NERC is requesting comments from industry through Sept. 10 on four proposed reliability standards aimed at satisfying FERC’s directive on inverter-based resources.
The ERO posted the standards in its Standards Balloting System on Aug. 8, along with the latest update to the ERO’s Reliability Standards Development Plan (RSDP), which lays out the planned schedule of standards development from 2026 to 2028. Comments on the RSDP are due by Sept. 5.
The following standards are up for comment:
MOD-032-2 — Data for power system modeling and analysis;
IRO-010-6 — Reliability coordinator data and information specification and collection;
TOP-003-8 — Transmission operator and balancing authority data and information specification and collection; and
MOD-033-3 — Steady-state and dynamic system model validation.
All of the standards were developed under Project 2022-02 (Uniform modeling framework for IBRs) except for MOD-033-3, which originated from Project 2021-01 (System model validation with IBRs). NERC’s Standards Committee approved all of them for posting at its April 16 meeting. (See NERC Standards Committee Approves IBR Posting.)
In Order 901, issued in October 2023, FERC directed NERC to develop requirements pertaining to the reliable connection and operation of IBRs, grouped into four milestones to be submitted over the following three years (RM22-12). (See FERC Orders Reliability Rules for Inverter-Based Resources.) Included in Milestone 3, due Nov. 4, are requirements for providing data on IBRs and distributed energy resources to entities responsible for planning and operating the grid.
To satisfy this mandate, the standard development team for Project 2022-02 decided to update MOD-032-2 to include language from the ERO Unacceptable Models List, renamed Aug. 1 from the ERO Acceptable Models List Criteria Document. A new requirement allows planning coordinators and transmission planners to specify whether they will accept standard-library dynamic models, user-written models or both.
NERC said the requirement is “responsive to FERC concerns about model usability and non-convergence by requiring PCs and TPs … to specify usability requirements and require appropriate model documentation and instructions,” while also allowing a level of flexibility requested by stakeholders in industry engagement workshops.
Another requirement was rewritten “to require estimation of modeling data if the responsible entity … is unable to gather required data.” This is intended to give entities a way to meet FERC’s directive of submitting data even if the actual information is unavailable; however, entities that submit estimates must explain the “limitations of the estimated data” — such as legal prohibitions on requesting certain data, incomplete records of connected facilities and lack of mechanism to enforce collection — “and the method used for estimation.”
The final revisions recorded by the SDT apply to TOP-003-8 and IRO-010-6, and state that “entities responsible for developing and distributing data specifications shall include requirements for model submissions consistent with the model submitted for planning purposes, as applicable.”
The drafting team for Project 2021-01 said that “no substantive changes are needed” for MOD-033, but members did note “opportunities to improve the clarity of both the [standard’s] requirements and measures.” To this end, they proposed to add the glossary term “model validation” — approved in May by industry ballot for inclusion in NERC’s Glossary of Terms — to the standard, along with a requirement that the PC implement a model validation process for its “portion of the existing system.”
Team members also updated additional language in the standard to correspond with the “model validation” definition and to reduce redundancy and wordiness.
1st Read on Offer Capping of Advance Scheduled Resources
PJM’s Phil D’Antonio presented a first read on a proposal to cap resources committed ahead of the day-ahead market at their cost-based offer. The proposal is set to be voted on by the MIC at its September meeting, and additional manual, operating agreement and tariff language would need to be drafted and voted on subsequently. (See “Offer Capping Resources with Advance Commitments,”PJM MIC Briefs: March 5, 2025.)
Advance commitments have been used more widely since the institution of the conservative operations procedure, which allows PJM to schedule resources expected to be necessary to maintain transmission security during strained operating conditions, especially winter storms. The cost of that practice has been criticized by consumer advocates, and the use of out-of-market commitments has been opposed by some generation owners. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.)
Paul Sotkiewicz, president of E-Cubed Policy Associates, said PJM’s governing documents only allow for offer capping resources with advance commitments to address transmission constraints, arguing that offer capping resources committed for other purposes violates the tariff and negatively impacts price formation.
“I think this is going down a very dangerous path,” he said.
PJM’s proposal states that the “PJM tariff and [Operating Agreement] allow for offer capping only for transmission constraints. Current [Manuals 11 and 13] language allows offer capping for units scheduled in advance of the day-ahead market but does not have supporting tariff and OA language.”
Offer Capping Issue Charge Revised
The committee endorsed by acclamation an expansion of the offer capping issue charge brought by the Monitor to include additional consideration of the treatment of resources with advance commitments in the day-ahead market, how uplift is calculated for resources committed for multiple days and additional transparency into how resources are scheduled.
The issue charge was renamed to reflect the wider scope, removing references to offer capping to instead read as “resource scheduling prior to the day-ahead energy market.” (See “Monitor Proposes Rewrite of Offer Capping Issue Charge,” PJM MIC Briefs: July 9, 2025.)
The revisions also add additional education on the triggers for allowing advance commitments, notifications that go out to stakeholders that such action has been taken, commitment instructions to resources, the inputs and models that determine commitment parameters and operational constraints not included in unit parameters, such as fuel inventory, gas nomination cycles and any run hour limitations associated with environmental permits.
Renewable Dispatch Proposal Endorsed
Stakeholders endorsed a PJM proposal to create a new Effective EcoMax parameter for wind and solar resources intended to better capture how they are capable of operating in real-time energy market dispatching. The proposal passed with 98.9% support. (See “First Read on Real-time Renewable Dispatch,” PJM MIC Briefs: July 9, 2025.)
The forecast for wind and solar output would be updated ahead of each five-minute interval, which then would feed into the Effective EcoMax parameter and update maximum output the generator can be dispatched up to. The existing EcoMax parameter limits security-constrained economic dispatch (SCED) based on the parameters submitted by resource owners, which can become stale and lead to units being curtailed below their potential.
The proposal was modified by PJM to retain curtailment flags for wind resources and establish them for solar as well; they had been set to be removed for all resources in July, but a Distributed Resources Subcommittee poll showed 96% support for allowing them for renewables.
Renewables would be limited to ramping at 20% of their ICAP per minute to minimize the volatility that can come from sudden shifts in renewable output. PJM’s Vijay Shah noted that still would allow those resources to go from 0 to 100% of their capability in a single interval.
Regulation Market Redesign Endorsed
The committee endorsed by acclamation a slate of manual revisions to conform with PJM’s regulation market redesign, which was approved by FERC in June 2024 (ER24-1772). (See “PJM Presents Manual Revisions for Regulation Market Redesign,” PJM MIC Briefs: July 9, 2025.)
The reworking of the market creates a single price signal with resources able to offer regulation up and down products, replacing a market model where participants offered bidirectional products to provide either Regulation A for long deployments or Regulation D for fast response. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.)
The proposal includes revisions to Manual 11: Energy & Ancillary Services Market Operations, which detail offer structure, DR participation and lost opportunity cost credits; Manual 15: Cost Development Guidelines, including a stipulation that regulation resources also participating in the energy market do not receive variable operations and maintenance cost increases; and Manual 28: Operating Agreement Accounting, which outline the regulation clearing price credit formula.
PJM’s Kevin Hatch presented an update on how two heat waves between July 14-17 and 23-30 affected PJM operations, which involved multiple demand response deployments and emergency alerts and advisories.
Loads reached their apex on the afternoon of July 29, with a preliminary integrated hourly peak of 157,487 MW, which Hatch said would be the ninth highest the RTO has seen. He said the day saw atypically high load ramping, renewable performance below the seasonal effective load-carrying capability (ELCC) value, and generation outages exceeding the three-year average. Around 3.7 GW of DR was deployed.
The declaration of maximum generation and load management alerts without extreme temperatures raised concerns for PJM that load growth and renewable penetration could jeopardize resource adequacy. During the Aug. 5 Planning Committee meeting, PJM said it had initiated 11 maximum generation and load management alerts in 2025, more than the prior decade combined.
The first heat wave saw maximum generation and load management alerts July 15 and 16, which Hatch said included notifications to neighboring balancing authorities that off-system sales could be curtailed.
A generation maintenance outage recall was issued ahead of the second heat wave, followed by hot weather alerts starting in PJM West on July 22 and for the whole RTO the following day. Maximum generation and load management alerts were issued for July 24, 25, 28, 29 and 30. Pre-emergency load management was called July 28 for the BGE, PEPCO and Dominion zones, expanded to the full RTO the next day, when all available long- and short-lead DR was called.
Synchronized Reserve Performance Inquiry
The Independent Market Monitor presented the results of a poll of resource owners who saw their units underperform during the July 1 synchronized reserve performance inquiry, which saw 79.5% response for individual resources. The event lasted 10 minutes and 38 seconds, with 2,398 MW of generation and 544 MW of DR assigned.
Joel Romero Luna, of Monitoring Analytics, said the owners of 33 underperforming resources were contacted and responses covered 20 units. The single-largest identifiable cause of those units’ shortfall was inaccurate parameters having been submitted, accounting for around 50 MW of the 581-MW shortfall. Around 225 MW of shortfall was categorized into an “other” category due to the number of resource owners falling below the confidentiality requirement of at least four generation owners providing the same information, allowing anonymized aggregation.
He said outreach to generation owners is continuing with the goal of increasing the response rate.
July Operating Metrics
PJM saw an average hourly forecast error of 1.7% for July and an average peak error of 1.78%, according to the RTO’s monthly operating metrics. The 3% daily peak error benchmark was exceeded three days, with over-forecasting on July 19, 24 and 26 attributed to storms causing load to come in lower than expected.
The month saw four spin events, two shared reserve events, seven maximum generation and load management alerts, five pre-emergency load management reduction actions, seven shortage cases, 10 hot weather alerts and 39 post-contingency local load relief warnings. All the shortage cases occurred July 28, with one primarily due to generation loss and six due to solar generation falling faster than load was expected to decline between 6:59 p.m. and 7:25 p.m.
Two of the spin events exceeded 10 minutes, allowing the RTO to begin measuring a rolling average to track synchronized reserve performance for the purpose of potentially backing down a 30% adder to the reserve requirement. PJM established the adder in May 2023 to address poor reserve performance, which PJM aimed to address through changes to reserve deployment implemented in December 2024.
In March 2025, PJM began measuring reserve performance, backdated to December 2024, and created a paradigm under which the adder could be reduced if reserve performance is above 75% across a rolling average of three events exceeding 10 minutes.
Under that model, the adder would be reduced by 10% if performance across the rolling average is between 75 and 85%. It would be reduced by 20% if the average is between 85 and 95%, and it would be eliminated at performance above 95%. The adder could be increased by 10% if performance falls below 75%, but the reserve requirement must remain within a 100-to-130% band. (See PJM OC Briefs: March 6, 2025.)
The July 1 and 22 events, paired with a spin event Feb. 5, carry an average of 74.4% performance, meaning the adder remains untouched. For the next event to reduce the adder by 10%, performance would need to be 66.7% or greater; performance at 96.7% or greater would result in the adder being reduced by 20%.
The July 22 event lasted 10 minutes and 32 seconds and saw 2,764 MW of generation and 548 MW of DR assigned, with performance at 79 and 80% respectively. A July 30 event last 5 minutes and 57 seconds, with 3,588 MW of generation and 328 MW of DR assigned, with performance at 59 and 72% respectively; the next day another spin event was declared lasting 6 minutes and 16 seconds, with 2,802 MW of generation and 582 MW of DR assigned, with 45 and 63% performance.
Generation Deactivation Manual Revisions
The Operating Committee endorsed by acclamation revisions to Manual 14D: Generator Operational Requirements to rework the requirements for a resource requesting deactivation. The proposal will advance to the Markets and Reliability Committee for a first read at its Aug. 20 meeting, followed by endorsement on Sept. 25. (See “1st Read on Manual Revisions Detailing Generation Deactivation Process,” PJM OC Briefs: July 10, 2025.)
Resource owners would be required to provide PJM with at least one year’s notice before going offline and follow the must-offer exemption process if they are seeking to not participate in the capacity market. The proposal also expands transparency requirements, mandating that resource owners entering into a reliability-must-run agreement with PJM provide the RTO and the Monitor with an estimate of the costs that would be recovered under the agreement, which would be publicly posted. Ongoing monthly updates would be required during the term of the RMR agreement. The Monitor also would publicize market power letters.
The language would remove a $2 million cap on project investments allowable under the deactivation avoidable cost credit (DACC) compensation methodology, limit the adder for investments to 10% and remove language causing the credit to be determined through the daily deficiency rate rather than the deactivation avoidable cost rate (DACR) when the DACR and applicable multiplier exceed the deficiency rate.
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.
