PJM initiated a load-shedding event Aug. 11 in the Baltimore Gas and Electric (BGE) region after the Brandon Shores substation went offline.
A PJM announcement states that the substation “experienced an unplanned disconnection” in the morning, after which transmission capability into the region was limited for much of the day and consumers were asked to conserve energy.
A voltage reduction action was initiated at 2:15 p.m. followed by a load-shed directive at 3:52 p.m. PJM’s emergency procedure page states that the directive was initiated due to an N-5 cascade risk identified on the Chestnut-Fredrick Road 115-kV line in BGE. The load-shed directive lasted 28 minutes, ending at 4:20, while the voltage reduction ended at 5:09.
“While BGE worked to address the transmission outage, electricity demand briefly exceeded the current capacity of the local transmission system as demand peaked in the afternoon. To prevent damage to equipment and the risk of cascading outages across a broader area, at 3:52 p.m. Eastern, PJM directed BGE to lower flows across overloaded lines by reducing electricity load. BGE concurred and implemented its load-reduction plan, resulting in limited outages,” PJM said in a notification to members.
Since the load shed was limited to BGE and did not extend to a full sub-zone, a performance assessment interval (PAI) was not initiated. PJM stated that some versions of its app incorrectly notified users of a PAI trigger.
BGE reported to PJM that transmission equipment that had been “inoperable” for much of the day had been brought back into service after the load-shed directive, allowing the action to be terminated. As of the 6:36 p.m. communication, some equipment still was offline.
“We expect that BGE will soon be returning to service those customers who were shed as part of our original directive. Continued reliable operation of the local transmission system will depend upon the operability of the transmission facilities that tripped this morning, but for now, the system is in a place such that we can serve our peak evening demand in the area,” PJM said.
The most recent load shed PJM had entered occurred on June 15, 2022, when storms damaged multiple transmission lines and put 200,000 customers along three 138-kV lines out of power. Following the December 2022 Winter Storm Elliott, PJM said it was one generation trip away from possibly having to implement a voltage reduction action. (See PJM Orders Load Sheds in AEP Following Storms and PJM Recounts Emergency Conditions, Actions in Elliott Report.)
Limited transmission capability in the Baltimore region contributed to the need for PJM to enter into a reliability-must-run (RMR) agreement with Talen Energy after it requested to deactivate its 1,289-MW Brandon Shores and the adjacent 843-MW H.A. Wagner generators.
Transmission violations identified with those units offline led to several transmission projects being added to the Regional Transmission Expansion Plan and a $180 million annual agreement to keep the two generators online.
Pennsylvania Gov. Josh Shapiro (D) and Virginia Gov. Glenn Youngkin (R) have requested that PJM consider former FERC Commissioners Mark Christie (R) and Allison Clements (D) to fill two vacant seats on the RTO’s Board of Managers.
“Last month, we joined seven of our fellow governors in urging PJM to begin to restore purpose and vision for the organization, independent from the wishes of any particular sector, by tapping nationally respected leaders to fill the two vacant board seats,” the governors wrote in a letter to the RTO on Aug. 11. “That diverse group of governors strongly urged PJM to appoint a bipartisan slate of energy luminaries: recently retired FERC Chairman Mark Christie and former FERC Commissioner Allison Clements.”
Nine governors signed onto a July 16 letter to PJM calling for a process for states to nominate candidates to the board and requesting a meeting with the RTO’s Nominating Committee. Virginia Energy Director Glenn Davis attended the Members Committee’s meeting to reiterate the governors’ concerns, saying they had candidates in mind. (See State Governors Seeking Ability to Nominate 2 Members to PJM Board.)
“Christie and Clements are widely respected leaders who understand the problems facing PJM and the region,” Shapiro and Youngkin wrote. “They have the independence and know-how to chart a principled new direction for the organization. We believe their appointments will begin to restore transparency and accountability to decision-making at PJM.”
They argued that PJM’s stakeholder process — with more than 1,000 voting members and requiring a supermajority for action — has resulted in a stalemate in recent years, requiring the Board of Managers to take unilateral action, which they suggested contributed to the ouster of two board members in May, including Chair Mark Takahashi. (See PJM Stakeholders Vote Out 2 Board Members.)
The nine governors also seek to create an association to engage in dialogue between their offices and PJM leadership. They plan to hold a technical conference Sept. 23 at the National Constitution Center in Philadelphia to discuss “organizational and market reforms at PJM.”
Shapiro and Youngkin wrote that failing to consider candidates recommended by the governors would undermine confidence in PJM’s governance.
“As governors from different parties, we have points of disagreement on energy policy, but we are united by the need to get PJM back on track to fixing the problems we collectively face,” they wrote. “By working together with a diverse, bipartisan coalition of governors, we are committed to solving these collective problems, and to ensuring that the citizens of our states and the region receive the affordable, reliable power that they deserve.”
Clements served from late 2020 until June 30, 2024, when she was replaced by Commissioner Judy Chang. (See Senate Confirms Chang as Clements’ Replacement on FERC.) She now works as a senior adviser for the consultancy Capstone, as a partner with digital infrastructure advisory firm ASG and as principal of 804 Advisory.
PJM Proposes Widening of Interim Deliverability Study Procedures
To increase energy supplies, PJMproposes expanding its process for allowing new resources to inject onto the grid while their required network upgrades are being completed, allowing a unit to operate partially.
The proposal includes two issue charges to rework the interim deliverability study process and expand provisional interconnection service.
PJM Director of Interconnection Planning Donnie Bielak said the RTO’s aim is to create a path for generators that fail interim deliverability studies but are able to inject some energy without causing network overloads, to operate as energy-only until they complete their full network upgrades. When an interim deliverability study identifies a local constraint affecting the ability for the resource to operate, an operational guide would be produced detailing the conditions under which dispatchers could use the unit.
Bielak said the impetus for the change is a surge in Energy Emergency Alert (EEA) Level 1 actions the RTO has initiated this year. The maximum generation and load management alert, the trigger for entering EEA-1, has been used 11 times in 2025, outnumbering all declarations since 2016.
“This is a pretty striking uptick in the use of this emergency procedure, which is only underscoring the need for more generation to be available to our control room,” he said.
Under the proposal, the deadline for developers to request an interim deliverability study would be pushed back from July 31 to June 30 to provide staff with more time to complete the studies. Developers would continue to cover the cost of their administration.
Paul Sotkiewicz, president of E-Cubed Policy Associates, welcomed the change and said it should have been pursued earlier, but faulted PJM for advancing it through the quick-fix process, which allows an issue charge and solution to be voted on concurrently. He argued the proposal cannot be made through manual revisions alone and would require tariff changes as well.
John Rohrbach, representing Southern Maryland Electric Cooperative, noted that, under PJM’s rules, resources without a capacity commitment have no accompanying day-ahead and real-time energy market must-offer obligation, making their market participation voluntary — a point on which Bielak agreed.
Stakeholders Endorse Revisions to PJM Protection Standards
The Planning Committee endorsed revisions to Manual 07: PJM Protection Standards to add a section saying the circuit cases studies produced by PJM planning staff should not be used in isolation. The language recommends generation owners (GOs) coordinate with the transmission owners (TOs) serving their points of interconnection, while TOs should coordinate with their neighbors.
The revisions also seek to expand relay communication requirements, add reporting open circuit conditions for station batteries and include additional detail on transformer high-side lead protection.
Relay Plans Endorsed
The committee endorsed a proposal to sunset the Relay Testing Subcommittee (RTS) and roll its work into the Relay Subcommittee (RS).
The revisions to the RS charter also seek to clarify the group is open only to NERC-registered transmission or generation owners in the PJM region who are signatories to the RTO’s operating agreement. Attendees are required to hold critical energy/electric infrastructure information (CEII) clearance. Invited guests are permitted to attend.
Addition of ELCC Classes Endorsed
Stakeholders endorsed manual revisions codifying the addition of two generation categories to be modeled under PJM’s effective load-carrying capability (ELCC) analysis. The concept was greenlit by the Markets and Reliability Committee at its March meeting and approved by FERC (ER25-1813). (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)
The language breaks oil-fired combustion turbines out of the catchall “other unlimited resource” category, putting them in their own bucket, and establishes waste-to-energy steam generation as an independent class from “steam.” The latter would be renamed to “other steam” as part of the change. The changes will be effective for the 2027/28 delivery year.
During the June MRC meeting, PJM presented ELCC values for the 2027/28 auction that rate oil CTs at 80% and waste-to-energy generation at 83%. The PJM Board of Managers approved parameters for the RTO’s Base Residual Auction derived in part from those ratings, contravening stakeholder opposition rooted in arguments that the ELCC methodology lacks transparency. (See PJM Stakeholders Reject 2027/28 Capacity Auction Parameters.)
The rating for oil CTs fell by 5% over initial estimates PJM presented at the March MRC meeting, while the waste-to-energy class rating remained the same. Those values were based on the 2025/26 third Incremental Auction (IA).
Transmission Expansion Advisory Committee
Market Efficiency Update
PJM has received several proposals to address congestion under the 2024/25 market efficiency window 1, which opened on April 11 and closed June 10. The window identified congestion on the Museville-Smith Mountain 138-kV line driven by expected load growth, and renewable development affecting the West Point-Lanexa and Garrett-Garrett Tap 115-kV lines.
Six projects focus on the Museville-Smith Mountain line, with three greenfield proposals costing between $270 million and $1.6 billion and three upgrades between $1.8 million and $131.6 million. Seven projects address the West Point-Lanexa congestion, including two battery storage proposals costing between $83.9 million and $221.7 million, three upgrades between $28.1 million and $90.9 million and two substation expansions between $21.4 million and $23.4 million. One update was proposed for Garrett-Garrett Tap with a $9.9 million cost.
Supplemental Projects
FirstEnergy presented a $20.4 million project in the Met-Ed zone to resolve low voltage identified in a contingency where two 230/69-kV transformers at the South Reading substation are offline. The project would install a new 230/69-kV transformer, a 69-kV grounding transformer, two new 230-kV circuit breakers, a 69-kV breaker and new relaying. It has a projected in-service date of Feb. 15, 2027, and is in the conceptual phase.
The utility also revised the scope of a project to rebuild the 7.2-mile Penelec section of the Ashtabula-Erie West 345-kV line to address maintenance issues with insulators and H-frame structures. The project now to is proposed to include replacing disconnect switches at Erie West and revise relay settings at Ashtabula, increasing the cost from $38.7 million to $52.4 million and pushing the in-service date from April 9, 2027, to May 31, 2027.
Exelon presented a $24.4 million project to replace a 345/138-kV transformer at its Skokie substation in deteriorating condition and with a possibly loose core/coil assembly. The first phase would install a new 138-kV, 115.2-MVAR capacitor bank, followed by removal of the tertiary 34-kV capacitor bank and replacement of the transformer and a 138-kV circuit breaker.
AEP presented several new service requests to serve large loads across Ohio, including a:
1,000-MW customer near the Hanging Rock substation in Scioto County by March 1, 2029;
1,200-MW load near the Muskingum substation in Waterford by Nov. 1, 2028;
Customer near the East Lima substation in Lima seeking service for 500 MW by Dec. 31, 2028, which is expected to ramp to 900 MW;
300-MW load near the East Lima-Fostoria Central 345-kV line in Findlay by Sept. 30, 2028; and
500-MW customer south of the Maddox Creek substation in Van Wert by Dec. 31, 2028.
A new report by EPRI and Epoch AI estimates U.S. power demand by artificial intelligence could jump from 5 GW today to more than 50 GW by 2030.
The sharp rise is due not only to the growth in the amount of large-scale training but also its increasing duration, and is tempered only partly by hardware efficiency improvements, the two organizations said in their Aug. 11 announcement of “Scaling Intelligence: The Exponential Growth of AI’s Power Needs.”
Beyond large-scale training, more power capacity will be needed for AI research and for the actual use of finished AI models. But the training needs alone are formidable: Power consumption for training cutting-edge AI models is doubling annually.
“Frontier AI training runs — the computationally intensive process of training large, advanced AI models — currently consume approximately 100-150 MW each and are projected to reach 1-2 GW each by 2028, exceeding 4 GW per training run by 2030,” the authors write.
Training duration is assumed to have a 10% to 20% annual growth rate in the future. This compares with 25% to 50% in recent years. Increasing the duration can spread the same amount of power use across over a longer period, smoothing out peak demand. But the authors say durations now exceed 100 days, so further increases may yield diminishing returns.
Meanwhile, for the study, hardware efficiency is assumed to improve 33% to 52% annually.
The authors say the split of demand between training AI models and using them is important, as it could affect the size, location, power demands and potential flexibility of AI data centers. But it is currently uncertain, and the landscape is changing rapidly.
Some forecasts show AI consuming more than 5% of U.S. generation capacity by 2030, with some training runs equivalent to the output of entire power plants.
As has been noted many times, meeting such a level of peak demand just with new capacity could be quite challenging and extremely expensive. Some flexibility of demand during peak periods would help make the process less expensive and difficult.
The authors suggest: “Planning should account for both concentrated and distributed data center loads as well as the potential for real-time flexibility in training and inference workloads and from on-site generation and storage assets.”
“Inference” — usage of a trained AI model, such as generating responses to user requests — could support more flexibility than AI training.
The authors state that the rapid rate of growth of AI computing seen recently and projected in the next several years almost certainly must slow by the 2030s, because it is accompanied by a growth in cost that is not quite as rapid but is nevertheless unsustainable.
Whether that slowdown starts before 2030 may depend on technical innovations, data constraints or diminishing returns to scaling, they write.
The Committee on Regional Electric Power Cooperation’s (CREPC) Transmission Collaborative (TC), in collaboration with Energy Strategies, has issued its first cost allocation study to provide the industry with guidelines on how to tackle the thorny issue.
“The work conducted by Energy Strategies in consultation with the CREPC Transmission Collaborative to develop the State Exploration of Western Transmission Cost Allocation Frameworks policy brief and technical report is valuable to helping Western states better understand different cost allocation methodologies and implications,” Gabriel Aguilera, chair of the New Mexico Public Regulation Commission and co-chair of CREPC, told RTO Insider in a statement.
“While nothing in this study is intended to be binding, states can build on the foundational elements of the study as transmission cost allocation discussions develop and evolve in the West,” Aguilera said.
In an effort to strengthen stakeholders’ understanding of the “challenges associated with regional cost allocation in the West,” the TC members provided six takeaways from the report, according to the policy brief.
The six takeaways are:
“Transmission cost allocation frameworks must result in the allocation of transmission capacity. Any transmission cost allocation framework that fails to align costs allocated with transmission capacity assignments (MW) is unlikely to be successful.”
Establish “well-defined thresholds, clear standards and independent expert input for ensuring that capacity assignments resulting from a cost allocation process are both meaningful and useful,” the brief stated. “As part of this, cost allocation approaches should include rules to ensure that entities receiving de minimis benefits are not allocated costs.”
Because there is no broadly accepted method for measuring public policy and resource access benefits, the TC suggests that entities should be allowed to voluntarily subscribe to capacity on a line based on their own perceived benefits of certain transmission projects. This can address allocation disputes arising out of projects aimed at, for example, helping public agencies achieve decarbonization goals by transporting wind power from one state to another.
Achieving a fully binding cost allocation process in the West is highly technical and difficult. Instead, stakeholders must agree that voluntary participation mechanisms are crucial for achieving significant transmission buildout, despite the risk of “free ridership.” However, voluntary commitments can be converted into contractual or financial capacity or cost-share commitments as projects advance.
Benefit quantification is a “critical foundation” for cost allocation. It is therefore important that those calculations be done with transparency, coordination and collaboration in mind.
A transparent, well-defined and flexible process can help tackle some of the common issues that can arise during cost allocation discussions, such as preventing the overburden of individual utilities, accommodating different value systems and supporting fairness principles, among other benefits.
To reach these takeaways, the TC and Energy Strategies developed three cost allocation frameworks, based on different combinations of four cost allocation approaches: subscriber pays, beneficiary pays, zonal-cost assignment (costs are assigned on a load-share basis) and opt-in/-out (costs and project capacity are reassigned after initial allocation to entities volunteering to purchase additional capacity).
The frameworks were tested under three hypothetical interstate transmission projects. Two of the frameworks provided more proportionality, flexibility and optionality than the base case and were also preferred by stakeholders who provided input to the study.
“Despite a split on which framework is most appropriate, most representatives felt somewhat comfortable with the conclusion that these flexible, nonbinding cost allocation frameworks can help address Western states’ concerns about misalignment between cost assignment and customer benefits,” the brief stated. “Participants also recognized the crucial importance of the potential project participants voluntarily subscribing to capacity for these frameworks to be successful.”
While the reported pick of David Rosner to be chair of FERC might appear to be a rare bipartisan move from the White House, sources familiar with the issues said in interviews that it represents another step in exerting control over what historically has been an independent agency. (See Reports: Trump to Name Democrat Rosner as FERC Chair.)
Sources who know FERC well were granted anonymity to speak candidly with RTO Insider about politically sensitive issues.
On Aug. 8, several outlets reported that a White House source said Rosner would be named chair. But as of close-of-business Aug. 11, the White House had yet to designate a chair, and FERC’s website listed only three sitting commissioners. Without a chair, the agency cannot issue orders. In the past, former Commissioner Bill Massey was named chair for literally a weekend as President Bill Clinton was transferring power to President George W. Bush during the Western Energy Crisis.
President Donald Trump issued an executive order in February directing FERC and other “so-called” independent agencies to submit proposed and final significant regulatory orders to the Office of Information and Regulatory Affairs for review before they could be published in the Federal Register. (See Trump Claims Authority over Independent Agencies in Executive Order.)
Former Chair Mark Christie, who stepped down from the agency Aug. 8, actually spent most of his first press conference defending that order, arguing that FERC never enacts policies at cross purposes with the White House’s goals. But he also said he never would allow discussions of pending items before the commission covered by ex parte rules. Ultimately, he proved too independent for this White House. (See FERC’s Christie Says Existing Policies Can Align with Trump Order.)
While the idea of ending FERC independence might seem short-sighted given that Democrats could retake the White House in 2028, one source said the view there now is “to the winner goes the spoils” and some members of the minority party would be happy to steer the agency when they are next in control of the presidency.
Nobody who spoke with RTO Insider could remember a time when a White House had passed over a nominee from their own party to name a chair from the other. In Trump’s first term, he demoted Norman Bay and elevated Cheryl LaFleur to run the agency again, but there were no Republicans on the commission after a dispute between President Barack Obama and members of the Senate Energy and Natural Resources Committee over nominees.
Opposition from former Sen. Joe Manchin of West Virginia (at the time a Democrat, though he converted to independent in 2024 before leaving office) to nominee Ron Binz and then making Bay the chair was part of that dispute with Obama. Manchin went on to chair that Senate committee and was a major supporter of Rosner, who was detailed to it from FERC before being nominated.
Everyone interviewed by RTO Insider praised Rosner as a well-qualified commissioner who would do a good job for as long as he runs the agency. But his pick could indicate the White House is favoring nominees who back specific policies as part of its efforts to control FERC.
The co-location order proved unpopular with owners of merchant nuclear plants who value the deals to hedge against the possibility of lower power prices in the future, which would help keep them open for decades. Data center developers also were not happy, but with the largest of them having massive balance sheets, they have found ways to keep expanding.
One source said Rosner has proven more eager to support natural gas infrastructure development, while See appears more inclined to pay heed to legal arguments that FERC needs to consider their environmental impacts and emissions.
Trump has nominated Laura Swett and David LaCerte to the two open seats on the commission, and the Senate likely will move on those nominations this fall. Swett has been expected to be named chair, and while sources likewise praised her abilities, she also might have been nominated due to being more willing to work with the White House than Christie was.
One source said Rosner could make that same deal and stay as chair even after Trump gets his own nominees on the commission.
Regardless of who runs FERC for the next several years, the issue of its independence, and that of all similarly structured agencies, is going to rise to the Supreme Court, where the same “unitary executive theory” the White House is pursuing is popular among Republican justices.
In an order from May 22 overruling a stay that would have stopped Trump from firing members of the National Labor Relations Board and the Merit Systems Protection Board, Chief Justice John Roberts wrote the government was likely to win that case, though the question is better left for resolution after a full briefing and argument.
Justice Elena Kagan, joined by the two other Democrat nominees on the court, pushed back on the chief justice’s argument that such agencies exercise considerable executive power on behalf of the president.
“Congress created them all, though at different times, out of one basic vision,” she wrote. “It thought that in certain spheres of government, a group of knowledgeable people from both parties — none of whom a president could remove without cause — would make decisions likely to advance the long-term public good.”
KANSAS CITY — SPP has approved its seventh competitive project under FERC Order 1000, a 19-mile, 115-kV new transmission line with an estimated cost of $45.5 million.
An independent industry expert panel (IEP) selected incumbent Southwest Power Service Co. as the project’s designated transmission owner. Invenergy, the only other bidder on the project, was designated as the alternate TO.
The RTO’s Board of Directors approved both selections during its Aug. 5 quarterly meeting. The Members Committee provided a unanimous advisory vote, with seven abstentions.
SPS submitted a bid of $21.1 million to build the line. Invenergy’s bid came in at $36.3 million.
The IEP unanimously endorsed SPS as the designated TO. It found the utility’s bid would significantly lower the project’s lifetime cost ($21.8 million to $51.9 million) and that it was superior in identifying a construction and procurement plan. The panel gave SPS a 1,052.2 score, more than 200 points better than Invenergy (829.62), aided by incentive points awarded by SPP for meeting detailed project proposal requirements.
“You’ll see a wide difference between points,” IEP Chair Tom Bozeman said as he shared the results with the board. “It was a relatively obvious, easy slam-dunk decision.”
The IEP’s final report included a request that bidders improve the quality of their reports, a new addition from the panel.
“The intention was to reinforce a well-organized quality proposal, because that’s what we’re looking at. That’s what we’re comparing,” Bozeman said. “It’s important for the bidders to have the information that’s requested and needed in their proposals because we’re not asking for additional information later.”
Scoring matrix for the Lynch-Medanos competitive project. | SPP
SPP staff determined the Lynch-Medanos project would help maintain NERC compliance and allow the continued ability to serve SPS load in New Mexico with adequate voltage levels. It was approved in 2024 as part of the latest Integrated Transmission Planning assessment, resulting in a $7.65 billion portfolio. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.)
The project has a Dec. 1, 2028, in-service date.
1st Surplus+ Initiative Approved
The board approved a tariff revision (RR693) that would accelerate the addition of new generation by quickly adding shovel-ready incremental capacity at existing generating sites. The first Surplus+ initiative is among a suite of products that would end when the Consolidated Planning Process begins in 2026. (See related story, SPP Celebrates its Novel Consolidated Planning Process.)
Under the proposal, priority requests would be queued higher than study clusters that haven’t started. The process would be conducted on an accelerated time frame, not subject to waiting for open seasons or processing as part of a cluster or from needs driven by other requests.
Assuming FERC approval in October, the first requests would be submitted for a 90-day system-impact study, with the first generator-interconnection agreements issued by April 1, 2026.
The Advanced Power Alliance appealed the tariff change to the board, asking it to reject three modifications made by the Markets and Operations Policy Committee in July: expanding eligibility to include facilities that retired in the past five years, assigning Surplus+ requests higher queue priority than requests in the 2024 studies, and removing key guardrails designed to limit facility expansion.
As an alternative, the organization asked that the board either impose a one-time participation limit per existing facility or include an explicit sunset clause in the tariff filing.
“This proposal is intended to serve as a short-term mechanism to facilitate modest incremental capacity additions, not provide an alternative path to interconnection long-term,” APA said in its comments. “The continued undermining of established processes to interconnect in SPP adds risk to developers who have a record of investing billions in the region.”
In response, board member Stuart Solomon amended staff’s motion to include a direction that staff modify the language to make the process available once per generating facility or applicable retired generator before it is filed with FERC.
“This is an innovative proposal that provides another tool for [load-responsible entities] to meet their resource adequacy requirements,” he said.
Members endorsed the amended revision 15-5, with two abstentions. The APA, EDP Renewables, Electric Cooperatives of Arkansas, the Natural Resources Defense Council and Pine Gate Renewables opposed the measure.
The board also approved RR689, which addresses a market inefficiency that allowed participants to exploit electrically equivalent settlement location (EESLs) to acquire transmission congestion rights (TCRs) at no net cost, despite real congestion costs in the day-ahead market. The policy establishes a systematic review to detect and prevent manipulative TCR bidding behavior by denying portfolios with offsetting EESL path bids.
Future suspicious activity will be flagged for monitoring and potential violations referred to the Market Monitoring Unit. The MMU supports the policy, calling it “manipulative behavior.”
Nickell: ‘Have to Move Faster’
SPP CEO Lanny Nickell thanked the Strategic Planning Committee for putting together a task force, headed by board member Irene Dimitry, to review and improve the grid operator’s selection process for competitive projects.
“Some of you have heard me lament over and over that I don’t like the fact that it takes so long to go through that process, particularly in today’s environment, when we need reliability faster than we’ve ever needed before,” he said. “Transmission is a big part of helping us improve our reliability.”
Under the RTO’s transmission owner selection process, staff will solicit requests for proposals once a project has been approved by the board. Qualified participants have until June 30 of each year prior to the selection process to submit their applications.
An independent panel of industry experts then reviews, ranks and scores proposals during a confidential process. The results are announced during board meetings.
Tx Costs Exceeding Estimates
Noticing the consent agenda included approval of 11 transmission projects with costs outside the +/- 30% acceptable band, board member Solomon asked staff how deep its and the Project Cost Working Group’s analysis goes in making the determinations. He also asked whether staff have considered reasons for the cost increases.
SPP’s Casey Cathey, vice president of engineering, said the PCWG looks at “each and every” out-of-band project and discusses the reasons for the new estimates with the project’s owner.
“Staff also validates those reasons,” Cathey said. “There’s certain things that this staff doesn’t have privy to … so it depends on how deep you want to go, but we do validate each reason.”
SPS’ 765-kV project was pulled off the consent agenda for a separate discussion. (See related story, SPP Board Sets Aside 765-kV Costs, Large Load Policy.) However, the Elm Creek-Tobias competitive project remained, despite a revised cost estimate of $291 million that almost doubles the original $148 projection.
Staff said the discrepancy stems from an omission in the original estimate, which included only conceptual projections for the project’s non-competitive portion. SPP re-evaluated the project and determined it remains the most effective solution to address winter weather transfer needs between Nebraska and Kansas.
The board approved the project, an 85-mile 345-kV transmission line on the western side of SPP’s footprint, in October 2024. The project includes four components: terminal upgrades at each end, a non-competitive segment and a competitive segment to be built. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.)
The consent agenda also included:
the 2026 Operating Plan, which serves as the foundation of the 2026 budget. The plan focuses on each business area within the RTO and aligns long-term strategy with 2026 initiatives. The Finance and Strategic Planning committees approved the plan during a joint meeting in July.
The Massachusetts Department of Public Utilities has directed the state’s gas distribution companies to revise their line extension policies and require new customers to cover the cost of new hookups, with limited exceptions.
Issued on Aug. 8, the order is poised to end the longstanding utility practice of charging to the rate base the costs of connecting new gas customers. The practice assumes the new customers eventually will pay back these costs through distribution fees (20-80-E).
The ruling likely will significantly increase the upfront costs associated with new natural gas hookups in the state and reflects the DPU’s increased focus on phasing out natural gas use for heating. In 2023, the DPU required the utilities to consider gas alternatives, and in 2024 state lawmakers required the department to consider the state’s emissions limits and risks of stranded assets when authorizing requests for gas system expansion.
The DPU first proposed the change in February, expressing concern that existing line extension policies are misaligned with the state’s efforts to decarbonize and do not account for risks of stranded assets as customers transition to electric heat pumps. (See Mass. DPU Proposes Major Shift in Gas Line Extension Policies.)
The proposal was supported in comments submitted by climate advocacy groups, the Department of Energy Resources and the Massachusetts Attorney General’s Office. Investor-owned gas utilities pushed back, arguing that ending line extension allowances may push some customers to higher-emitting heating methods like oil and propane.
In its ruling Aug. 8, the DPU agreed with the AGO that the gas utilities assume “unrealistically long” payback periods for new customers and do not account for declining gas usage because of decarbonization.
The DPU also wrote that the gas companies’ existing formulas for calculating upfront payments for new customers fail to account for “the environmental impact of the additional gas combustion facilitated by the expansion of the gas distribution system through line extensions.”
The department rejected arguments that the policy change will push customers toward fuel oil or propane heating systems, writing that “no evidence is offered to suggest that such a situation is anything more than a rare or isolated circumstance.”
Responding to utility concerns about cost barriers to electrification, the DPU referenced a 2024 report sponsored by environmental groups that found all-electric new construction has reached near-cost parity with fossil construction. (See Report Outlines Cost Savings of All-electric Buildings in Mass.)
“It is a better course of action to address in other proceedings the claimed barriers to electrification than to maintain a line extension policy that locks in continued growth in the natural gas distribution system that is contrary both to the commonwealth’s climate goals and to the minimization of potentially stranded costs,” the DPU added.
The department stressed that the policy change does not deny customers the ability to connect to the gas network but requires customers to assume the costs and stranded-asset risks associated with these connections.
“Eliminating line extension allowances neither incentivizes nor disincentivizes new gas extensions,” the DPU wrote, citing AGO testimony that the change “only removes an unwarranted incentive.”
Under the proposal, the department would allow utilities to socialize the costs of new gas connections only if a customer “can demonstrate that it has no technically feasible alternative to the use of natural gas, including electrification.”
The DPU wrote that exceptions likely will be limited to “hard-to-electrify” commercial and industrial customers. It said gas utilities will be responsible for demonstrating the need for any exception.
The department required the utilities to file revisions within 30 days in the dockets for their climate compliance plans (CCPs). It noted that stakeholders will have the opportunity to file briefs and evidence within the CCP dockets on the DPU’s revised proposal and the utilities’ compliance proposals (25-40 through 25-45).
“This order is another great step in the right direction toward an orderly transition off of the natural gas system,” said Kyle Murray, Massachusetts program director at the Acadia Center. “It also shows that the natural gas system has traditionally only been able to expand thanks to massive subsidies from existing ratepayers. This order is simply removing that subsidy and requiring natural gas to compete on an even playing field.”
Stakeholders requested that the NYISO Market Monitoring Unit provide a comprehensive explanation of the difficulties in obtaining data from the ISO and market participants on supplemental commitments after it presented its State of the Market report for the first quarter Aug. 5.
Supplemental commitments to satisfy reserve requirements occurred on 75 days in the first quarter in the North Country load pocket — near the border with Canada — and 28 days in New York City load pockets, according to the MMU’s presentation to the Installed Capacity Working Group. Nearly half of these commitments could not be verified by the MMU.
“These are instances where we weren’t able to get information to substantiate the need for the commitment,” said Pallas LeeVanSchaick, vice president of Potomac Economics.
A supplemental commitment is an out-of-market action in which a generator is not committed economically in the day-ahead market but is needed for reliability. Transmission owners and NYISO operators may dispatch generators “out of merit order” to maintain lower-voltage reliability and manage constraints in high-voltage transmission that are not represented in the market model.
Stakeholders pointed out that this was a repeat issue for the MMU and asked whether there was a provision in the tariff or a technical issue that was preventing the MMU from obtaining the information. LeeVanSchaick said the data from the ISO are not detailed enough to make a determination in all cases.
Stakeholders also asked whether the MMU was able to ask transmission owners and generators for information. LeeVanSchaick said that while it can ask any market participant for information, the kind of information is different depending on what kind of participant it is.
“I don’t think it’s a matter of asking the MMU to identify who the bad guy is, so much as … providing more information about the … different rules and responsibilities for information requested from generators, the NYISO, TOs and other parties,” a stakeholder who did not identify themselves said. “Understanding that at a general level could show what the barrier to receiving information might be.”
Competitive and Congested
The NYISO markets otherwise performed competitively, the MMU said. Prices in each region were up year-over-year this quarter, ranging from 59 to 119%, mostly driven by higher natural gas prices, which rose 67% in Western New York and 188% along the border with Vermont. LeeVanSchaick said that this was from the extremely cold weather in January and February.
Load levels were higher across the state compared to 2024. The average daily load increased 4.5%, and the peak load increased by 3.4%. At the same time, congestion rose within the state and across the PJM-NYISO interface. This was partially because of transmission outages in New York but also from high demand.
Thirty percent of the congestion occurred in New York City, increasing 450% year over year. The Gowanus-Greenwood line was out of service throughout the quarter, and a parallel line was out of service in February.
Many generators were curtailed or out of service. During the coldest part of January, roughly 1.75 GW of oil generation was out of service because of planned outages. “As NYISO implements firm-fuel capacity accreditation in 2026/27 and designs a seasonal capacity market, it will be important to consider reasonable limits on planned outage scheduling under peak conditions and incentives for availability,” the MMU said.
NYISO and local TOs issued 28 GWh of wind curtailments manually because of unmodeled transmission constraints or generators not responding to economic curtailment instructions. The MMU found that TO-controlled communication equipment was not maintained well enough to send signals from NYISO to the control centers of many wind plants. It suggested implementing stronger penalties for failure to comply with curtailment instructions.
SPP’s Board of Directors has agreed to defer action on a 765-kV transmission project with a ballooning cost estimate and on staff’s large load integration policy, both the source of much stakeholder discussion.
The 765-kV project, the first in SPP history, was awarded to Southwestern Public Service in February with an estimated cost of $1.69 billion. SPS filed a revised cost estimate of $3.62 billion in June, more than double the earlier projection and easily outside the variance bandwidth of +/‑30% that can lead to a re-evaluation.
However, SPP said the 765-kV project remains “the most cost-effective and strategically sound option” to address Eastern New Mexico’s “critical needs.” The grid operator has seen a 32% increase in summer peak load for the 2023 and 2024 transmission planning assessments, driven by rapid electrification of the oil and gas industry. It said “significant” growth is continuing into the 2025 and 2026 assessments.
The board deferred a decision on the project during its Aug. 5 quarterly meeting until it meets again in November, at the latest.
The directors also delayed action on SPP’s proposed large load integration policy, agreeing to wait until after a special Markets and Operations Policy Committee call Aug. 21. That will allow for additional stakeholder input and technical review. The board plans to hold a joint meeting with state regulators less than two weeks after the MOPC call to discuss the issue further. Both bodies will vote on the proposal during their October and November quarterly meetings.
MOPC rejected the proposal during its July meeting, giving it only 53.7% approval. (See “Members Shoot down Staff’s Proposal for Integrating High-impact Large Loads,” SPP MOPC Briefs: July 15-16, 2025.)
SPP says high-impact large loads (HILLs), generally defined as anything equal to or larger than 50 MW, are investments requiring short-term costs to integrate and operate that are balanced with long-term benefits (jobs and revenue). The proposal would complete system impact studies within 90 days for the load and its supporting generation together, leading into the normal firm-service interconnection queue. Study costs would be directly assigned to the cost-causers (the requesting transmission customer), staff said.
SPS 765-kV Project Deferred
The RTO gave the Potter County-Crossroads-Phantom project a notification to construct with conditions (NTC-C); SPS could not order materials or begin construction until it provided a refined project estimate within the study’s variance bandwidth.
The company’s engineers revised the line costs from about $4.2 million/mile to $5.9 million/mile, comparable to what MISO and ERCOT are projecting in their 765-kV projects. They also increased SPP’s original estimate of 244 miles for the project’s two legs to 354 miles to account for their actual paths. The modifications accounted for more than $661 million of the increased cost estimate.
Reactor costs also increased $180 million between the two estimates, SPS said. It will incur additional expenses for two new 765/345-kV substations, necessitating three additional 20-mile 345-kV line segments, because of “land challenges.”
SPS’ Jarred Cooley, the utility’s director of strategic planning, told the board and stakeholders that the 765-kV lines’ right of way of up to 250 feet forced it to “skirt around” communities, oil and gas infrastructure, irrigation systems, archeological sites and environmental species habitats, such as the endangered lesser prairie-chicken.
“This is something that we, as an entire company, are digging into deeply across multiple fronts,” Cooley said during SPP’s joint stakeholder briefing Aug. 4. “We’ve spent a lot of time on this. We definitely understand the sticker shock of the comparison between the initial SPP estimates and what SPS is providing today.”
American Electric Power’s Stacey Burbure, vice president of FERC and RTO policy and strategy, said SPS’ cost estimates are in line “across the board” with what her company is seeing. AEP has been awarded one of three 765-kV projects in ERCOT and owns 2,110 miles of 765-kV transmission, more than any other transmission company in North America.
“When I think about why we are here, it’s because the initial cost estimate is wrong,” she said.
“There’s a need for improvement,” Oklahoma Municipal Power Authority’s Dave Osburn said, “but when I looked at what the future projections and the load increases that are being projected, I’m not sure how we can really efficiently do that without 765.
“Yes, they are more expensive than others, but there’s a lot of other benefits that come with the 765 overlay,” he added. “As we go through this particular project, let’s learn from this, and let’s figure out the true cost of building out the 765, because I do think it’s something we’re going to have to be addressing going forward.”
As a short-term reliability project, Potter County-Crossroads-Phantom is not eligible for the competitive process. It currently has an in-service date of 2031.
“Back in February when we addressed short-term reliability projects, I raised concerns about this particular project because it was so large. Now that the costs are more than double, my concerns are intensified, but I’m very sensitive to the fact that this is a reliability project,” Director Irene Dimitry said. Alluding to the in-service date, she added, “The solution that has been identified for this near-term need is not a near-term solution.”
Dimitry said she wanted to see more time taken to find the right balance between reliability and affordability by considering competitively bidding the project. She offered a motion that would rescind the board’s prior approval of the project and direct staff to facilitate an expedited competitive selection process. Dimitry, who has been tasked with assembling a task force to refine SPP’s competitive selection process, suggested a recommendation be made to the board at its May 2026 meeting.
The motion failed both the Members Committee’s advisory vote (7-8, with seven abstentions) and the board’s vote. SPP does not disclose the board’s vote beyond “pass” or “fail.”
SPS President Adrian Rodriguez defended the project’s reliability status, saying that had it been in place in March, the utility would not have had to drop 122 MW of load for almost three hours. He welcomed the board’s attention, saying, “We need to get this right.” (See SPP Addresses 3rd Load Shed Since March 31.)
“The scrutiny is justified, and we’re committed to being part of our early engagement in assessing costs with the SPP staff and bringing this before the board,” he told directors. “It’s clear that the costs, I acknowledge, are different from the original estimate, but that comes with validation of uses. We’re excited about setting a strong precedent.”
Rodriguez promised SPS would continue to update the board and work with staff before November. He said the company has focused on keeping costs as low as possible, from competitively procuring engineering and construction services to holding slots for equipment in an uncertain supply chain.
Any further delays would only increase the project’s costs, Rodriguez said.
“The tradeoff that we’re always sensitive to is, in this case, delayed dollars. Every day that passes, these costs can increase,” he said. “I am very sensitive to moving quickly … but very concerned about any type of lengthy delay that could result in increased costs” for major transmission and distribution supplies.
“What I don’t want to do is to have a self-fulfilling prophecy that we come a couple of months later [and] there are some cost increases because of the additional delays, and then we are back in the same boat,” Rodriguez added. “At the end of the day, ultimately, it’s our customers that are impacted.”
Members agreed there’s a need to address how large loads are added to the system but raised concerns about maintaining reliability, cost-allocation equity and transparency. Views differed on how to balance speed with planning thoroughness; how to define qualifying load types; and whether existing processes could be adapted or new pathways were needed.
The discussions have continued since then. COO Antoine Lucas surveyed the audience for the board meeting and said he could see stakeholders he has had phone conversations with in recent weeks as he worked to “try to get people comfortable as quickly as we could,” he said.
He argued that the policy will help SPP integrate the large loads and their high impact.
“The high-impact portion of it is really based on our assessment that these loads have the ability to materially impact the reliable operations of the system,” he said. “For that reason, we felt that there was a need for pretty detailed and enhanced policy proposals to ensure that we were able to identify what those differences were and some of the risks that those posed.”
Lucas said staff will continue to engage with stakeholders until an MOPC call Aug. 21. The joint board and Regional State Committee meeting that follows will give staff additional input in bringing back the policy to the October and November meetings.
Based on the feedback already received, Lucas said SPP will focus on just two of the policy’s three paths: HILLs and high-impact large load generation interconnection assessments (HILLGAs). The latter are generation and load studied on the fast track and pairing generation with a HILL or a conditional HILL (CHILL).
Lucas proposed that SPP continue to work on CHILLs, which has received most stakeholder questions. These loads would be interconnected to the grid quickly but would be expected to transition to firm service within five years.
“We would have a little more time to work through that with stakeholders and make sure that they’re all comfortable with that,” Lucas said. “We think we have a pretty good product at the end of the day to make the SPP region more attractive for entities who are looking to … connect large loads.”
Board Vice Chair Ray Hepper, leading the meeting in place of Chair John Cupparo, reminded the board and stakeholders that it was an “executive order” from the chair in May that asked for staff to return in August with a large load integration policy.
“Not only did they bring us a proposal, they brought us tariff language; that is an incredible accomplishment,” Hepper said, not mentioning that the proposal is about 500 pages long. “Everybody agrees we need to move quickly. We don’t want to slow this proposal down, but a little more time is helpful. This is an important initiative for lots of the [load-responsible entities], and it’s important for lots of the states.”
