Too many state pension funds are failing to take adequate steps to address climate-related financial risk, said a report released Feb. 10 by the Sierra Club and “Stand.earth.”
The Hidden Risk in State Pensions examined 32 of the largest public pension funds representing $3.8 trillion in assets under management and graded some of them well on climate issues but found that most were not adequately addressing climate change.
Pensions are a key source of capital for asset managers like BlackRock and Brookfield Asset Management, which have invested their money heavily in the power industry through stock purchases and direct infrastructure investments.
“As investors on the longest-term horizons, pensions must read the writing that’s been on the wall for decades: live up to their fiduciary duty, and protect pensioners and climate alike through updated proxy voting guidelines, and voting in line with climate and human rights,” Stand’s Associate Director of Climate Finance Amy Gray said in a statement. “It is disappointing to see so many funds not accessing such a powerful strategy to defend climate and the working-class communities they serve.”
The pension funds were evaluated based on their proxy voting guidelines, which signal investor priorities on corporate governance and direct how a shareholder votes, and proxy voting records in 2024. The votes came from various sectors including financial institutions, automakers, utilities, industry and the consumer sector.
Only one pension got an “A” grade on guidelines — the New York State Common Retirement Fund — while an additional seven from California, Connecticut, Massachusetts, New York and Vermont received “B” grades. Two thirds of the funds analyzed got a “D” or an “F.”
As for actual voting records, eight funds scored an “A,” and they were based in California, Massachusetts, New Jersey, New York, Ohio and Oregon. Pensions in Connecticut and Los Angeles County got “B” grades, while the State of Wisconsin Investment Board and the Washington State Investment Board got “C” grades.
Some of the funds have begun voting for climate-friendly policies, with two issuing new guidelines in 2024 to cover biodiversity, director accountability on climate and human rights.
“While this progress is noteworthy, all the pensions highlighted in this report could do more to shield their beneficiaries from growing climate- and environment-related financial risks,” the report said.
Many pensions might underestimate the financial risks posed by climate change as they rely on models the report criticized as significantly flawed. One study in 2024 estimated that equity valuations could plunge 40 to 50% if emissions are not addressed, which would affect public sector workers’ ability to retire with economic security.
“Pension funds are universal owners, meaning that they have highly diversified and long-term portfolios that are representative of global capital markets,” the report said. “The performance of diversified long-term portfolios is largely driven by the overall growth and stability of the global economy, more so than the fluctuations in the value of various companies and sectors.”
Pensions hold shares for the long term because they need to ensure payments for retirees for decades.
“Only by taking an approach that seeks to mitigate systemic risks and risks to their overall portfolios can long-term and diversified investors, such as pensions, best preserve the value of their investments,” the report said.
Exercising shareholder rights by voting at annual corporate meetings is a way pension funds can influence actions.
“Institutional investors, such as pensions, hold a large number of corporate shares, granting them disproportionate influence over corporate behavior,” the paper said. “This means that how pensions vote on who sits on a company’s boards of directors or on shareholder proposals asking companies to decarbonize will be influential in determining whether or not the world will rein in catastrophic climate and ecological crises.”
Eight pensions in the report operate in states with “anti-ESG” (environment, social and governance) investing principles: Arizona, Florida, Indiana, Missouri, North Carolina, Tennessee, Texas and Virginia. They scored lower than their peers and had fewer guidelines than their counterparts.
While the funds in anti-ESG states scored lower, the report noted that many funds without legal barriers have “minimally better guidelines,” and the non-participation of those two groups limits the effectiveness of shareholder engagement on climate.
PJM’s Market Implementation Committee narrowly endorsed a PJM proposal to use effective load-carrying capability (ELCC) to model the availability of demand response resources in all hours, along with other changes to how DR accreditation is determined.
The package received 77% support for implementation in the 2027/28 delivery year, which shrunk to 54.3% for implementation in the preceding year, while a third proposal from the Independent Market Monitor received 40.1% support. (See “Discussions Continue on Demand Response Availability Window,” PJM MIC Briefs: Jan. 8, 2025.)
PJM’s Pat Bruno said the proposal seeks to capture more of the reduction capability DR can provide and apply performance requirements to those hours. Modeling of curtailment capability currently is limited to 6 a.m.-9 p.m. in the winter and 10 a.m.-10 p.m. in the summer, which DR providers argue fails to account for the growth of consumers with flat load profiles and how the DR resources interact overall with reliability risks occurring during a larger number of winter hours.
Calpine’s David “Scarp” Scarpignato said the proposal would be cutting it too close to the auction.
“Even if it looks like it’s financially better for us, the disruption is too much. … It’s not that we oppose the proposal; it’s just that there’s a reason there’s pre-auction schedules,” he said.
Representing DR providers, Bruce Campbell of Campbell Energy Advisors said while he’s sensitive to concerns about uncertainty, the current setup represents a barrier to entry for DR that is excluding resources at a time when PJM says new entry is needed.
The proposal also would revise how DR resources’ winter peak load (WPL) is determined to be measured fleetwide at a point that aligns capability with identified system risks, in this case the hour ending at 9 a.m. The status quo allows the WPL for individual resources to be measured at their highest output whatever time of day that may be, which Bruno said can result in a fleetwide WPL that never can be achieved.
When modeling reliability risks under the ELCC framework, the proposal also would create a classwide load profile for DR capability in winter and derate the amount of curtailment expected by hour. Bruno said no change to summer modeling is needed, since reliability risks tend to be concentrated in a few hours correlated with peak loads, whereas winter risk is more diffused.
Given the short amount of time between the beginning of pre-auction activities for the 2026/27 Base Residual Auction (BRA) and the significant number of market design changes pending at FERC, several stakeholders said PJM instead should target the 2027/28 delivery year, scheduled to be conducted in December. Curtailment service providers countered that some locational deliverability areas (LDAs) cleared short of the reliability requirement in the 2025/26 BRA and there are concerns that could widen in the 2026/27 auction. Expanding the amount of DR considered available could add several gigawatts to the market, they said.
Bruno said PJM intends to seek same-day endorsement during the Feb. 20 meeting of the Markets and Reliability Committee to allow for the package to be implemented for the 2026/27 delivery year, if stakeholders endorse that alternative.
The Monitor’s package would base accreditation on historical performance of DR resources akin to how generation is modeled and rated. It also would use ongoing analysis of load data to determine resource WPL and aim to account for the possibility that load may exceed WPL at the time that a performance assessment interval (PAI) is initiated. A separate stakeholder process would be initiated to consider the role DR plays in the capacity market overall.
PJM Discusses Market Performance During January Winter Storms
Stakeholders said PJM’s markets and operations teams performed well in maintaining reliability during two cold snaps seen in January, but more work is needed to ensure that needs during emergency conditions are reflected in economics. (See “Performance Strong During Record Winter Peak,” PJM MRC/MC Briefs: Jan. 23, 2025.)
Senior Dispatch Manager Kevin Hatch said forecasts showed significant increases in load as cold weather began Jan. 18, with Jan. 22 setting a new winter peak of 145,060 MW. PJM initiated several emergency procedures ahead of the storms, including the use of conservative operations to commit resources — mainly gas generators — thought to be at risk of underperforming. The RTO added conservative operations to its toolbelt after December 2022’s Winter Storm Elliott, when significant amounts of gas generation failed to perform. Gas operators have sought to lay the blame on how PJM dispatches units and have largely supported the ability to make out-of-market commitments.
PJM principal fuel supply strategist Brian Fitzpatrick said last month’s Martin Luther King Jr. Day weekend proved to be challenging because of warm weather Friday, Jan. 17, that shifted to a winter storm with subzero temperatures in some regions. Ensuring the availability of gas resources is especially challenging on such weekends since fuel delivery on pipelines tends to be sold in ratable take packages, which can cause generation owners to lose money if gas providers don’t follow through on procurement contracts.
Constellation Director of Wholesale Market Development Adrien Ford said PJM’s conservative operations declaration resulted in significant uplift payments to generators, creating unhedgeable costs for load-serving entities. PJM’s response to the storm was successful from a reliability perspective, but not economically, she said.
PJM Senior Director of Market Design Rebecca Carroll said the Reserve Certainty Senior Task Force (RCSTF) is trying to address the fact PJM does not have an in-market way of committing resources under those circumstances.
First Read on Black Start Compensation Proposals
PJM and the Monitor presented first reads on competing proposals to revise how black start units are compensated under the Base Formula Rate (BFR). (See “PJM Presents Changes to Black Start Compensation,” PJM MIC Briefs: Jan. 8, 2025.)
The PJM proposal would remove the net cost of new entry (CONE) component of the BFR calculation to instead use a fixed value derived from the average net CONE between 2020 and 2024 with an inflation escalator. The change was spurred by analysis finding that net CONE could fall to zero in some LDAs in the 2026/27 BRA under the shift to a combined cycle reference resource. While PJM has asked FERC to allow it to revert the reference resource back to a dual-fuel combustion turbine, PJM has argued net CONE values could remain low and impact black start compensation.
The BFR is used to compensate black start units that do not require new capital investments to provide black start service, whereas the Capital Recovery Rate (CRR) is used when upgrades are required. PJM’s Glen Boyle said many resources already providing the service could pull their capability if low net CONE values reduce compensation under the BFR. Requiring new resources to make costly upgrades to provide black start service, such as installing diesel generators, could drive up costs he said.
Monitor Joe Bowring’s proposal would temporarily pay black start units an RTO-wide net CONE value while stakeholders embark on a long-term effort to untie the BFR from net CONE entirely to instead focus on the ongoing cost to provide the service.
Bowring has said PJM has acknowledged that net CONE does not relate to black start costs; however, it proposes to arbitrarily create a static value derived from net CONE with an inflation modifier to be the basis of revenues. Rather than changing the rule in an “arbitrary and [illogical] fashion,” he said PJM should let market sellers tell PJM their cost so it can ensure they are compensated with a fair return.
Issue Charge Seeks to Address Offer Capping Advance Commitments
PJM presented a problem statement and issue charge focused on the potential for market power and manipulation when resources are scheduled in advance of the day-ahead energy market.
Key work activities (KWAs) include education on how resources are scheduled ahead of the day-ahead market; governing document revisions related to how those units are scheduled; possible market power mitigation protections; and aligning how the process is detailed across the governing documents.
Two phases are envisioned: the first drafting a proposal on how to select which schedule should be committed in advance of the DA market, and the second focusing on incorporating fuel costs in cost-based offers. Day-ahead and real-time offer capping would be out of the issue charge’s scope.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said he finds it troubling PJM has implemented processes detailed in the manuals that are not appropriately defined in the governing documents and is attempting to codify them after the fact. He said the wording of the problem statement also gives the impression there have been specific accusations of market power abuse.
Other Committee Business
The MIC endorsed by acclamation a second slate of manual revisions conforming to FERC’s order granting PJM’s changes to risk modeling, accreditation and resource testing. The proposed revisions to Manuals 11, 14D, 18 and 28 would rewrite the rules for testing resource capability in summer and winter and operational testing, and also require that dual-fuel generators offer schedules with both fuels into the energy market.
PJM’s Joseph Tutino presented revisions to Manual 11 drafted through the document’s periodic review. The changes include grammatical and spelling corrections, updating web links and removing outdated references to the day-ahead scheduling reserve.
Resource Performance Improves During January Winter Storms
VALLEY FORGE, Pa. — PJMcredited emergency procedures with improving generator performance during a pair of winter storms in January, including a new all-time winter peak of 145,060 MW on Jan. 22.
Executive Director of System Operations Dave Souder told the Operating Committee on Feb. 6 that PJM identified as much as 42,687 MW of generation at risk of not being able to perform during the extreme cold days because of a combination of potential start-up and operational issues.
Emergency procedures such as conservative operations allowed dispatchers to schedule units in advance to ensure they were running when cold weather began and to avoid cycling those units on and off if they might have trouble restarting. The conservative operations emergency procedure was established following December 2022’s Winter Storm Elliott.
Tests also were scheduled a week in advance of the storms, with about 20% of tested units running into mechanical issues that largely were able to be resolved before the storms began.
The forced outage rate peaked at 9.24% on Jan. 22, with 16,857 MW offline because of lacking gas for fuel, equipment failures, freezing temperatures and other causes. The forced outage rate during Elliott was 24%, and it was 22% during the 2014 polar vortex.
Souder said PJM continues to refine the risks that are incorporated into its determination of what resources are considered at risk ahead of periods of high system strain. Part of that is the cold weather operating limits created after Elliott, which allow generation owners to report conditions that could impede resource performance.
Senior Vice President of Operations Mike Bryson said generation owners also were more diligent about reporting operating restrictions on their units, giving dispatchers more insight into the status of the fleet and what units were most likely to be available. Generation owners also were forthcoming about how they procure fuel and how their strategies could interact with PJM dispatch instructions. As stakeholders consider changes to the intersection between the electric and gas sectors, Bryson recommended avoiding one-size-fits-all approaches that would not recognize those differences.
“We have probably 40 different flavors, so what was important was for each [generation owner] to tell us what their strategy was,” he said.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said the performance data show the idea that gas generation struggles to meet its obligations during winter storms is untrue. He argued that if gas resources had been provided advanced commitments as they had in January, their performance would have been significantly better. He said this raises questions about how gas should be modeled in PJM’s effective load-carrying capability risk modeling and accreditation framework if a significant amount of the class’ risk comes from how it is committed.
Generation forced outage rates during a January winter storm | PJM
“Now that we understand everything, why is gas being punished” for how it was dispatched under a different set of rules? he asked.
Sotkiewicz also said PJM should find a venue where the interactions between market design and dispatcher actions can be discussed. He said the two presentations PJM gave on the storm during the Market Implementation Committee and OC meetings were siloed into each committee’s scope, limiting the ability for stakeholders to have substantive discussion.
“Markets help determine the reliability outcomes … and now we’re separating these two into silos, and I fear we’re going to be losing a lot of details doing that,” he said.
January Operating Metrics
PJM saw an average hourly forecast error rate of 1.67% during January, with two days exceeding the RTO’s 3% peak error benchmark, Marcus Smith, lead engineer for markets coordination, told the OC.
Smith attributed a 3.54% peak load overforecast on Jan. 20 to the impact of the Martin Luther King Jr. Day holiday weekend, and a 3.67% overforecast of the Jan. 28 peak to temperatures being significantly higher than expected.
Winter storms led to several emergency procedures and alerts being declared, including a conservation alert, maximum generation alert, spin event, low voltage alert, six cold weather alerts and six shared reserve events.
The spin event was initiated Jan. 21 at 12:20 a.m. and lasted four minutes and 40 seconds, with 694 MW of generation and 40 MW of demand response being committed. Performance for generation resources was 160% and 139% for DR.
Other Committee Business
Stakeholders endorsed by acclamation revisions to Manual 40: Training and Certification Requirements drafted through the document’s periodic review. The changes include updating references to PJM departments and clarifying that member training liaisons should respond to RTO-initiated data verification requests.
The committee also endorsed by acclamation revisions to Manual 14-D: Generation Operational Requirements conforming to FERC’s order accepting PJM’s generation operational testing requirements (ER24-99). The testing is one component of a larger proposal that came out of the Critical Issue Fast Path process the RTO conducted in 2023.
The revisions allow PJM to initiate two tests each in the summer and winter with the aim of validating that resources are able to operate as needed for reliability. If a resource fails a test, it can be required to undergo a retest, which, if also failed, would subject the unit to a daily generation capacity resource operational test failure charge.
Finally, the OC endorsed by acclamation a proposal to sunset the Data Management Subcommittee and shift its work to a new Modeling Users Forum. PJM’s Jeff Schmitt said the change would allow for a focus on long-term goals and initiatives.
ERCOT CEO Pablo Vegas says the grid operator’s proposal to build more than $30 billion of extra-high-voltage transmission infrastructure is part of a “new era in planning” and just an incremental step from its normal practices.
Speaking in front of the ISO’s Board of Directors Feb. 4, Vegas said the $33.9 billion and $32.6 billion estimates for 765-kV and 345-kV backbones, respectively, “effectively” amount to about $5 billion a year.
“Last year, we approved almost $3.8 billion of transmission costs, so it’s a little bit of a step up from what we’re doing,” he said, “but it’s not a radical step up from what we are already used to developing and building here in the ERCOT grid.”
Vegas said the massive buildout, which includes ERCOT’s first foray into 765-kV infrastructure, is necessary to add generation to a grid that is maxed out. The two plans are intended to address industrial and electrification load growth in West Texas’ oil-rich Permian Basin. (See 765-kV Lines in West Texas Inch Closer to Reality.)
“We see that the current system that we’re operating is really getting close to its full utilization capacity,” he said. “Not only do we see the load growth being very significant, but we have seen the rapid increase in supply … significant growth in solar, significant growth in batteries recently on the grid. That requires transmission to carry that supply and then to the grid.”
Vegas said the increase in generic transmission constraints (GTCs), which are used to monitor and control flows using market-based mechanisms to maintain stability and other non-thermal reliability limits, is “evidence” of the grid’s full use.
“[GTCs] have grown over the last several years,” he said.
ERCOT says its Texas 765-kV Strategic Transmission Expansion Plan will require 1,443 fewer miles of transmission and provide $229 million in annual consumer energy cost savings and $28 million more a year in production cost savings. The EHV lines will increase power transfer capability by 600 MW to 3,000 MW and reduce annual energy losses by 560 GWh.
The Texas Public Utility Commission last year approved ERCOT’s Permian Basin plan, which includes both the 765-kV and 345-kV plans. The PUC has said it will decide between the two plans and their import paths into the Permian by May 1. (See Texas PUC Approves Permian Reliability Plan.)
ERCOT also has filed with the PUC a regional transmission plan.
“765-kV systems have been around for decades, have been used throughout the United States for decades and in other parts of the world,” Vegas said. “There is a robust experience set in the engineering procurement and construction world, as well as a robust supply chain globally to support the infrastructure that’s needed to develop 765. That is something Texas could benefit from when we looked at the comparison for the broader regional transmission plan.”
SPP earlier in February also approved its first 765-kV project in its history, a $1.69 billion, 293-mile circuit in Southwestern Public Service Co.’s Texas and New Mexico service territory. (See related story, SPP Board Approves 8 Urgent Short-term Projects.)
Staff Still Looking at Braunig
ERCOT General Counsel Chad Seely told the board that staff still is working to execute a reliability-must-run contract with San Antonio municipality CPS Energy for one of three aging gas plants slated for retirement this year, even as its costs continue to rise.
Seely said CPS’s original estimated budget for Braunig Unit 3 has risen from $82 million to $93 million due to inspection outage, equipment and compliance costs. (CPS submitted an additional $1.5 million budget increase Feb. 3 as it “fine-tunes” overall labor costs.) The all-in costs, which include an incentive factor and fuel expenses, have gone from $90 million to $105 million.
“Our analysis still shows that it is cost-effective to move forward with Unit 3 relative to the overall value of lost load from a system-wide perspective if we had to end up in a load-shed situation,” Seely said.
ERCOT is close to executing an RMR contract with CPS in advance of the inspection outage, scheduled to begin in early March, Seely said. Discussions are ongoing over two addendums addressing CPS’ environmental emissions exceedances and communications and work approvals during the RMR contract’s term. That will start the clock ticking on a 90-day exit plan for Unit 3; staff plan to present the plan to directors during their April 8 meeting.
Costs for the smaller Braunig units 1 and 2 also have risen slightly to $54 million as submitted by CPS and $60 million for all-in costs. ERCOT is continuing talks with CPS, CenterPoint Energy and LifeCycle Power about using mobile generators as an alternative to RMRs for the other two Braunig units. Units 1 and 2 have a combined maximum summer rating of 392 MW, while Unit 3 has a 412-MW summer rating.
Seely said ERCOT still believes the LifeCycle mobile generators are the most “cost-effective reliability solution” for Units 1 and 2. He said CenterPoint has indicated it is willing to release the generators to CPS for two years. The Houston utility leased the 15 32-MW generators from LifeCycle for $800 million over eight years.
LifeCycle has estimated it will cost $26 million to move the generators to San Antonio, while CPS has projected costs of $27 million to connect the units to substations. ERCOT says the cost estimates are subject to change as discussions continue.
“This whole thing is so wasteful,” Stoic Energy principal Doug Lewin said as he followed the meeting on Substack. “Perhaps [Elon Musk’s Department of Government Efficiency] can look into ERCOT,” he cracked.
The grid operator has scheduled a special meeting Feb. 25 to discuss the alternative proposal with the board.
CPS told ERCOT last year it planned to retire the Braunig units, which date to the 1960s, in March. However, the grid operator said the plant’s units were needed to address transmission constraints and congestion in the San Antonio area. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)
3 Tx Projects Endorsed
The board approved three Tier 1 reliability projects — those with capital costs over $100 million — previously endorsed by the ISO’s Reliability and Markets Committee (R&M) during its Feb. 3 meeting and the Technical Advisory Committee. The projects, located east and south of Dallas, were submitted by Oncor Electric Delivery and have a combined cost of $380.6 million:
$103.5 million rebuild of a 345/138-kV switch in Forney.
$118.9 million reconstruction of 76 miles of 345-kV lines south of Dallas.
$158.2 rebuild of 40 miles of 138kV- and 69-kV lines and two 345/138-kV transformers south of Dallas.
The directors also approved R&M’s recommendation to add ERCOT’s COO (currently Woody Rickerson) as one of the delegates responsible for monitoring and reporting the market’s credit risk to the board, and the ISO’s annual methodologies for determining minimum ancillary services in 2025. The methodology limits the amount of a resource’s responsive reserve service using primary frequency response to 157 MW.
Board Approves 17 Revision Changes
The directors unanimously approved 11 nodal protocol revision requests (NPRRs), two changes each to the Nodal Operation Guide (NOGRRs) and Planning Guide (PGRRs) and single other binding document (OBDRR) and system change requests (SCR) on their consent agenda:
NPRR1246, NOGRR268, OBDRR052, PGRR118: Inserts terminology associated with energy storage resources (ESRs) in the appropriate places throughout the protocols, aligning provisions and requirements for ESRs with those already in place for generation resources and controllable load resources. This NPRR applies to ESRs in the future single-model era and should be implemented simultaneously with NPRR1014 (BESTF-4 Energy Storage Resource Single Model).
NPRR1243: Revises requirements regarding notice and disclosure of protected information and ERCOT Critical Energy Infrastructure Information (ECEII).
NPRR1250: Updates the protocols to comply with state law retiring the renewable portfolio standard program (ERCOT will continue to administer a voluntary renewable energy credit trading program).
NPRR1251: Implements several improvements to the firm fuel supply service’s (FFSS) cost recovery process by clarifying qualified scheduling entities representing FFSS resources are able to accelerate restocking reserved fuel using existing fuel inventories or based on new purchases.
NPRR1252: Permits ERCOT to provide ECEII or protected information materials to vendors or prospective vendors without a pre-notice of the provision to a market participant’s vendor or prospective vendor, if they have executed an appropriate confidentiality agreement. The NPRR adds a definition of “ERCOT research and innovation” (R&I) and “ERCOT R&I partner” to clarify notice requirements prior to those entities receiving protected information from ERCOT.
NPRR1253: Includes wholesale storage load charging-load to the dataset ERCOT provides through its inter-control center communications protocol.
NPRR1257, NOGRR271: Establishes a maximum limit on the amount of responsive reserve that a resource can provide using primary frequency response. Proposes an initial static limit of 157 MW, intended to be reevaluated annually as part of the ancillary services methodology review and approval process.
NPRR1258: Removes protocol language duplicative of requirements that are detailed in Management Activities for the ERCOT System and provides model update requirements designed to ensure network data is in common information model format and uses the required naming convention.
NPRR1259: Clarifies that retail transaction response timing requirements will not include the duration of a planned and approved ERCOT retail system outage.
NPRR1260: Reinstates requirements applicable to controllable load resources that inadvertently were removed during the approval and implementation of NPRR863 (Creation of ERCOT Contingency Reserve Service and Revisions to Responsive Reserve).
NPRR1261: Removes references to TAC-approved congestion revenue right (CRR) transaction limits and per-CRR account holder transaction limits, replacing the existing limits with a framework specific to each auction to maximize market bidding and liquidity while minimizing the risk of performance issues and/or triggering a transaction adjustment period.
PGRR117: Revises the Planning Guide to reflect the PUC’s rulemaking on certification criteria, which requires the ISO to conduct a biennial assessment of the ERCOT grid’s reliability and resiliency in extreme weather scenarios and recommend transmission projects to address the assessment’s resiliency issues.
SCR828: Increases the number of resource certificates permitted for email domains within the Resource Integration and Ongoing Operations system.
PJM Presents Preliminary Congestion in 2024/25 Base Case
PJM’s Nick Dumitriu presented the Transmission Expansion Advisory Committee with the preliminary 2029 congestion results in the 2024/25 Base Case, which previously had been unable to offer a workable solution without the transmission upgrades included in the first window of the 2024 Regional Transmission Expansion Plan (RTEP).
The final base case and congestion drivers are expected to be published in March, with a long-term market efficiency project proposal window open between April and July. The TEAC and PJM Board of Managers may review any project recommendations to come out of that process toward the end of 2025.
The 345-kV Green Acre-P9701 West and Douglas-Francisco lines saw the greatest amount of annual congestion at $164 million and $107 million, respectively. Around 35 lines were identified with congestion exceeding $1 million annually.
RTEP Changes Include Doubling of Tx Costs for Brandon Shores Deactivation
The network upgrades necessary to allow the deactivation of Talen Energy’s Brandon Shores coal-fired generator outside Baltimore have doubled in cost from $738.83 million to more than $1.513 billion, PJM Director of Transmission Planning Sami Abdulsalam said.
Part of the increase came as more detailed engineering studies were conducted and assessments were made on site conditions. Abdulsalam said an example of that can be seen with the plan to build a new Batavia Road substation, which originally was planned to be air-insulated but has been upgraded to a gas-insulated substation due to limited land and wetlands on site.
Quotes received through the conceptual design phase also tended to be lower than those received once competitive bidding opened and constructability reviews were conducted with the aim of improving right of way access and limiting the potential for cost overruns. Abdulsalam said labor costs for construction and engineering have increased since the project was announced.
The cost of transmission upgrades to interconnect New Jersey’s offshore wind projects under the State Agreement Approach has decreased by $8.2 million with the removal of prebuild extension work, such as duct banks, for four high-voltage direct current lines to each of the converter station areas for the generators.
FirstEnergy has canceled the $37.5 million Whippany–Montville 230-kV line included in PJM’s package of transmission upgrades in the first window for the 2025 RTEP, citing “routing and permitting issues.” The upgrade was intended to resolve the potential for two 230-kV circuits in the Montville area to be lost and cause a voltage collapse dropping over 300 MW of load. FirstEnergy informed PJM that an alternative project should be identified and included in the RTEP.
Supplemental Projects
Dominion presented a $110 million project to build a new substation, named Duval, to serve more than 100 MW of residential and commercial load forecast in Chesterfield County. The $30 million substation would be connected to the Midlothian substation with four 230-kV lines for $80 million. The project has an in-service date of Jan. 1, 2028, and is in the engineering phase.
Dominion presented a pair of projects to replace two 230/115/13.2-kV transformer banks at its Landstown facility due to their age and maintenance issues. The projects would cost $9.86 million, with one expected to come online in December 2025 and the second a year later.
Dominion presented a series of projects to build a string of four substations networked between its planned Cirrus, Potato Run and Oak Green substations to serve new data center load in the Culpepper area.
At one end, the $14.3 million, six-breaker ring Palomino substation would be connected to the Cirrus substation with two 230-kV lines for $24.2 million. Palomino would be connected to the $14.3 million Chandler substation with double circuit 230-kV lines for $6.5 million.
The similarly priced McDevitt substation would be connected to Chandler with double circuit 230-kV lines for $5.5 million. The last facility, Mount Pony, would cost $11.6 million and would be connected to McDevitt with double circuit 230-kV lines for $28.2 million. Mount Pony also would connect to both Potato Run and Oak Green with 230-kV lines for $100 million in transmission and $40.8 million in upgrades at the existing sites. Each component has an in-service date in the second quarter of 2028 and is in the conceptual phase.
FirstEnergy presented two projects totaling $14.8 million to replace 230/34.5-kV transformers at its Glen Gardner and Larrabee substations, along with circuit breakers and disconnect switches to address maintenance issues associated with the end of life for the transformers. The Glen Gardner transformer would be installed by May 1, 2025, while the transformer at Larrabee would go in-service on April 12, 2027.
NYISO opened the Installed Capacity Working Group’s meeting Feb. 4 by telling stakeholders it is assessing the impact of President Donald Trump’s 10% tariff on “energy resources from Canada” on its markets.
“NYISO is actively pursuing guidance pertaining to the impact on electricity markets and which Canadian energy resources qualify,” it said in a statement read at the start of the meeting. “We will communicate to all stakeholders as soon as we receive clarification.
“The U.S. and Canada have one of the most integrated electric grids in the world, allowing system operators in both countries to pool resources for improved reliability and economic efficiency. We are in close and regular contact with Hydro-Quebec and Ontario’s Independent Electricity System Operator to ensure a reliable grid and stable flows of electricity across interregional transmission lines.”
In addition to the applicability of the tariff to electricity imports from Canada to New York, NYISO is investigating:
whether the ISO has any responsibility in collecting the tariff;
whether the ISO’s tariff (that is, its filed rate) requires any amendments to fulfill a collection obligation;
software and administrative procedures to effectuate tariffs; and
reliability considerations over the short and long terms.
NYISO spokesperson Andrew Gregory declined to say who or what the ISO is consulting or when it expected answers.
A spokesperson for New York Gov. Kathy Hochul told RTO Insider the governor’s office did not know what the tariff would include, if it proceeded. The New York Department of Public Service said in a statement that it was “closely reviewing the situation.”
Celeste Miller, acting director of media relations for FERC, declined to comment.
FERC Order 904
Amanda Myott, NYISO senior market design specialist, presented an update to the ISO’s compliance filing for FERC Order 904, which prohibits transmission providers from including charges in their rates to compensate generators for reactive power that falls “within the standard power factor range by generating facilities.”
In keeping with the order, NYISO intends to discontinue compensation to voltage support service (VSS) suppliers for reactive power within the standard range.
“NYISO is also proposing to continue compensation for suppliers that offer voltage support outside the standard power factor range, with compensation being based on demonstrated capability using existing VSS testing and payment procedures,” Myott said.
The ISO also proposes to define the standard range of 0.95 leading to 0.95 lagging, which is industry standard.
Suppliers who want to participate will be subject to the same VSS capability testing rules and procedures that exist. The penalty structure for VSS program participants will be retained. Performance failures within the standard range for suppliers who do not participate in the new program will not be subject to penalties but may be reviewed under the tariff for a market violation.
The new VSS program will be integrated into the capacity market through an adder to account for VSS revenues for each peaking plant technology. The adder’s value will be determined formulaically based on the Rate Schedule 2 compensation structure. This will come into effect on May 1 to align with the 2026/27 capability year.
Several stakeholders asked to be allowed to review the tariff revisions necessitated by these changes before NYISO submitted its compliance filing, which is due March 28. The ISO stated they would return to the working group if necessary for more feedback.
While heating electrification in New England is poised to drive a major increase in peak demand, electrifying about 80% of households could reduce the combined cost of the region’s electric and gas systems by 21 to 29%, according to a new study by researchers at the Massachusetts Institute of Technology (MIT).
The researchers emphasized the cost savings associated with retrofitting buildings to improve heating efficiency, noting that building envelope upgrades reduced electricity demand by an average of 16% in high-electrification scenarios and reduced gas demand by about 11%.
They also stressed the importance of coordinated planning between the gas and electric systems to minimize the overall costs.
“Our results highlight the value of integrated power-gas planning in future decarbonized energy systems, particularly in regions like New England where [natural gas] is prevalent as a heating fuel and also currently plays a major role in electricity supply,” the authors wrote. (See New England Gas Generation Hit a Record High in 2024.)
The researchers evaluated five electrification pathways for 2050 across the gas and electric systems. They modeled supply costs and the need for new infrastructure, including transmission and generation, and accounted for the impacts of weather variability and emissions limits aligned with state policies.
Across all scenarios, high electrification coupled with building heating efficiency improvements produced “the lowest combined residential power and gas demand that is up to 28 to 30% lower than values in the year 2020,” the study found.
The model indicated that higher levels of electrification would reduce natural gas consumption and gas system costs, along with demand for expensive low-carbon fuels. While electrification would increase costs for the power system, it would bring significant savings on the gas side, the authors noted.
“This highlights the importance of joint energy system planning and indicates that evaluating the gas or power systems in isolation from each other can lead to misleading results,” they wrote.
To meet the increased demand from residential electrification, the study’s power production model relied heavily on new onshore and offshore wind resources, in part due to their high capacity factor relative to solar resources. The study also found a significant need for dispatchable resources, mirroring the findings of a recent ISO-NE study on deep decarbonization. (See ISO-NE Study Lays Out Challenges of Deep Decarbonization.)
“At 17.7–28 GW, the overall capacity of the fleet of gas power plants is roughly 1 to 57% larger than the existing capacity but makes up only 8.4 to 13.4% of overall generation as compared with 52% for New England in 2022,” the authors noted.
However, the role of natural gas was reduced when methane leaks were factored into the calculations for the emissions constraint. Methane, which is an extremely potent greenhouse gas over short-term periods, is a major source of emissions from natural gas networks.
“Across all scenarios, accounting for methane emissions in the modeled decarbonization target leads to reductions in [natural gas] and increasing use of lower emissions-intensive but expensive [low-carbon fuel], thus increasing the total system cost,” the study found.
The authors found that including methane leaks into the emissions calculations increased the cost benefits of the high-electrification scenarios, which rely the least on natural gas. Accounting for natural gas leaks also increased demand for low-carbon fuels to meet decarbonization requirements.
“A theme of our findings is that a flexible, low-carbon electricity resource and/or low-carbon energy carrier will likely be needed to supply the energy demands of electrification cost-effectively while meeting decarbonization objectives in cold climates,” the authors wrote.
The model allowed for additions of resources reliant on low-carbon fuels or carbon capture and storage. The authors noted that “competing technologies like nuclear-based power generation and long-duration energy storage could also be equally important to consider,” though these technologies were not modeled in the study.
They also acknowledged there is uncertainty around the cost, availability and lifecycle emissions of low-carbon fuels, and similar viability concerns for natural gas generation with carbon capture and storage.
The study, which sheds light on combined costs from the bulk power and gas systems, should not be interpreted as an all-encompassing cost-benefit analysis for heating electrification. It does not compare costs at the distribution level and does not account for the installation costs of end-use equipment or building retrofits.
The authors highlighted the need for more research into commercial sector electrification, demand flexibility and distribution system impacts.
NYISO on Jan. 30 laid out for the Installed Capacity Working Group its proposal to remove operating reserve suppliers that consistently underperform from the market until they pass a requalification test.
“When a resource is identified for review, there will be a rebuttable presumption that the resource’s ability to provide operating reserves will be removed,” said Katherine Zoellmer, NYISO market design specialist. “Removing a resource’s qualification to provide operating reserves should incentivize performance due to a loss of operating reserves revenues during the period of removal.”
Zoellmer said the ISO was exploring the possible timeline of removal and possible requalification. In response to a stakeholder’s question, this would mean that 100% of the resource’s operating reserves would be “in jail” and off the market.
“We want to make sure that the time of removal is long enough that it provides a disincentive,” said Mike Mager, representing Multiple Intervenors. “But it shouldn’t be too long. We want to get resources able to provide operating reserves to the market.”
NYISO first presented the proposal last year, along with financial penalties for resources on the day-ahead schedule that fail to provide electricity as promised in the real-time market. The Business Issues Committee ended up tabling the penalty component but approved moving forward with the removal portion. (See Stakeholders Turn down NYISO Reserve Performance Penalties.)
As currently proposed, NYISO would remove a resource from the market if it failed to perform during reserve pickup (RPU) events or audits and when dispatched in real time. The thresholds for failure have not been finalized. Crossing these thresholds would not cause automatic removal, Zoellmer said, but it would trigger a “holistic performance review.”
“We take a look at the resource’s performance as a whole,” she said. “The goal of this is to remove persistently poor performers.”
Stakeholders emphasized that resources should not be removed for isolated events. One stakeholder suggested splitting the RPU events/audits metric to take into account a failure to not just perform but also to ramp in the time desired.
There was some discussion about whether removing a supplier would cause prices to rise. Mager said the point is that if resources are not providing the electricity they promised, they already are costing consumers money.
“If we remove supply, that could have a price impact in the short run,” said Nathaniel Gilbraith, NYISO manager of energy market design. “The focus of this project is to improve performance and reliability of our operating reserve supplier fleet so in the long run, consumers can benefit from more availability of supply.”
Another stakeholder said it would be helpful if the ISO generated automated notifications for resources that fail to perform on its metrics. Issuing warnings could help mitigate administrative or communications issues between NYISO and its fleet, they said.
The Members Committee was sharply divided on an agreement in principle between PJM and Pennsylvania Gov. Josh Shapiro to institute a cap and floor on capacity prices for the 2026/27 Base Residual Auction (BRA) and the following auction.
The Feb. 7 consultation with the Members Committee allows PJM to move one step closer to filing the agreement at FERC under Federal Power Act Section 205. The MC meeting was followed by a closed-door consultation with the Transmission Owners Agreement Administrative Committee (TOA-AC). (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)
The proposal initially would limit prices to between $175/MW-day and $325/MW-day, values that are tied to the accreditation of a dual-fuel combustion turbine (CT) generator and could change with time.
PJM Executive Vice President Market Services and Strategy Stu Bresler said the agreement would improve confidence in market outcomes as FERC considers several market designs the RTO has filed and complaints about the capacity market — including one from Shapiro’s administration. Without an agreement on the commonwealth’s complaint, he said there could be further delay in the 2026/27 auction schedule, or the results could be subject to refund.
General Counsel Chris O’Hara said Shapiro’s administration has committed to withdrawing its complaint if the agreement is accepted by FERC, which could come in the form of a contingent notice of dismissal. The Pennsylvania complaint seeks to revise the auction price cap to be set at 1.5 times the net cost of new entry (CONE), rather than the greater of gross CONE or 1.75 times net CONE (EL25-46). (See Pennsylvania Seeks Lower PJM Capacity Price Cap in FERC Complaint.)
The agreement is focused on the next two auctions, Bresler said, because of a confluence of circumstances likely to limit the amount of new entry. Those include the short time period between BRAs and the corresponding delivery years under the compressed auction schedule and the backlogged interconnection queue. He said both are temporary as PJM holds a goal of returning to three-year forward auctions and as it works through a transitionary process meant to shorten the timeline for studying new interconnection requests.
“This is proposed as a temporary solution for the next two BRAs … we believe not moving forward with this settlement would have been untenable,” Bresler said.
PJM plans to file the proposal at FERC on Feb. 14. That could be delayed if it determines it would be preferable to see how the commission acts on several other filings first. Vice President of Market Design and Economics Adam Keech said a FERC order on the RTO’s proposal to revert the reference resource to a dual-fuel CT, instead of a combined cycle (CC) generator, would be especially noteworthy. Even if the reference resource change is rejected, Keech said PJM likely would seek to continue basing the proposed price cap and floor on a CT.
Denise Foster Cronin, of the East Kentucky Power Cooperative (EKPC), said PJM’s motivation is to provide short term relief for consumers, but she’s concerned this is a fundamental change in the auction design that will undercut reliability and ultimately lead to much higher prices in the long term, starting as soon as 2028. Infusing additional uncertainty into the market for those who must make investment decisions now will stymie much needed investment in new and existing resources. Additionally, in relying upon generators in Western PJM to supply load centers in Eastern PJM subject to the price cap, she said this proposal effectively requires Western generators to subsidize load to achieve the purported short-term savings.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said the capacity market was created in part to address state rules and standards that could have compromised resource adequacy by creating a stable market design that allows the impact of those policies to be reflected in price signals. Instead of holding to that history, he said PJM has arrived at a settlement drafted without including its membership, which would lead to fewer resources being committed.
“We’re shifting and transforming price risk into reliability risk for political expediency,” he said.
If it moves forward with the agreement, Tom Hoatson, of LS Power, recommended PJM clear the auction normally, publish the clearing price, and then truncate the results to fit within the cap and floor. Doing so would allow investors to have greater insight into the market dynamics, while still meeting PJM’s goals driving the settlement.
“It’s just information that we need to understand to determine how we should invest in these markets,” he said.
Consumer advocates questioned the need for a floor on prices, with Greg Poulos, executive director of the Consumer Advocates of the PJM States, saying that even if the auction cleared at the proposed floor, that would remain one of the highest clearing prices the capacity market historically has seen.
“This is an extremely high floor to incentivize resources in that perspective,” he said.
Ryann Reagan, of the New Jersey Board of Public Utilities, said the BPU takes seriously the resource adequacy concerns PJM has laid out in recent years and the focus on high prices. However, if the price floor does turn out to be relevant it would indicate there’s been a fundamental misreading of market conditions. If that were the case, he said consumers should not be expected to pay higher prices than necessary.
Bresler said PJM has conducted a lot of analysis over the past two years showing supply and demand are tightening in an accelerating manner. To achieve a solution mutually beneficial for market sellers and buyers, it needed to address the legitimate consumer cost concerns and also sustain any new entry possible in PJM over the next two years.
“We feel that it is really important to ensure that we really address both sides of the equation,” he said.
Senior Vice President of Governmental and Member Services Asim Haque said PJM and the Shapiro administration reached an impasse during negotiations on the agreement, leading them to seek input from market sellers. When pressed by stakeholders, he declined to provide more detail on which market participants were included in the discussion other than stating it was a broad swath.
“This was input to our discussions around the concept of investment [and] economics in the marketplace. The easiest way to think about this is we don’t build anything, and the Shapiro administration doesn’t build anything,” he said.
Jackie Roberts, federal policy advisor for the West Virginia Public Service Commission, said she does not believe settlement privilege would extend to entities not party to the agreement who provided insight that informed its terms. She argued the fact that PJM spoke to other suppliers isn’t privileged and the RTO owes it to the members to tell them who it spoke to. She asked that any explanation of why this is not the case be supplied in writing to the Organization of PJM States Inc.
Independent Market Monitor Joe Bowring said he supports the agreement, subject to appropriate implementation, and believes it would be consistent with a competitive market result. The variable resource requirement (VRR) curve always has included maximum prices.
“The argument has been about what that maximum price should be. IMM analysis has shown that PJM’s proposed maximum price of about $600 would result in a wealth transfer from customers to generations of about $8.7 billion per year with no achievable incentive effects,” he told RTO Insider.
He compared the agreement to a recommendation the Monitor has made in its analysis of the 2025/26 BRA results that PJM revise the formula defining the maximum price to be 1.5 times the net CONE, rather than the greater of gross CONE or 1.75 times net CONE, although he said the agreement would result in maximum prices 14% higher than the Monitor’s proposal. Bowring told RTO Insider he’s opposed to minimum prices in the auction design.
“The agreement would set the maximum price on the VRR curve at a level consistent with the capacity market design. The maximum price of $325 is almost three times higher than the weighted average capacity auction price over the history of the capacity market, $116.30,” Bowring said. “PJM’s implementation of the agreement is not consistent with an agreed on maximum price of $325 because PJM converts the price from UCAP to ICAP, making it subject, for no good reason, to changes in ELCC ratings.”
RSC, Directors Approve One-time Study to Meet PRM Requirements
SPP’s Board of Directors has approved a one-time process to quickly add generation so load-responsible entities (LRE) can meet their resource adequacy needs under the grid operator’s planning reserve margin (PRM) requirements.
During its virtual Feb. 4 quarterly meeting, the board endorsed the Resource and Energy Adequacy Leadership Team’s proposal for an expedited resource adequacy study (ERAS) to ease the interconnection of new resources. The process, separate from the RTO’s existing generator interconnection (GI) process and its definitive interconnection system impact study of proposed generation, is designed to address resource adequacy concerns created by increased load projections, generation retirements and the current GI queue backlog.
While cautioning that stakeholders fall on both sides of the recommendation, CEO Barbara Sugg said, “I believe we have to do everything we can to get generation online as quickly as we can and meet our reliability needs, and I think this is a big step toward that.”
“This provides an additional optionality for those trying to meet the additional PRM requirements, so I think this is a positive step forward,” director Stuart Solomon, a former utility CEO, said.
Under the proposal, LREs will be able to select any generation and fuel type, based on their needs, for a special one-time study conducted outside the regular GI study queue. Requests accepted into the study will have priority over all GI requests without signed agreements. The requests must have a commercial operation date within two years.
The Regional State Committee (RSC), which unanimously approved the proposal during its Feb. 3 meeting, also will be required to approve the one-time ERAS.
While LREs generally supported the recommendation, developers said that existing GI requests might suffer financial harm from ERAS projects “jumping the line.” They also expressed concerns about FERC’s acceptance of an eventual tariff change, saying that it appears contrary to longstanding policy.
“We also understand the desire to add more generation, but we really still echo some concerns about the potential harm that this could have on projects in the existing queue and getting to our goals of getting through the backlog,” NextEra Energy Resources’ Jennifer Solomon said. “One of the problems that we see with moving this to FERC is that currently, the proposal is only open to projects that are selected by an LRE. There a number of issues that we will look at as the [tariff revision] develops, but I echo that it’s important that we stay kind of focused on how, if this moves forward, [it does so] in a way that ensures that it’s targeted, that it’s looking at how the [commercial operation dates] are going to be met.”
“We’re in a very unusual time. We have unprecedented load growth. We have these increases in PRMs, but it’s really challenging load-responsible entities,” Oklahoma Municipal Power Authority’s Dave Osburn said. “We’re the entities that are responsible for serving load. What SPP put forward is a bold plan, but this is the time for bold plans.”
The Members Committee approved the measure with its advisory vote, 16-4, with two abstentions. The Advanced Power Alliance, EDP Renewables, the Natural Resources Defense Council and Pine Gate Renewables opposed the proposal.
RA, Congestion-hedging Recs Pass
The board also approved several other recommendations related to resource adequacy and congestion hedging that previously were endorsed by the RSC:
A long-term PRM policy paper outlining the framework for establishing planning horizon PRM requirements and providing LREs with adequate advance notice leading up to the applicable operating seasons. Stakeholders approved a Year 4, Year 7 and Year 10 cadence for the loss-of-load expectation studies and switching the LOLE study from a biennial analysis to annually.
Implementing a 2029 PRM for the summer and winter seasons of 17% and 38%, respectively, based on submitted forecasts for the resource and load mix using the 2023 LOLE study.
Two policies stemming from the Holistic Integrated Tariff Team’s work on congestion hedging. One increases opportunities for all market participants to receive long-term congestion rights (LTCRs) awards and the other coordinates with planning to review firm transmission assumptions used in planning processes. The LTCR proposal allows the netting of flows in their allocation. Eligible participants can nominate up to 50% of each path, with all current awarded LTCR paths over 50% grandfathered. The awarded LTCRs can be held for five years.
SPP staff said the increase in LTCRs would improve their allocation while also maintaining participants’ ability to retain current allocations by grandfathering those rights. That would result in more awards with no entity losing their current positions there, they said.
However, stakeholders pushed back, as they have since firm transmission service customers first asked in 2016 for improvements in determining the amount of auction revenue rights awarded in the annual and monthly ARR allocations. The Market Working Group and Cost Allocation Working Group both voted against the proposals, expressing a desire to wait until the 2025/26 LTCR period to evaluate other changes. Concerns also arose that allowing more LTCRs to be allocated could lead to underfunding issues.
“I think we have a responsibility to think about the public interest, and expanding the size of the pie is a way to create value for customers across the SPP region,” director Steve Wright said. “A 50% increase in LTCRs seems like a very big deal to me. There’s a lot of value that’s created and therefore, a lot of benefit that can flow through to members in the SPP region. I think we have a responsibility to go try and make that happen and continue to work with those who are concerned that their existing rights may be impacted in some way.”
EDP Renewables’ David Mindham was among those protesting the congestion-hedging recommendation over what he said was a lack of equity in allocating LTCRs.
“What we’re saying in SPP right now is the only way you can get value from paying for transmission is if you’re already getting that value, so that discourages new entry into willingly paying for transmission on the SPP system,” he said. “EDP has paid for a lot of transmission service throughout the years. We’re not going to do that anymore. We’re not going to willingly pay for transmission because we weren’t here long enough to derive value from the existing long-term congestion process. We’ve been run out of the market.”
The Members Committee voted against the motion with their advisory ballot, 6-10, with six abstentions.
Nickell, Sugg Share CEO Report
Lanny Nickell, who doesn’t officially take the CEO’s reins at the RTO until April 1, shared his initial thoughts with stakeholders while sharing the president’s report to the board with Sugg.
“I made a commitment to the board to help SPP succeed by placing an emphasis on operational excellence, ambitious strategy and high visibility,” he said. “Those are the three pillars that I believe will allow us to be successful, if built upon a foundation of SPP’s world-class culture and stakeholder experience.” (See Nickell: SPP’s Culture Paves Way for its 2025 Success.)
Nickell listed SPP’s three corporate goals for 2025, down from five the year before:
Continuing to mitigate resource adequacy risks (he sits on the Resource Energy and Adequacy Leadership Team).
Accelerating generator and load interconnection while planning for the load of the future.
Continuing SPP’s Western expansion.
“Just because there’s three and not five doesn’t mean there’s less work,” he said. “These do not represent all the work and initiatives that will be undertaken throughout the year. They just simply represent the objectives that need to be most visible within our member community and within the organization and need a higher degree of focus and attention to ensure successful completion.”
Sugg, who announced her retirement last year, said, “I’ve worked with Lanny for a long time, and I have every confidence that he’s the best choice.
“As I look forward, I’m excited about where SPP is headed,” she added. “There’s no shortage of challenges, but we’ve proven time and time again that we always rise to the challenge. Lanny has got a lot on his plate and very high expectations that he set for himself, never mind the expectations that you all set for him. Certainly, I’m going to be watching SPP from the front row with my pompoms and whatever else I need to cheer on the organization as a whole.”
Ellis Retires, Evergy Exec Hired
Sugg also said Sam Ellis had retired Feb. 3 as vice president of IT after 22 years with SPP. He joined the organization in 2003 from member company Empire District Electric Co.
“It’s particularly noteworthy that I tried to hire Sam, and he rejected my offers prior to 2003, not that I’m holding a grudge against Sam or anything,” Sugg said. “He finally did come to SPP, and he did finally come and work directly for me. Anyway, we’re going to miss Sam, his sense of humor, his love for this company, and for our people.”
Sam Ellis (left), Kevin Bryant | SPP
Ellis received a round of virtual applause from the board and stakeholders.
Nickell tag-teamed Sugg by announcing Kevin Bryant’s hire as the RTO’s first executive vice president of stakeholder affairs and chief strategy officer. Bryant will oversee the development and execution of SPP’s corporate strategy; lead the administration of its stakeholder process; and direct the management of the organization’s relationships and communications with internal and external stakeholders, including member companies and market participants in the Eastern and Western Interconnections.
Bryant comes to SPP after 22 years at Evergy, where he most recently was the company’s COO and its CFO before that. He will join the staff April 1.
RTO Western Expansion Progressing
COO Antoine Lucas said during the quarterly update to stakeholders that while SPP has received tariff approval for Markets+, it also is waiting on FERC’s go-ahead for its Western RTO expansion. The RTO filed a response to the commission’s deficiency filing in November.
“I hope that we will get that approval toward the middle of this month,” he said.
Lucas said in the meantime, staff is working with its vendor to build out the market systems. He said there have been a “few challenges” with software delays, but that staff is working to ensure the RTO expansion meets its April 2026 go-live target.
Casey Cathey, vice president of engineering, said SPP signed 108 generator interconnection agreements for more than 18 GW of capacity in 2024, three times more than the 10-year average for GIAs. He said the RTO expects to execute another 150 GIAs for 6.7 GW this year, when four study clusters are expected to enter negotiations for GI agreements.
The GI backlog effort continues, Cathey said, with clusters through 2022 resolved this year. The 2025 study cluster closes March 1, leaving the 2026 cluster as potentially the first study group under SPP’s consolidated planning process. Staff plans to bring a revision request for stakeholder approval in the second quarter this year and file a tariff change at FERC in the third quarter.
RSC OKs Order 1920 Extension
The RSC unanimously approved staff’s recommendation to request an extension of a six-month engagement period under FERC Order 1920 until Nov. 3.
The order requires transmission operators to produce a 20-year regional transmission plan to identify long-term needs at least every five years. SPP has produced 20-year plans for at least a decade. However, it still is subject to a six-month engagement period to allow state entities to negotiate a cost allocation method and/or a state agreement process.
“It really appears FERC wants to model other regions after what SPP does, and that is to have states involved in cost-allocation decisions provided to transmission upgrades,” SPP General Counsel Paul Suskie told the regulators.
SPP’s engagement period was to end May 5, but several RSC members expressed a desire for an extension. The committee is responsible for determining cost allocation issues, financial transmission rights allocations and the regional resource adequacy approach.
STEP Report Approved
The board’s unanimously approved consent agenda included:
Approval of the 2025 SPP Transmission Expansion Plan report, which indicates 43 transmission upgrades, valued at $161.8 million, have been completed since the 2024 report. Another 290 upgrades were issued notices to construct, valued at $3.2 billion, and 20 upgrades worth $195.4 million were withdrawn.
A revision request (RR650) to develop HVDC planning criteria for SPP’s governing documents.
Endorsement of the Oversight Committee’s recommendation that the 17 members of the 2024 industry expert pool be renewed for 2025 and that five new members be added: former SPP exec Michael Desselle and Carolyn Barbash, Adrienne Bradley, Susan Thomas and Stanley Krause.
Adding an independent director to the 24-person Strategic Planning Committee, giving the board between three and five seats.
