.)
Building on these efforts, the DPU on April 30 ordered a series of significant changes to the program, requiring the utilities to more rigorously document their analyses of pipe repairs and NPAs, lowering the annual GSEP spending cap and prohibiting the collection of carrying charges when utilities defer cost recovery on GSEP investments that exceed the annual cap.
“The GSEP program as currently implemented is not striking a good balance between safety and affordability, given the escalating costs and limited progress in addressing leak-prone pipe,” the department wrote in the order, adding that the utilities’ focus on pipe replacement is at odds with affordability and the state’s decarbonization laws.
The department estimated the utilities spent about $4.7 billion on GSEP projects between 2015 and 2024 and projected that addressing the 4,000 miles of remaining leak-prone pipe in the state would cost an additional $13.7 billion if the gas distribution companies “continue down the current path of relying primarily on pipe replacement and failing to control costs in any meaningful manner.”
“The replacement strategy followed by the LDCs [local distribution companies] is the most expensive path for customers, and the one most profitable for the LDCs given the earnings benefits of making a capital investment in new pipe having a useful life of 50 to 60 years,” the DPU wrote.
The DPU noted that its $13.7 billion cost estimate may be “relatively conservative,” as it assumes just 2% inflation, compared to the nearly 12% annual increase in GSEP costs seen in recent years. Prior to the DPU’s order, Dorie Seavey, senior research scientist at Groundwork Data, estimated the cumulative cost to ratepayers of the GSEP program was on track to reach $42 billion by the end of the century.
“The fundamental issue is the lack of any meaningful incentive for cost containment,” the DPU wrote, noting that GSEP’s accelerated rate recovery mechanism bypasses the typical regulatory lag between when investments are made and when utilities recover the costs, which typically “provides an effective incentive for the LDCs to minimize costs.”
The reforms were praised by the Massachusetts Attorney General’s Office (AGO) and climate advocacy groups, who recommended similar changes prior to the April orders.
“We applaud the DPU for adopting nearly all of our office’s recommendations to rein in the gas companies’ unrestrained and costly spending under the GSEP program,” Attorney General Andrea Campbell said in a statement. “It is fundamentally unfair to charge ratepayers billions of dollars to prop up the gas system as the commonwealth works to decarbonize.”
Both the AGO and the DPU framed the changes as an important step to reduce gas costs in the state, which skyrocketed this past winter due to increased delivery fees and high gas supply prices induced by cold weather. The DPU noted that GSEP costs are the second-largest component of gas delivery charges.
The GSEP cap reduction cuts the amount the utilities can spend through GSEP from 3 to 2.5% of the companies’ total firm service revenues. The DPU also wrote that it likely will cut the cap to 2% in 2026 and 1.5% in 2027.
However, the department still will allow the companies to spend up to the 3% cap on NPAs, which should create increased incentives for the utilities to pursue these alternatives.
In the proceedings prior to the order, the state’s gas utilities opposed cutting the spending cap, arguing it would make it difficult for them to meet their DPU-approved GSEP timelines, and would be “inconsistent with the Commonwealth’s climate goals and injurious to customers, from both a risk and financial perspective.”
However, the DPU rejected this argument, writing that “reforms in the risk prioritization process and increased integration of NPAs and advanced leak repair technology into the GSEP process” should enable the companies to meet their existing timelines while also reducing costs.
The department also stressed that the updates to GSEP cost recovery mechanisms should have no effect on reliability, as the gas companies “are obligated to spend whatever it takes to maintain and operate a safe gas distribution system, in compliance with all federal safety requirements.”
Also in the order, the DPU directed the companies to improve their frameworks for analyzing NPAs, writing that “it appears that the LDCs are continuing with business as usual for the 2025 GSEPs.”
The department emphasized the importance of NPAs for meeting the state’s decarbonization requirements and said the gas companies must fully incorporate NPAs into their planning processes to ensure full recovery of GSEP investments in the future.
The DPU also ordered the creation of a GSEP Risk Assessment Working Group to “improve the transparency and consistency of risk prioritization within GSEP filings,” which will begin meeting in the coming months.
National Grid and Eversource Energy, the two largest gas utilities in the state, said they are reviewing the orders. National Grid said it “is dedicated to exploring viable alternatives to gas infrastructure for heating, including targeted electrification and networked geothermal.”
Eversource wrote that its “work will continue on behalf of our customers to safely, efficiently, and cost-effectively address aging, leak-prone pipe across the state.”
PJM Director of Interconnection Planning Donnie Bielak presented additional details about the projects selected for expedited interconnection studies through the Reliability Resource Initiative (RRI) to the Planning Committee on May 6.
The one-time program is designed to allow a limited number of resources to enter the next study cycle based on the amount of capacity they would provide, as well as their locations and expected in-service dates. (See PJM Selects 51 Projects for Expedited Interconnection Studies.)
In a May 2 announcement of the results, PJM said 51 projects totaling 11,793 MW of nameplate capacity were awarded positions in Transition Cycle 2 through the initiative, 39 of which are uprates of existing resources while 12 are “new construction” projects.
The RRI projects are expected to start coming online this year, with four to be completed in 2025, six in 2026 and 10 in 2027. One existing project receiving additional capacity interconnection rights (CIRs) was listed as being completed in 2023 in Bielak’s presentation. Each project, whether it was selected or not, has been added to PJM’s Cycle Service Request Status webpage with queue numbers AH1-674 and above; Bielak said there are no projects outside of RRI intertwined with those queue numbers.
Bielak said the initiative is considered complete by PJM, and any projects not selected will have their deposits refunded. Even if some of the projects with RRI positions withdraw from the queue, he said PJM does not plan to allow others to take their place.
Because RRI was meant to address localized resource adequacy shortfalls that PJM is projecting in 2029, stakeholders questioned why some new projects with longer construction timelines were selected over uprates that could be completed more quickly. Bielak said some new developments had characteristics that outweighed the in-service date. The ranking process awarded 35 points for unforced capacity (UCAP); 20 for effective load-carrying capability (ELCC) rating; 10 for projects sited in Dominion or BGE; 10 for being able to enter commercial operation between 2028 and 2031; 10 points for providing evidence of permits, siting or equipment procurement to support the in-service date; and 5 points for using existing transmission headroom.
Several stakeholders asked if PJM could provide more information about how specific projects were scored to the public or the applicants, but Bielak said those results “cannot be discussed in any capacity” for data confidentiality reasons.
The Natural Resources Defense Council’s Claire Lang-Ree told RTO Insider that the weighting used to rank projects led to many being selected that are unlikely to be online in time to address PJM’s projected capacity shortfall, which she also sees as a significant reliability risk the region faces. Of the 51 projects selected, 21 are expected to come online between 2029 and 2031, amounting to more than 8 GW of the expected capacity. She said that creates a risk that construction delays could result in projects being pushed beyond the time frame that RRI is targeting.
“The vast majority of that capacity in UCAP terms is coming online at the last minute or too late to help with the capacity crisis PJM is anticipating,” she said.
Lang-Ree argued PJM should have prioritized the in-service date rather than “double counting” the output of a project by having separate ELCC and UCAP values in the ranking. With shorter development schedules, she argued a design that selected more storage resources would have provided more certainty around the ability for the projects to start providing capacity in time for the start of the capacity shortfall. Of the 46 rejected RRI applications, 12 storage and hybrid resources had in-service dates prior to 2029, 17 were aimed to come online that year, and one had an in-service date in 2030.
She credited the RTO for reworking its interconnection queue to process applications more expeditiously and noted that it recently announced a partnership with Alphabet and Tapestry to use next-generation software to process interconnection requests. The next area she said PJM should focus on is creating a process for replacing retiring generation with new resources on the same day the deactivation occurs. The siloed nature of the existing CIR transfer and deactivation processes creates roadblocks for developers to take advantage of the interconnection facilities left behind after a resource goes offline, Lang-Ree said.
PJM has filed a package of changes to its CIR transfer rules with FERC, which would eliminate categorical restrictions on which resources can participate and allow applications that may consume transmission headroom. The commission has yet to issue an order on the proposal (ER25-1128). (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.)
Transmission Expansion Advisory Committee
PJM Recommending Changes to Independence Energy Connection
PJM staff plan to recommend the Board of Managers revise the scope of the Transource Independence Energy Connection market efficiency project to abandon its eastern segment because of challenges with getting it approved.
The project includes two 230-kV lines, the western route running from the Ringgold substation in Washington County, Md., to the Rice substation in Franklin County, Pa., and the eastern route between the Conastone substation in Harford County, Md., and the Furnace Run substation in York County, Pa. While the Maryland portions of the project have been approved by the state’s Public Service Commission, the Pennsylvania Public Utility Commission rejected the certificate of public convenience for Transource to proceed with construction in the commonwealth. A federal court invalidated the rejection in 2023, ruling that it was based on economic protectionism rather than siting issues. Construction has not commenced on either of the lines. (See Christie Blasts PJM Pursuit of Transource Market Efficiency Project.)
Presenting an update on the project to the Transmission Expansion Advisory Committee, PJM’s Tim Horger said there are regulatory and constructability challenges with the eastern portion, leading staff to determine it no longer is worth pursuing. He said the most recent cost-benefit analysis found the original route, an alternate route modifying the eastern leg to use existing right of way and the western component alone each passed the 1.25-to-1 ratio threshold. The original had a 3.74 ratio, the alternate a 3.42 and the western-only route 3.85.
Carl Johnson, representing the PJM Public Power Coalition, said the RTO’s membership needs more information about how it conducted the analysis such that the cost-benefit ratio significantly increased for the 2025 project reevaluation. Horger said PJM can present more information about the topology and load forecast used.
Supplemental Projects
Dayton Power and Light presented a $480 million project to serve three new customers located near Jeffersonville and Wilmington, Ohio, by expanding several 345-kV substations and linking the Clinton, Fayette and Atlanta facilities with new 345-kV lines.
The Fayette and Atlanta substations would be expanded to breaker-and-a-half configurations to accommodate a 25-mile double circuit between the two sites, as well as two customer feeds from Fayette. The Clinton facility would be expanded with equipment for a new 27-mile line to Fayette and two 345-kV customer feeds. The project is in the conceptual phase with a projected in-service date in January 2031. The two Jeffersonville customers are expected to come online in September 2026 and ramp up to 1.5 GW of load by 2031, while the Wilmington customer is expected to come online in 2028 and grow to 500 MW.
The East Kentucky Power Cooperative presented a $566 million project to serve a new customer in Mason County expected to grow from 110 MW in 2026 to 2.2 GW by 2031. The customer has agreed to pay for all the interconnection costs.
The first phase of the project would construct two 1.5-mile temporary tap lines, one each on the 138-kV Spurlock-Goddard and Spurlock-Plumville lines. Next, a 345/138-kV switching station, to be named Mason County 1, would be constructed and tied into the 345-kV Spurlock-North Clark line with 1.5 miles of new lines. It would be outfitted with six 345-kV breakers, 15 138-kV breakers and two 345/138-kV transformers.
The next phase would expand the new substation with three more 345-kV breakers, 11 138-kV breakers and another 345/138-kV transformer. Another 345/138-kV switching station, named Mason County 2, would be constructed with eight 345-kV breakers, six 138-kV breakers and two 345-kV transformers. The second substation would tap into the 345-kV line between Mason County 1 and North Clark, and a new line would be constructed to Spurlock.
The final phase would expand Mason County 2 with three 345-kV breakers, 14 138-kV breakers and an additional 345/138-kV transformer. A third substation, Mason County 3, would be built and cut into lines between Spurlock and the two other Mason County facilities. A new 11-mile 345-kV line would be built to the existing Stuart substation. The temporary taps from the first phase would be removed when the rest of the work is complete.
PPL presented a $19.4 million project to rework portions of the Susquehanna switchyard to serve a 1,440-MW customer in Berwick, Pa. The customer is set to come in service in 2026 with 120 MW, growing to the full load in 2030. The transmission solution is in the development phase with a projected in-service date of May 30, 2028.
Dominion presented a $145 million project to address several violations in the Meadowville Load Area in Chesterfield County, Va. The work would rebuild the 230-kV Carson-Clubhouse line with new double-circuit structures and an additional 230-kV conductor. An additional 5.5 miles of 230-kV lines between Hopewell and the planned Sycamore Springs substation would be reconductored. The project is in the conceptual phase and is envisioned to be completed in the fourth quarter of 2030.
The company also presented a $135 million project to address thermal violations in the White Oak area of Henrico County, Va., through the 2025 Do No Harm analysis. Segments of the 230-kV Techpark Place-Darbytown, Chickahominy-Elmont, Chickahominy-Elko and Chickahominy-Bermuda Hundred lines would be reconductored, totaling around 40 miles. The project is in the conceptual phase and projected to go in service on Dec. 1, 2030.
Stakeholders Discuss DR Participation in Regulation Market
PJM’s Market Implementation Committee discussed a proposal to revise its governing documents to allow demand response (DR) resources to participate in the regulation market when there may be energy injected at the customer’s point of interconnection (POI).
Curtailment service providers (CSPs) would be required to have a net energy metering (NEM) agreement with the relevant electric distribution company (EDC) and explicit approval from that EDC to allow participation alongside injections. The same change also is part of PJM’s larger proposal to comply with FERC Order 2222, but some members have expressed a wish to have the capability implemented before 2028, when the Order 2222 implementation is set to go live.
PJM’s Pete Langbein said allowing DR participation at POIs with injection would require some software redesign.
Intelligent Generation CEO Jay Marhoefer said the company supported the proposal at the Distributed Resources Subcommittee (DISRS) because DR aggregators can get injection rights only when they have a wholesale market participation agreement (WMPA) or similar arrangement with PJM. When a DR resource provides regulation service, injection is allowed under an NEM tariff, but there no longer is uncounted energy and thus a WMPA no longer applies.
Representing DR providers, Bruce Campbell of Campbell Energy Advisors said it is arguable that a customer with a NEM agreement that includes the capability to inject energy cannot participate in the markets as DR. He said such configurations could be operated as DR when the injections are not wholesale energy.
1st Read on 3rd Phase of Hybrid Resource Rules
PJM’s Maria Belenky presented a set of proposed manual revisions to codify the third phase of PJM’s rules for hybrid resources, which would expand the rules to configurations in which non-inverter generation is paired with storage. (See “Third Phase of Hybrid Resource Rules Endorsed,” PJM MRC/MC Briefs: Nov. 21, 2024.)
For generation paired with storage, participation in the energy and ancillary service markets is based on PJM’s Energy Storage Resource Participation Model. For hybrids composed entirely of non-inverter resources, rules for participation are similar to those for wind and solar generation
The changes would allow the resource owner to decide whether the storage component of a hybrid should enter PJM’s market as open-loop capable, meaning it can charge from the grid, or closed-loop capable, limiting it to charging only from the generation components of the hybrid. Belenky said current practice dictates that if a storage resource is considered open-loop if it is physically capable of receiving energy from the grid, even if that does not reflect how the storage is operated.
Hybrids with a capacity obligation and composed entirely of inverter generation must meet their requirement to offer into the energy market by providing their economic maximum equal to or greater than the hourly forecast for each component of the hybrid. If there is a battery component, the offer should reflect the expected intermittent and storage output, including the “roundtrip efficiency of the battery.” The resource owner can use either PJM’s forecast or supply its own.
The changes also include adding a description of the formula used to determine lost opportunity cost (LOC) credits for hybrid resources that are instructed by PJM to charge to maintain reactive reliability. Resources are eligible for credits when locational marginal pricing (LMP) is lower than its offer.
The changes rewrite portions of Manual 11: Energy & Ancillary Services Market Operations, Manual 27: Open Access Transmission Tariff Accounting and Manual 28: Operating Agreement Accounting.
Stakeholders Endorse Market Suspension Rules
The MIC endorsed a slate of revisions to Manuals 6, 11, 28 and 29 to conform with a 2023 FERC order approving a PJM proposal to define how it proceeds with settlements under a market suspension. (See “First Reads on Manual Revisions,” PJM MIC Briefs: April 2, 2025.)
The filing established three sets of rules for determining real-time prices when suspensions last less than six hours, between six and 24 hours, or for longer periods. Shorter suspensions would average real-time prices for each hour before and after the outage; moderate-length outages would use day-ahead prices if available or an average of real-time prices for the intervals before and after the suspension began; and suspensions longer than a day would use an aggregate supply curve (ER23-1431).
For the day-ahead market, prices would be set to $0/MWh and real-time output and prices would be used to determine settlement.
Regulation compensation would be based on a market-clearing price calculated by PJM based on the average prices in the hour before and after a suspension lasting less than one day. For longer suspensions, the highest-cost resource in each hour would set the clearing price.
The price for synchronized, non-synchronized and secondary reserves would be based on the average price in the hour before and after a suspension for events shorter than six hours. If a suspension lasts between six hours and a full day, the day-ahead market-clearing prices would be used, and for events longer than a day, prices would be set to $0/MWh and LOC would be paid to resources.
PJM Presents on April 8 Reserve Shortage
PJM’s Brian Chmielewski presented information on a reserve shortage April 8 that caused shortage conditions to be declared in the RTO and Mid-Atlantic Dominion (MAD) subzone between 7 and 7:15 a.m. Colder-than-expected weather during the morning caused load to ramp up more quickly than forecast, limited ramping capability was available at the time and imports were scheduled to reduce by around 900 MW.
The event drove LMPs to $3,586.99/MWh at 7 a.m., with an RTO synchronized reserve deficit of 199.4 MW, a 792.6-MW primary reserve shortfall and 379.7 MW deficit in MAD, all of which was at the $850/MW penalty factor. Prices increased in the following 5-minute interval to $3,700/MWh before falling to $2,786.10/MWh at 7:10 a.m.
LANSDOWNE, Va. — PJM’s Members Committee voted not to reelect two incumbent members of the RTO’s Board of Managers: Chair Mark Takahashi and Terry Blackwell.
Committee Chair Lynn Horning, of American Municipal Power (AMP), called the body into recess, following Exelon’s motion to reconsider, to allow members time to prepare to cast votes on the motion and potentially a second ballot on the two board members. The committee will return to session on May 13 at 11 a.m. ET.
Takahashi received 30.8% sector-weighted support in the vote, shy of the 50% required to be elected, while Blackwell received 43.5% support. The committee did vote to elect Matthew “Matt” Nelson, principal of regulatory strategy at Apex Analytics, to fill the seat vacated by outgoing board member Dean Oskvig, who is retiring. Prior to his position at Apex, Nelson served as chair of the Massachusetts Department of Public Utilities and worked on Eversource’s regulatory policy team for four years.
PJM CEO Manu Asthana expressed disappointment with the results of the vote but said he respects the will of the RTO’s members. Asthana noted the board is in the process of searching for his own replacement and also will be seeking a new board member when Charles Robinson steps away next year. (See PJM CEO Manu Asthana Announces Year-end Resignation.)
“As the outgoing CEO, I will say there is a lot of change happening at PJM with Dean leaving, with Charlie leaving next year … my experience with both Terry and Mark has been exceptional. I could not ask for more hard-working, dedicated board members,” he said.
In an emailed statement, PJM spokesperson Jeff Shields told RTO Insider, “PJM members, via our governing documents, decide who will serve on the independent Board of Managers.”
Introducing the motion to reconsider, Exelon’s Alex Stern said losing two experienced board members, the sitting chair especially, could cause expertise to drain from PJM at a particularly sensitive time, with looming resource adequacy concerns and an ongoing CEO search.
“We are in the beginning of a historic time, complete with an executive order declaring a national energy emergency,” Stern said, pointing to a series of “challenges” facing the RTO, including resource adequacy issues, large load additions and the transition to a new CEO.
“I’d like to ask for a revote. I’m hopeful that some of the folks that voted against may now, given the result, may appreciate the opportunity to consider … the destabilizing influence of what just happened with this vote,” he said.
That motion was seconded by Vistra’s Erik Heinle, who said he understands the frustration many members feel with PJM’s direction over the past year but contended this is a critical time for the RTO. He said both Takahashi and Blackwell have been excellent board members and that he appreciates their openness and willingness to reach out to RTO members. He said the results of the vote sent a message to the board that the membership wants to see a change in direction, but there is no reason to continue down the path of removing two experienced leaders.
Transparency Concerns
LS Power’s Marji Philips said PJM members have been extremely disappointed with the direction the board has taken. Without further statements from board members about how they would act differently, she argued there is no reason for members to change their votes on whether to reelect Takahashi and Blackwell.
“It’s not just a sign; it’s a sign that we want change … so what is the change we could see if we revote this?” she said.
Paul Sotkiewicz, president of E-Cubed Policy Associates, pushed back on the idea that removing two board members would be destabilizing, saying PJM is on a perilous course and a change in leadership is needed to avert a crisis down the road.
“This was clearly a vote of no confidence and to say that this would be destabilizing … I don’t think there’s been anything more destabilizing than the last few years at PJM,” he said.
Members also voiced concern about how a vote to reconsider could be administered. A third-party vendor conducts the vote to elect board members in a portal that provides PJM staff no access to see how individual members have voted. However, PJM Director of Stakeholder Affairs Dave Anders said the vendor cannot change voting on the fly. Therefore, the vote to reconsider would have to be done through PJM software. If the members give the directive, Anders said staff is willing to commit to ensuring that sector and member votes remain private and that the internal audit team can ensure the data is deleted without having been viewed.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), told RTO Insider that many advocates feel there has been little improvement since the 2024 Annual Meeting, when the sector voted against reelecting board members Paula Conboy, David Mills and Vickie VanZandt out of frustration with the design of the capacity market and a proposal to shift filing rights over regional planning from PJM’s membership to the board. (See Stakeholders Re-elect 3 PJM Board Members Over Consumer Dissent.)
Poulos said consumer advocates have supported several major board decisions — such as renewing the Independent Market Monitor’s contract and modeling the output of resources operating on reliability-must-run (RMR) agreements as capacity. But even in many of those instances, he said, the board acted with little transparency and rushed through the stakeholder process, leaving advocates feeling their perspectives were not sought.
Poulos stressed that the advocates who voted against reelecting Takahashi and Blackwell did not do so out of opposition to them as individual candidates, but because there’s no other way to hold the board accountable, given that it meets in private and acts as a body. He noted that board member David Mills told the committee on April 12 that the board is planning to add a standing agenda item to the end of future MC meetings where attending board members will speak with stakeholders with the hope of providing more transparency.
Federal policy changes and slow buildout of emissions-free generation may change the timetable for the retirement of New York Power Authority gas-fired peaker plants in New York City.
Environmental and neighborhood advocates have long sought a reduction in fossil-fuel power generation within the city, due to serious local impacts on air quality and residents’ health.
NYPA had begun planning for such a transition years ago, such as by installing battery storage on the sites.
Then 2023 state legislation mandated the shutdown occur by 2030 — if doing so would not harm grid reliability or result in a net increase of air pollutants within any disadvantaged community.
Advocacy groups working as a coalition called Public Power NY criticized this as excuse-making by a state entity not living up to their vision of it becoming a new driver in a lagging energy transition.
When the 2023 legislation was drafted, negotiated and enacted, a clean energy transition backed by hundreds of billions of federal dollars was ramping up and New York state had a robust-looking pipeline of more than 10 GW of renewable energy generation proposals working their way through to potential construction.
Two years later, a new federal administration is racing to turn the emphasis back to fossil fuels and in some cases actively thwart renewable energy development. New York’s pipeline is in tatters, with many projects having paused or terminated offtake contracts amid cost escalations.
NYPA said in the transition plan that its small gas plants — 10 simple-cycle units at six sites in New York City and one in suburban Long Island, totaling 460 MW — are among the cleanest and most efficient in the area. By law, NYPA needs to ensure that shutting them down will not cause dirtier plants to run more and degrade air quality further by doing so.
Meanwhile, electricity demand is growing and NYISO has raised reliability concerns of varying severity.
These things informed the transition plan. It reads:
“The plan concludes that, at this time, NYPA must conduct additional studies with the NYISO and expert consultants to determine the impact to air quality in disadvantaged communities across New York state, including in New York City and Long Island, when the small plants are shuttered.”
NYPA will consult with utilities and the Department of Public Service to decide if plants whose retirement would not harm air quality also would not harm grid reliability by retiring.
The problem is there’s “unprecedented uncertainty” about the future resource mix that would determine grid reliability.
Just three weeks before the transition plan was released, federal regulators slapped a stop-work order on Empire Wind 1, a fully permitted offshore wind project that would send up to 810 MW of emissions-free power right into New York City.
Clean energy advocates and public power supporters have long chafed at the pace of decarbonization in New York state, where energy development is slow and expensive.
Some of these advocates also sought for years to place a greater responsibility for renewables development on NYPA, reasoning that it could do the work at a lower cost than the private sector.
They got much of what they were seeking in the spring of 2023, when the state budget included provisions directing NYPA to start developing renewables and stop running the fossil peakers, with the air quality and reliability caveats.
Public power advocates had been hoping for NYPA to kick off its new role with a robust 15-GW debut plan for renewables development. They were sorely disappointed when NYPA adopted a 3-GW plan and predicted a high rate of attrition.
They were disappointed again with the transition plan.
Public Power NY Co-chair Michael Paulson said May 12: “The Build Public Renewables Act directed NYPA to shut down their peaker plants by 2030 and begin to redress environmental injustices and extreme public health impacts. Unfortunately, their plan is short on detail and long on excuses for potential failure. New Yorkers deserve better: a proactive plan to shutter the peakers and a commitment to build 15 GW of public renewables to facilitate that transition.”
NYPA is self-funded. Its roughly 6 GW of capacity generates about 22% of the state’s electricity, most of it emissions-free hydropower.
The preliminary results of PJM’s look ahead at the capacity available for this summer and the expected peak loads suggest that about 5.4 GW of demand response could be needed to maintain the 3.5-GW real-time primary reserve requirement.
The season is forecast to see a 90/10 diversified peak load of 166.6 GW for the season, with 175.6 GW of committed capacity and fixed resource requirement (FRR) resources available, plus 3.6 GW of non-capacity resources. About 13 GW of that is expected to be on outage when called on, with an additional 1.6 GW flowing out to serve firm interchange. Even with a 5.4-GW load management deployment, PJM said it may fall 1.5 GW below the day-ahead scheduling reserve requirement (DASR).
An announcement of the outlook described the 90/10 forecast as an “extreme planning scenario” and noted that the generation expected to be available remains above 160,961-MW peak load in the 50/50 forecast. No reliability violations were identified in the Operations Assessment Task Force’s (OATF) summer report.
“This season also marks the first time in PJM’s annual assessment, however, that available generation capacity may fall short of required reserves in an extreme planning scenario that would result in an all-time PJM peak load of more than 166,000 MW,” PJM said in the announcement.
PJM’s Mark Dettrey told the Operating Committee that the OATF report focuses on meeting the forecast peak load, whereas the 90/10 analysis included reserve requirements.
In the low solar and no wind sensitivity, 3.8 GW of renewable resources are modeled as being unavailable, leading to the system falling 1.3 GW short of the DASR target and triggering a 9.2-GW load management commitment. The single largest gas-electric contingency scenario would take slightly more off the grid at 4 GW with similar impacts. PJM also modeled the two combined in a “stressed system scenario” and found that could cause a 9.3-GW DASR shortfall and require 13.2 GW of load management.
Dettrey said the drivers are in line with the resource adequacy concerns PJM has been airing over the past few years: deactivating generation, sluggish new resource entry, and accelerating load growth fueled by data centers and electrification. The outlook shows there is increased risk of emergency procedures, such as capacity deployments, and that PJM will be “heavily reliant on” good generator performance, Dettrey said.
April Operating Statistics
Presenting the April operating metrics, PJM’s Marcus Smith told the OC the month saw an average forecast error rate of 1.45%, just shy of the 1.5% benchmark, and a peak error of 1.34%.
Three days surpassed the 3% day-ahead forecast error rate, with low temperatures leading to a 3.62% overforecast of the peak load April 8. During the MIC meeting May 7, PJM presented how rapidly ramping load that morning caused reserve shortage conditions, driving high LMPs.
April 27 and 28 both saw underforecasting as higher-than-expected temperatures contributed to high consumption.
PJM experienced two spin events, two shared reserve events, five high system voltage actions, one geomagnetic disturbance warning and 11 post contingency local load relief warnings.
The first spin event was initiated at 4:21 a.m. April 5 and lasted eight minutes and 23 seconds, with 1,755 MW of generation and 452 MW of DR assigned. The generation resources had a response rate of 87%, and 89% of the DR responded.
The second event was at 12:50 a.m. April 24 in the Mid-Atlantic Dominion (MAD) zone and lasted seven minutes and three seconds. There was 1,085 MW of generation assigned, 86% of which responded. No DR was assigned.
Key House committees are marking up “One Big, Beautiful Bill” for the fiscal 2025 budget that includes much of President Donald Trump’s legislative goals, including clawing back funds and phasing out tax credits for clean energy.
The House Ways and Means Committee on May 12 released proposed language that would axe the tax credits for energy-efficient and plug-in vehicles while winding down credits for renewable and nuclear energy earlier than current law.
The production tax credit (PTC) and investment tax credit (ITC) for wind and solar already are in place until the later of 2033 or when CO2 emissions fall below 25% of 2022 levels. Under the bill, both would start to be rolled back in 2029. Projects put into service by Dec. 31, 2028, will be eligible for the full rates, but that will be cut back to 80% in 2029, 60% in 2030, 40% in 2031 and then expire entirely for 2032.
American Clean Power Association CEO Jason Grumet criticized the early phaseout as causing disruption when the industry needs to meet surging demand. He promised to work with Congress to improve the language as the bill moves forward.
“The Ways and Means bill is at odds with American energy dominance,” Grumet said in a statement. “If adopted, the proposed language will raise energy costs for American consumers, force American factories to shut their doors and threaten American jobs. While our industry is ready to engage constructively and find a workable path forward, the committee’s approach simply goes too far too fast.”
Even without subsidies, some wind and solar would have been built, but the tax credits have expanded their capacity on the grid well beyond that hypothetical, American Enterprise Institute’s James Coleman said at a panel on Capitol Hill on May 6 hosted by the Electric Power Supply Association. The tax credits do not need to go to zero tomorrow, which would upset business plans, he said.
“But I do think it’s a problem that needs to be phased out, addressed, lowered — something needs to be done there,” Coleman said.
The 45U PTC for existing nuclear also would be wound down earlier, following the same schedule as the other tax credits.
Provisions in the bill also would end the transferability for tax credits, which allows energy producers to sell them to third parties.
“Our well-run, low-cost nuclear plants earn over $500 billion in tax credits that go directly to reducing our customers’ bills,” Sideris said. “Nuclear has broad support in Washington, and we were pleased to see last week [that] 26 representatives signed a letter stressing the importance of these nuclear tax credits and transferability to the president’s objective of affordable and reliable energy.”
The Natural Resources Defense Council criticized the bill after the text was made public.
“This measure would hike energy bills, not lower them; cut domestic energy production, not increase it; and put workers out of jobs, not spur American manufacturing,” said Jackie Wong, NRDC senior vice president for climate and energy.
The bill would immediately end energy efficiency tax credits, including the Energy Efficient Home Improvement (25C) credit and the New Energy Efficient Home (45L) credit. It also would end credits for individual consumers to buy new (30D) and used (25E) electric vehicles and the Commercial Clean Vehicle credit (45W).
“Canceling these tax credits would raise monthly costs for American families and businesses,” American Council for an Energy Efficient Economy Executive Director Steven Nadel said in a statement. “This proposal would make it harder for homeowners to make energy improvements that lower their utility bills and improve their comfort. It would reduce builders’ incentive to construct efficient homes with low monthly energy bills. It would make it harder for individuals to use electric cars and businesses to use electric trucks, which can both lower monthly costs.”
House Energy and Commerce’s Markup
The Energy and Commerce Committee also released language that includes clawing back some unspent funds from the Inflation Reduction Act and provisions meant to speed up permitting of natural gas infrastructure and electric transmission.
“This bill would claw back money headed for green boondoggles through ‘environmental and climate justice block grants’ and other spending mechanisms through the Environmental Protection Agency and Energy Department,” committee Chair Brett Guthrie (R-Ky.) wrote in an op-ed published by The Wall Street Journal. “The legislation would reverse the most reckless parts of the engorged climate spending in the misnamed Inflation Reduction Act, returning $6.5 billion in unspent funds.”
Those clawbacks would include funding for transmission, facilitation of the siting of interstate lines, and interregional and offshore wind electricity transmission planning.
Language from Rep. Julie Fedorchak (R-N.D.) is meant to speed up cross-border pipelines and transmission. It would remove the process from the State Department and the White House and give FERC authority over siting pipelines and DOE over transmission, limiting the president’s power to overturn their decisions.
“We need a cross-border permitting process that supports investment and infrastructure — one that can’t be undone by the stroke of a pen,” Fedorchak said. “North Dakota has long worked with Canada to develop and transport reliable energy, and this bill strengthens that partnership while ensuring the U.S. remains a leader in energy production. This legislation gives energy producers the green light to move forward with certainty and will help us deliver reliable, affordable energy to American families, farmers and businesses who depend on it every day.”
The bill would allow pipeline developers to speed up their review process before all federal agencies by notifying FERC in their application and paying the U.S. Treasury the lesser of $10 million or 1% of the total project cost. The approvals would have to be completed within a year, with agencies able to ask FERC for an additional six months “if the commission receives consent from the relevant applicant.”
Developers of LNG export and import facilities would have to pay $1 million in a fee collected by the Secretary of Energy, who then would be required to find the application in the public intertest.
Other language in the bill would clear up a longstanding issue, giving FERC jurisdiction over interstate pipelines meant to carry carbon dioxide and hydrogen.
The bill also would limit who can sue for judicial review of natural gas permits, the NRDC said in a statement.
“While it slashes much-needed support for clean energy and climate resilience, it would allow fossil fuel companies to pay to get their project approved,” NRDC Chief Policy Advocacy Officer Alexandra Adams said in a statement. “That’s not just wrong; it’s un-American. Congress should reject this radical bill that would harm the health and welfare of the American people.”
Colorado Gov. Jared Polis signed a bill May 9 that proponents say will streamline the building of new transmission lines within state highway rights-of-way.
House Bill 25-1292 lays out a series of steps for a transmission developer and the Colorado Department of Transportation to take if the two agree that a state highway right-of-way may be a suitable site for a new transmission line.
“By building in existing rights-of-way, transmission developers in Colorado can avoid the kind of political and legal pushback that slows projects down,” said Randy Satterfield, executive director of NextGen Highways. The group promotes the use of existing rights-of-way such as highways as corridors for electric and communications infrastructure.
The bill aims to “open channels of communication that will allow for more coordinated and efficient planning between transportation officials and utilities,” NextGen Highways said in a release.
Renewable energy industry group Advanced Energy United said HB 25-1292 would facilitate coordination among utilities, state agencies and transmission developers looking to build in highway rights-of-way, “enabling faster, cost-effective solutions that will support Colorado’s clean energy goals.”
And the text of the bill notes that building transmission lines in highway rights-of-way potentially could reduce impacts on wildlife and habitat, compared to building across undeveloped areas.
“This will accelerate project timelines while reducing disruption to communities and the environment,” bill co-sponsor Rep. Junie Joseph (D) said in a statement after the House passed the bill. “By establishing a clear and responsible permitting process, we’re supporting a safer, more sustainable transition to clean energy.”
Other bill sponsors include Rep. Andrew Boesenecker (D) and Sen. Faith Winter (D).
Multistep Process
HB 25-1292 applies to transmission developers including private parties, the Colorado Electric Transmission Authority (CETA), utilities, and generation and transmission cooperatives.
Upon the request of a transmission developer, the DOT must provide its best available information on future state highway projects that could have an impact on transmission line placement.
If the DOT and the developer agree a site seems suitable for a transmission line, the DOT will develop a pre-construction plan review schedule. A developer that meets pre-construction requirements would submit a constructability, access and maintenance report. The report must include strategies for mitigating impacts on wildlife, habitat and communities, including disadvantaged communities, along with a community engagement process.
The developer also must post project information, including the route selection process, on a publicly accessible website.
The bill also contains provisions for a developer to compensate the DOT for use of the highway right-of-way. Options include a $600/mile surcharge each year of a 20-year term or a $12,000 lump sum payment. DOT may adjust the surcharge according to inflation. Access can be renewed at the end of the 20-year term.
Another compensation option is an in-kind infrastructure exchange in a public-private agreement.
The DOT will conduct rulemaking related to transmission lines in highway rights-of-way.
CETA Partnership
NextGen Highways and CETA worked together to launch an effort last year called NextGen Highways Colorado.
The coalition represents energy, transportation electrification, business, environmental and wildlife interests. It provided input on HB 25-1292, which also is known as the NextGen Highways bill.
The effort comes as CETA has identified the need for up to $4 billion in transmission investment to ensure that the state’s power grid can keep up with demand.
“Co-location of transmission in existing rights-of-way is an important tool that will assist the Colorado Electric Transmission Authority with avoiding property rights conflicts and building needed infrastructure,” CETA Executive Director Maury Galbraith said in a statement.
OMAHA, Neb. — As expected, SPP’s Board of Directors has approved a tariff change that creates a one-time study outside the grid operator’s normal planning process over the concerns of independent power producers.
During its quarterly meeting May 6, the board added its endorsement of a revision request (RR668) already approved by state regulators (the Regional State Committee) and stakeholders (the Markets and Operations Policy Committee and several working groups). The expedited resource adequacy study (ERAS) is designed to help load-responsible entities meet their RA requirements that are under pressure from large loads that have increased demand and SPP’s backlogged generator interconnection queue. (See New ERAS for SPP: Stakeholders Approve RA Studies.)
“SPP is committed to evolving its processes to better serve our members,” SPP CEO Lanny Nickell said in a statement. “ERAS is one part of that evolution — an innovative solution that will mitigate acute reliability risks without disrupting SPP’s other processes or ongoing [generator-interconnection] queue reforms — and it comes just in time to meet the reliability needs of a quickly changing grid.”
Transmission-owning members welcomed ERAS’ approval. Environmental groups and IPPs did not, arguing that the study amounts to queue jumping, bypasses open access to the RTO and fails to treat all customers in an equitable manner.
“It will help those of us responsible for keeping the lights on,” said Oklahoma Municipal Power Authority’s (OMPA) Dave Osburn.
“This is an affront to open access and a major and significant problem for those exploring whether or not to invest in SPP,” the Advanced Power Alliance’s (APA) Steve Gaw said.
Brett White, senior vice president of regulatory and government affairs for Pine Gate Renewables, agreed ERAS places open access under threat. He said “undue discrimination” is being applied to interconnection customers who have invested in the current process.
“We as an IPP and our fellow IPPs will be harmed by ERAS, in several ways that are worth mentioning again,” White said. “The lack of coordination between ERAS and the normal [study] process will create unanticipated curtailment and overloads on the system that will harm both groups of projects until additional upgrades are built. This is why we don’t study two clusters in parallel.”
White cast doubt on SPP’s promise that ERAS will be a one-time proposal, saying the RTO has proposed to use the same process in the RTO Western region on a recurring basis.
“This does not reflect the supposed ‘emergency’ nature of this proposal and affirms concerns that ERAS is simply the beginning of a process to chip away at principles of open access,” he said.
The Members Committee’s advisory vote for the board passed 17-5, with one abstention. The APA, Pine Gate, Natural Resources Defense Council, EDP Renewables and Google all opposed the measure.
SPP said it remains committed to principles of independence, fairness and equity and that its standard processes will continue to ensure interconnection requests are studied fairly and efficiently. It said the proposal is necessary to respond to an “imminent and growing need” by adding more generation before the region’s capacity is drawn down to zero.
Large loads have increased LREs’ load forecasts significantly, SPP said, potentially leaving them short by 17 GW in 2030.
“I think of this region as a one-lane road on the edge of a cliff,” board member Steve Wright said. “We’re too close to the edge right now. The need to bring more generation and transmission online is a crucial component to the region.”
ERAS is available only to generation projects nominated by LREs and that meet clearly defined thresholds related to near-term resource adequacy needs. It also provides a bridge to the longer-term relief expected from the Consolidated Planning Process (CPP), a separate initiative to streamline the complex and time-intensive planning process, SPP said.
“Ultimately, CPP is the answer to these problems of getting generation online faster,” White said. “ERAS will only delay by further complicating planning studies and taking staff away from the crucial work of getting CPP up and running.”
MOPC’s approval included an amendment to extend a resource’s commercial operations date to seven years because of supply chain constraints. However, the RSC took up the proposal without considering the extended timeline.
SPP plans to file the proposal with FERC later in May. Assuming the commission’s approval, staff will notify LREs of the process for submitting ERAS projects as early as August, with interconnect rights being granted as early as April 2026.
The board also ran into pushback from the MC in approving a tariff change (RR665) that establishes “subregions” for the cost allocation of future byway (between 100 and 300 kV) upgrades. The measure decouples SPP’s Schedule 9 (zonal rates) and Schedule 11 (highway/byway) transmission pricing zones and creates 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. (See “Members Pass Last of HITT’s 2019 Recommendations,” SPP MOPC Briefs: April 15-16, 2025.)
Five members opposed the proposal during the MC’s vote: American Electric Power, Oklahoma Gas & Electric, OMPA, City Utilities of Springfield and Omaha Public Power District.
“AEP remains concerned whether or not this zonal approach is going to benefit customers,” said AEP’s Stacey Burbure, who is responsible for transmission business development and joint ventures. She pointed to no votes cast by Oklahoma and Texas regulators during the May 5 RSC meeting.
“We’re concerned this could result in significant litigation,” Burbure said.
Board members approved several other tariff changes and other measures previously endorsed by the RSC and MOPC:
A provisional load process (RR672) that allows transmission customers to add load to the system when they don’t have enough designated resources to cover their 10-year load forecast (including losses). Under the new methodology, upgrade costs will be assigned directly to the customer, with base-plan funding covering the remaining cost. (See “‘Chicken & Egg’ Issue,” New ERAS for SPP: Stakeholders Approve RA Studies.)
A structured cost-allocation method for assigning a portion of the new Consolidated Planning Process’ upgrade costs based on benefits received to generator interconnection customers. The generalized rate for interconnection development contribution (GRID-C) formulas and associated cost-control approach will determine load-based cost-allocation impacts for energy resource interconnection service versus network resource interconnection service. The RSC recommended the board approve the approach to proportionally allocate incremental long-term congestion rights based on the GI GRID contribution to the overall CPP transmission portfolio cost.
An increase to the planning reserve margin for the 2029 seasons (RR664). The summer PRM will go from 16 to 17%, and the 2029/30 winter PRM will go from 36 to 38%.
Nickell Focuses on Members’ Needs
Nickell, making his first president’s report to the board, said his vision of SPP as the best RTO in the country has evolved since the announcement of his selection as CEO in December 2024. (See SPP Names COO Nickell to Replace Sugg as CEO.)
“A lot of our members … instilled in my head that it’s not good enough necessarily to be just the best RTO. What SPP needs to be is what’s best for you, our members and our stakeholders,” he said, directing his comments to state regulators and members. “That has become my slightly modified vision. It’s not just to be the best RTO, but it’s to be the best for those who depend on us in this footprint. Getting there will depend on a strong foundation of culture.”
Nickell said SPP’s stakeholder-driven culture is being challenged by the industry’s rate of change.
“We will need to evolve both as a company and as an organization, to move faster than we are accustomed in order to survive and thrive,” he said. “We know that we’ve got a generational challenge. We know that our risks are increasing because it takes a long time to get new assets and new steel in the ground.”
Nickell called for more visibility in the industry, saying too often the utility business has been happy to stand in the shadows. But that all changed with Winter Storm Uri in 2021, when SPP was forced to shed load for the first time in its history and ERCOT’s grid was minutes away from a complete meltdown, he said.
“It put us in a much more public position, and now our generational challenge simply compels us to be in front of utility leaders, elected officials, regulators and even consumers,” Nickell said. “We have to do a better job of telling our story in order to make the change that needs to be made and to move our industry forward. We’re going to have to be engaged with CEOs across the industry, with executive leadership of our members, and with government officials. We have to understand their needs, and we hope to be able to explain ours and make sure that we’re moving in the right direction and at the right speed.”
Nickell closed by mentioning the release of SPP’s virtual annual report and its annual member value statement indicated the RTO’s membership realized $3.9 billion in savings and benefits, up 7.8% from 2023 to 2024.
Cupparo Issues ‘Executive Order’
Board Chair John Cupparo closed the meeting with one of his self-admitted monologues and called on staff to outline a draft proposal that will help integrate large loads with the “appropriate acknowledgement of risks and costs” and bring it to the August board meeting.
“This one’s getting heightened national attention. It also has implications on generation and interconnections beyond issues addressed in ERAS,” he said. “This board is willing to push the boundaries on speed and make decisions that may not achieve total consensus in order to meet our mission, to preserve the sustainability of our model and to continue to provide the value consumers in the region have become accustomed to receiving.”
Cupparo asked that the proposal be drafted with the “requisite stakeholder engagement.” He included states and other national regions in the engagement that will be necessary in “pushing the boundaries.”
“We believe it’s important, though, that we drive a stake in the ground in terms of moving these initiatives forward, given we’ve got a window to respond. In my mind, the reality is we’re going to need to go faster as we make additional decisions to meet our generational challenge,” he said.
“Thank you for your executive order, I appreciate that,” Nickell responded. Alluding to his frequent call for “the need for speed,” he pointed out it took 18 months for SPP to approve a competitive project recommended in 2023.
“That’s not speed, folks. We’ve got to get faster,” he said.
Limits for Working Group Chairs
By approving the consent agenda, the board accepted the Corporate Governance Committee’s recommendation to limit working group chairs to three consecutive, full two-year terms as part of its “adaptive governance effort.” The committee said term limits were necessary to ensure balanced representation of various sectors and member organizations across the working groups, given the chairs’ active role in determining the groups’ representation.
The CGC also recommended incumbent Mark Ahlstrom, with NextEra Energy Resources, chair the Future Grid Strategy Advisory Group and Western Area Power Administration’s Brianna Haug chair the Modeling Development Advisory Group. Haug previously served as the group’s vice chair.
The consent agenda also included MOPC’s endorsement of eight transmission upgrades with estimated in-service dates (ISDs) 90 days past their first-reported ISD, and staff’s recommendation to approve four out-of-cycle evaluations for projects issued out of the 2019, 2021, 2022 and 2024 ITP assessments.
Staff said the projects are base-plan funding and any cost changes will be reflected regionally.
Nickell, who chairs the CGC, said the committee has renominated Bronwen Bastone, Ray Hepper and Steve Wright for additional three-year terms as independent directors. It will be Bastone’s third year and the second for Hepper and Wright. SPP’s membership will vote on the nominations during its annual meeting in November.
