Search
February 25, 2025

Posted on

EIPC: Transmission Studies Need More ‘Granularity’

The Eastern Interconnection Planning Collaborative on Feb. 24 urged FERC to not use NERC’s Interregional Transfer Capability Study (ITCS) “as a metric for determining prudent additions” to transfer capability on the grid (AD24-5). 

In comments filed with the commission on the study, EIPC — an association of 18 planning authorities from the Eastern and Central U.S., including PJM, ISO-NE, NYISO, Duke Energy, Dominion Energy and the Tennessee Valley Authority — also commended NERC for the “enormous task” carried out by the ERO in a short time frame, and thanked the organization for working with industry stakeholders during the study. 

NERC submitted the final installments of the ITCS to FERC in November, ahead of the December deadline set by Congress in the Fiscal Responsibility Act of 2023. (See NERC Files ITCS to FERC, Meeting Congress’ Deadline.) In the FRA, Congress directed NERC to submit to FERC a study detailing current transfer capabilities across the North American grid, recommendations for prudent additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability. 

The ERO’s final report, submitted in three parts — with a fourth component focused on Canada planned for release this year — recommended a total of 35 GW of additional transfer capability across FERC’s transmission planning regions. NERC Director of Reliability Assessments and Performance Analysis John Moura said the ERO had to use its discretion to narrow the FRA’s broad requirements to a workable framework; for example, NERC’s definition for “prudent” additions focuses on reliability rather than economic factors. 

EIPC’s comments acknowledged that NERC had “relatively little time to develop a study methodology, gather the required data, consult stakeholders, execute the study and validate results” and that the limited time required the ERO to “change and reduce the scope of its study.” EIPC also said it appreciated that NERC went out of its way to coordinate with grid stakeholders through the ITCS Advisory Group. 

However, the collaborative did express concerns about the study — partly regarding its methodology, but mainly that large transfer capability studies like the ITCS are inherently unsuitable “to drive transmission upgrades on the power system.” EIPC pointed out that transmission service providers (TSPs) and transmission planners “have a more in-depth understanding of the current and planned transfer capability on their system” than NERC. 

“Decisions on the value of specific transmission improvements are complex, and they must consider all the factors regularly evaluated by TSPs, transmission planners and resource planners,” EIPC said. “This goes beyond the factors considered for transfer capability in [large transfer capability studies]. For example, available capacity, the feasibility of upgrades, the potential for excess generation and cost allocation must be considered to ensure investments are prudent and aligned with a beneficiary-pays methodology.” 

EIPC emphasized that it “shares the same goals as FERC, NERC and the rest of the industry” regarding improving grid reliability through interregional transfer capability, and that it also believes investments in transfer capability can add value to the grid “at appropriate costs.” However, it also cautioned that despite providing “interesting insights,” large-scale “snapshot-in-time” studies like the ITCS lack “the appropriate granularity” to make useful recommendations. 

Calling the ITCS “not directly actionable,” EIPC suggested that federal and state regulators and policymakers seek input from “planning entities responsible for analyzing transmission security and resource adequacy needs” when determining interregional transfer capability needs. In addition, EIPC said that prudent additions should be assessed in terms of cost, not just their reliability benefits. 

EIPC also recommended that FERC work with state regulators on metrics to guide decision-making on increasing interregional transfer capability. The collaborative stopped short of defining the metrics itself but suggested that they include factors such as specific needs that a proposed expansion could address, whether the potential reliability benefits exceed the projected cost of the project, and the feasibility of the proposed project to meet the identified need. 

In a separate statement, EIPC said its members “stand ready to provide technical assistance” for the Eastern Interconnection if FERC decides to pursue such a metrics project. 

Posted on

PJM MRC/MC Briefs: Feb. 20, 2025

Markets and Reliability Committee

Voting on Site Control Requirement Manual Revisions Deferred Pending Settlement

VALLEY FORGE, Pa. — Stakeholders in the Markets and Reliability Committee (MRC) voted for a third consecutive meeting to delay acting on revisions to Manual 14H intended to clarify when developers may add or remove parcels from their project footprint. PJM and EDF Renewables stated they’re working toward resolving a complaint filed on the matter (EL25-22). (See “Other Committee Business,” PJM MRC/MC Briefs: Jan. 23, 2025.)

The complaint from the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United alleges PJM is violating its tariff and Manual 14H in guidance it has issued to developers around when they can change the parcels included in their projects. In past stakeholder meetings, PJM said the proposed manual revisions would codify that guidance, which renewable developers have argued is overly burdensome and would require them to retain land they have determined is unneeded.

A motion to defer voting on the manual revisions initially was rejected by stakeholders, with the 60% in support falling shy of the two-thirds sector-weighted threshold. Emma Nix, of EDF Renewables, told the committee that settlement discussions are making progress and passing the proposal would frustrate that process. The second vote passed with 82% support.

“I expect that we will have a settlement that we can share with stakeholders within the next month … things are going very smoothly,” she said.

PJM attorney Chris Holt said the RTO is limited in what it can say due to settlement confidentiality. But he confirmed discussions are progressing toward a resolution. He noted that FERC has granted an abeyance on the complaint that ends on March 10 and stated that PJM is hopeful an agreement can be reached by then. General Counsel Chris O’Hara said settlements often result in PJM committing to propose revisions to its governing documents in the FERC docket in which the settlement is made. If such an agreement is reached, those changes might not come back to the stakeholder process for consideration next month. Interested parties instead could comment on that docket.

The proposed changes would allow parcels to be added to a project at Decision Point 1, so long as the land is adjacent to the site or evidence of connecting easements is provided. Parcels also could be removed at this point, so long as the project continues to meet the minimum acreage and energy output defined in the project application. (See “Vote on Site Control Requirements Deferred,” PJM MRC/MC Briefs: Dec. 18, 2024.)

The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 by specifying that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels similarly can be added to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle.

No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement to determine permissibility.

3 Packages Advancing from ELCC Task Force

PJM presented a slate of proposals aimed at adding new generation categories to the effective load carrying capability (ELCC) framework and how analysis of changes in the resource mix and risk modeling affect class accreditation. They are the first recommendations made by the ELCC Senior Task Force (ELCCSTF), which was formed last year to consider changes in the functionality and transparency of the methodology.

Two of the proposals focus on how changes in ELCC inputs can affect resource class ratings between the completion of a Base Residual Auction (BRA) and the associated delivery year, as well as how that might interact with any capacity shortfalls that could be caused if a resource sees its accreditation reduced between a BRA and incremental auction (IA).

The main motion advancing to the MRC, Package B, would lock resources’ ELCC ratings and accreditation in at their values used in the BRA, though any changes in risk modeling still would affect the Reserve Requirement Study values used in the IAs and could cause PJM to revise the amount of capacity it procures in those auctions. The alternative, Package C, would follow the status quo of updating ratings between IAs, but would lower the penalty rate for any deficiency associated with reduced accreditation to 100% of its clearing price, down from the 120% penalty rate. The two proposals were nearly tied in an ELCCSTF poll, with Package B holding 66.5158% support and 68% preference over the status quo, while Package C received 66.5025% and 74.9% preference.

Package A was introduced by Vistra and would have capped the deficiency charge at the lesser of any change in accreditation or the equivalent demand forced outage rate (EFORd).

PJM’s Pat Bruno said Package B would remove the uncertainty associated with shifting accreditation from market sellers while retaining penalties for any shortfall in installed capacity (ICAP). He gave the example of a unit experiencing a catastrophic failure or a planned resource not entering commercial service on time still being subject to deficiency charges. Package C would retain some incentive for market sellers to mitigate any lost AUCAP.

Susan Bruce, representing the PJM Industrial Customer Coalition, argued that Package B would shift all risk to load and require load to buy shortfall capacity twice, in the BRA and IA.

“The main motion addresses a concern, and I certainly am sympathetic to the concern, but it shifts the risk to load … so I think some fundamental question should be answered here,” she said.

Adrien Ford, of Constellation, said the main motion would handle the unhedgeable risk of changing ELCC ratings more effectively than the other two options considered.

The third proposal advancing from the ELCCSTF would add two new resource classes: a waste-to-energy subset of the steam generation category and oil-fired combustion turbines (CTs). The former has an estimated ELCC rating of 83% based on the parameters used in the 2025/26 third IA, while oil CTs would have an 85% rating.

1st Read on CIFP Manual Revisions

PJM’s Joseph Tutino provided a first read on a set of manual revisions to conform with FERC’s order granting PJM’s capacity market changes drafted through the Critical Issue Fast Path (CIFP) process in 2023. The package is the second set of conforming revisions, this time focusing on generation testing requirements and adding a requirement that dual-fuel resources must offer schedules with both fuels into the energy market. (See “1st Read on 2nd Phase of CIFP Manual Revisions,” PJM MIC Briefs: Jan. 8, 2025.)

The summer and winter capability testing detailed in Manual 18 would be changed to focus on whether capacity resources are able to output their daily ICAP minus the 95th percentile hourly seasonal net output. A resource that has a daily ICAP value exceeding the tested capability during that season would be subject to shortfall charges until it is able to test to a greater capability. The addition of generation operational testing to Manuals 14, 18 and 28 would allow PJM to test a resource twice per season, plus any additional retests if a unit fails to perform. The dual-fuel must-offer requirement would be codified in Manual 11.

Ford said Constellation has worked with PJM on changes to the language to reflect permit requirements. PJM’s Skyler Marzewski said the RTO views those changes as a clarification rather than substantive change to the proposal.

Members Committee

Manual Revisions Seek to Reimagine Role of MC Webinar

PJM’s Michele Greening presented revisions to Manual 34 that would restructure the MC Webinar in an effort to shift substantive discussions to be held instead at the MC. The proposal includes a single change to revise the manual to state that “reports, briefing and non-decisional business will be conducted” to instead read as “may be conducted,” allowing for more flexibility.

Vistra’s Erik Heinle said the webinar is a useful venue and should continue. But some stakeholders have grown concerned that topics discussed there are more appropriately addressed before the broader attendance that the full committee sees. In particular, he said the monthly reports the Independent Market Monitor provides should be moved to the MC.

Tom Hyzinski, of the GT Power Group, provided an example from the March 18 MC Webinar to highlight the concern raised by Heinle. Hyzinski said that although it was not covered or even noticed in the Market Monitoring Report that was posted, the Monitor mentioned at the webinar that PJM had unilaterally increased the amount of reserves they carry some time ago. That increase needs to be addressed, he said, suggesting the additional reserves PJM procures are inappropriately increasing consumer costs. Hyzinski said PJM staff were not present to refute those claims or offer alternative perspectives. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)

Monitor Joe Bowring responded that the argument he voiced during the webinar was that there are communication issues between PJM dispatchers and generation owners that have led to reserves underperforming and that resolving that issue would obviate the need for the higher reserve requirement. Rather than moving the reports to the MC, Bowring suggested it may be more effective for webinar participants to request that discussion of materials presented be added to the MC agenda when warranted.

Stakeholders Discuss Synchronized Reserves

PJM’s Mike Bryson said PJM may lower its synchronized reserve requirement if a trend of increased performance holds up. The RTO increased the requirement by 30% in May 2023 to address low performance. That change may be reversed if five consecutive spin events see 100% or higher performance. In response to stakeholder questions as to whether PJM will continue to monitor reserve deployment and consider ongoing changes to the requirement, Bryson said the focus is getting back to the standard procurement target before considering next steps.

Bowring said he’s glad to hear PJM is considering the change and he’s hopeful changes to how reserves are deployed will improve performance to where the baseline requirement is sufficient for PJM. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)

Both Bowring and Bryson said the dialogue they had with generation owners whose units underperformed yielded helpful insight into what was driving the issue, and ongoing coordination would be beneficial.

Posted on

Report: Trump Executive Orders Put 43 GW of Wind Projects at Risk

A report released in February by Aurora Energy Research has found that President Donald Trump’s executive orders have put 43 GW of East Coast offshore wind projects at risk of permitting delay. 

The report found most of the orders, issued on Trump’s first day back in office, would not have an immediate impact on the offshore wind industry, though it contains a summary of each, as well as of other actions by the president, and potential long-term impacts.  

Of more immediate concern to the industry is Trump’s halt on onshore and offshore wind power leasing and permitting and directed agencies to review existing ones. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

“Our biggest concern with the executive orders in particular is not in necessarily in the long term, but the potential for permitting risks for the projects that are already under development or already have leases downstate,” said Julia Hoos, head of USA East for Aurora. 

The report examined the status of more than two dozen projects and compared their risk profiles under the moratorium. It ranked projects by development phase, with those under construction deemed the lowest risk. Projects that had approved construction and operations plans were deemed medium risk. Low- and medium-risk projects include 5.1 GW and 5.9 GW of nameplate capacity, respectively. 

Projects that were still going through the permitting process were deemed high risk. This is the bulk of the current projects both numerically and in capacity, with 32 GW at risk.  

“For projects that are more advanced, it would be pretty unprecedented for those projects to run into additional challenges,” Hoos said. “But the language of the executive order is so aggressive on revisiting the legitimacy of the leases and permitting that it’s not out of the question.” 

Hoos said the executive order had caused “real nervousness” for projects that are currently working on their permits because a full blockage right now could lead to a cancellation. For projects not fully blocked, developer costs would almost surely escalate. 

Dan Shawhan, a fellow at Resources for the Future and adjunct assistant professor at Cornell University, said Aurora’s analysis “seemed reasonable” to him. 

“Based on comments Trump has made, it seems like he’s interested in stopping offshore wind for as long as you can,” Shawhan said.  

He advised developers and states trying to build offshore wind to “pick their battles to live to build another day. They should challenge the parts of this that they think they might be able to overturn or overcome by court challenge. They should take advantage of this time to prepare to build after the Trump administration.” 

New York Reliability Risks

The report includes a section on New York’s energy future, citing 7.5 GW of at-risk projects against a backdrop of downstate fossil fuel plant retirements. 

It found that delaying key offshore wind projects could push the state back toward combined cycle gas turbine plants downstate by causing increased energy prices and reliance on imports from PJM. The analysis assumes a “strong enforcement of the peaker rule,” meaning that old peaker plants would be retired. 

“Demand is expected to grow in the winter with more heating electrification,” Hoos said. “Assuming the state doesn’t allow for that generation to be replaced by gas, which feels very likely given the last several years of policy, then reliability downstate is dependent on bringing in batteries and bringing in new generation.” 

Hoos said offshore wind was the most feasible path for new generation to be brought online in downstate New York. Delaying those projects poses “real risk” to the region. 

Shawhan said New York could avoid falling back on gas and imports if they accelerated solar development or other onshore renewables, but unless the state acted, it would likely be forced to increase fossil generation. Transmission projects that support renewables might also see increased attention from the state. 

“Transmission development usually takes a long time, about a decade,” Shawhan said. “There are projects in development that might or might not be built, and this would tip the balance in favor of them being built.”  

“NYSERDA will carefully review federal actions regarding offshore wind development,” a spokesperson for the New York State Research and Development Authority said in an email. “It is too soon to determine what impact, if any, federal actions might have on New York reaching its ambitious renewable energy targets.” 

Posted on

Analysis: Sluggish PJM Reforms Cost Consumers Billions

A new Advanced Energy United/Grid Strategies report estimates that better PJM interconnection processes could save consumers billions of dollars. 

The authors say the system’s inefficiencies raised the cost for consumers as much as $7 billion just in PJM’s latest capacity auction. 

They say the problem will persist for PJM without reforms, but add that the situation is not unique to PJM: Regional operators nationwide should see the auction as a warning sign and should expect similar repercussions if they do not address projected generation and transmission needs. 

The Pacific Northwest, SPP, MISO, ERCOT and Georgia Power are seeing notable demand growth, the report states, along with PJM. 

“Penny wise and pound foolish: PJM’s Capacity Auction Demonstrates the Cost Imperative of Simplified and Speedy Interconnection” was prepared by consulting firm Grid Strategies for the clean power trade organization Advanced Energy United. 

Co-author Rob Gramlich said the title derives from the process by which PJM (and other RTOs) allow interconnection of new generation assets. 

“Typical interconnection processes are ‘penny wise’ but ‘pound foolish,’” he said in AEU’s announcement of the report. “As illustrated by the data from PJM, grid operators are slow and methodical, which means they provide detailed cost responsibility accounting, but the associated length of time to connect new generation contributes to scarcity and raises consumers’ rates.” 

Despite FERC’s push for proactive transmission planning, the report states, most regions still have reactive transmission planning and interconnection processes in place.  

As a result, generation is added slowly and capacity market prices rise. 

The report highlights the glaring example: PJM’s latest capacity auction, in which the clearing price rose 833% from the 2024/25 Base Residual Auction (BRA). (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

The total cost to consumers was $12.5 billion higher than in the previous BRA, but it could have been as little as $5.5 billion higher, the authors state, had PJM begun proactive transmission planning and simplified its interconnection process years ago. 

Updated resource accreditation numbers and new market rules around extreme weather effects factor into the equation, but the report focuses heavily on the basic laws of supply and demand: Load is growing, existing generation is retiring and new generation is coming online too slowly. 

Supply offered in the 2025/2026 BRA was about 6.6 GW lower than in 2024/25, while estimated peak load demand was about 3 GW higher. 

The report notes that PJM interconnection service requests totaled well over 200 GW at the end of 2023 and estimates that 68.6 GW of accredited capacity is in the PJM interconnection queue.  

But very little of that has been coming online. Only about 3 GW was placed in service in 2022, less than 5 GW in 2023 and less than 2 GW in the first 8.5 months of 2024. 

The report is backward-looking and analyzes how past cost increases might have been minimized had reforms been enacted earlier. But looking forward, the authors suggest PJM’s partly complete, multiyear interconnection reform process may not prove significantly more efficient when it finally is finished. 

Broader strokes are needed nationwide, they write: “While much of the discussion around the exorbitant price tag has treated [the 2025/26 BRA] as a one-off issue that can be fixed by tweaks to market rules, the issue is more fundamental. … Regions across the country should expect to face similar repercussions if they do not address the generation and grid infrastructure needs posed by increased power demand.” 

Independent Market Monitor

Independent Market Monitor Joseph Bowring said he does not agree with the report’s central thesis: that queue issues are a primary cause of higher prices in the PJM capacity market.  

He does agree that faster and more efficient interconnection processes are needed, and he told RTO Insider that PJM should have begun pursuing them earlier. 

But he disagreed with some other points and conclusions in the report: 

    • Historical data on PJM’s inefficient interconnection process is not a good guide to how the new and improved rules will work. 
    • The problems with PJM’s interconnection queue are due partly to developers crowding it with weak and/or duplicate projects unlikely ever to reach construction. 
    • Most of the proposed resources in PJM’s queue are intermittent, and while they would provide critically needed power, they cannot solve reliability issues. 
    • The report overstates the impact of supply-and-demand fundamentals in the last auction. 

Bowring also noted the most recent regulatory changes may change the picture painted by the report.  

For example, FERC on Feb. 11 approved PJM’s Reliability Resource Initiative, which will allow PJM to move resources ahead in the queue if they are close to commercial operation. This should help, he said, and PJM should strengthen this approach. 

FERC also just approved PJM’s surplus interconnection service proposal to permit the more efficient use of existing transmission capacity, Bowring noted. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.) 

Posted on

California PUC Approves Portfolio Incorporating Clean Energy, Storage

A California electric resource portfolio that incorporates 63 GW of clean energy and new storage by 2035 has received approval from state regulators and will be sent to CAISO for use in its 2025/26 transmission planning process. 

The California Public Utilities Commission voted 4-0 on Feb. 20 to approve the portfolio, which as modeled reaches 99% clean energy serving retail load by 2035. The portfolio projects a decrease in natural gas generation in the CAISO system, with a 71% drop from 2026 to 2035 and an 80% reduction by 2040. 

“This is an extremely promising glimpse of a possible future,” Commissioner John Reynolds said before the vote. 

The electric resource portfolio is an annual exercise for the CPUC, which described it as a “key input” into CAISO’s transmission planning. In addition to a “base case” portfolio, the commission approved a “sensitivity portfolio” that incorporates a larger amount of long-lead time resources, such as geothermal energy, offshore wind and long-duration energy storage.  

Wind Study

The commission’s decision also asks CAISO to study “but not yet trigger the investment in new transmission to support some out-of-state wind and Northern California wind” outside of the CAISO balancing authority area. 

The decision noted that the amount of out-of-state wind on new transmission in the 2025/26 portfolio has increased to 9 GW in 2035, up from 6 GW in 2034 in last year’s portfolio. Sources of out-of-state wind include New Mexico and Wyoming. 

“The new amounts, if fully developed, will require additional transmission beyond those projects that are already approved and in development, including SunZia, SWIP-North and TransWest,” the CPUC said in its decision. 

The additional transmission could be “complex to accomplish” and “require regional cooperation,” the decision said. 

Another issue discussed in the decision is the deliverability of energy from offshore wind (OSW) along the Northern California coast. Most deliverability on existing Northern California transmission has been allocated to resources now in the interconnection queue, the CPUC said, pointing to battery storage projects in particular.  

“If … CAISO does not reserve some deliverability for OSW and ensure there is adequate transmission available for that deliverability, it will all be used by the storage in the queue,” the CPUC said. But adding transmission for OSW runs the risk of overbuilding “at considerable cost,” if all the resources are not developed. 

The decision directs CPUC staff to work with CAISO to identify storage projects with transmission plan deliverability that could have the biggest impact on OSW in the area. 

Building the Portfolio

The CPUC built its electric resource portfolio using information from 2022 integrated resource plans filed by utilities under its jurisdiction, plus additional identified resources. 

The base case is “reliability- and policy-driven,” according to the CPUC. For example, it factors in a greenhouse gas emissions target for the electricity sector of 25 million metric tons (MMT) by 2035. 

And the two study years for the base case portfolio, 2035 and 2040, satisfy the 0.1 loss of load expectation (LOLE) standard. The process also includes busbar mapping, which identifies locations of electricity generation and storage. 

Along with its base case portfolio, the CPUC also typically develops a sensitivity portfolio as a “reasonable alternative” for CAISO to evaluate. 

Last year’s sensitivity case was a high natural gas retirement scenario, which the CPUC said was “designed to assist in planning for the potential future retirement of fossil-fueled resources.” 

Posted on

SPP Promotes Abbas to Senior VP, CTO

Felek Abbas | SPP

SPP has promoted Felek Abbas to senior vice president and chief technology and security officer, combining his current duties as CSO with responsibility for information technology and corporate facilities. 

Abbas joined SPP in January 2024 as vice president and CSO, overseeing SPP’s cyber and physical security, emergency management and business continuity. He takes over the IT responsibilities of Sam Ellis, who retired in February. 

“Given the rapidly increasing changes and risks confronting our industry, it’s essential we have the very best leading our pursuit of transformative technology,” said incoming SPP CEO Lanny Nickell.  

Abbas has more than 30 years of electric industry experience in cybersecurity, engineering, consulting, risk management, audit and compliance. Previously, he was senior manager of cybersecurity for power and utilities at Ernst & Young. Abbas also has served as a NERC critical infrastructure protection compliance adviser and auditor.  

Posted on

PJM Stakeholders Endorse More Detailed Demand Response Modeling

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed a proposal to rework how demand response (DR) resources are modeled in PJM’s effective load carrying capability (ELCC) framework, most significantly by replacing the availability window with round-the-clock profiling of DR load.

The proposal received 74% sector-weighted support and was approved by the Members Committee Feb. 20 as part of its consent agenda. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025.)

The revisions to the Reliability Assurance Agreement and Manual 20A are envisioned to more accurately align the capability of DR resources with the times reliability risks are most pronounced, particularly in the winter when a greater share of risks lie outside the 6-9 a.m. seasonal availability window. PJM’s Pat Bruno said about 17% of loss of load hours fall outside the availability window, having a significant impact on DR accreditation.

The package also would redefine the winter peak load (WPL) for DR participants to be measured at a set hour PJM believes best reflects the resource class’s overall ability to match system needs. Because individual resources’ WPL are measured at their highest point, regardless of time, adding them up to form a class-wide peak load would overstate the amount of curtailment capability there is, because those peaks would not necessarily coincide.

The third component would model the expected curtailment capability each DR resource is expected to provide by hour to reflect lower potential overnight in the ELCC and risk modeling analyses.

Bruno said the proposal would improve reliability, increase DR parity with generation by recognizing capability in all hours, capture more load and reduction capability, and improve the incentives for curtailment service providers to sign up customers that have more capability to curtail throughout the day.

The proposal targets implementation in the 2027/28 Base Residual Auction (BRA), which DR providers and consumer advocates argued waits too long to unlock the resource’s potential to mitigate tightening supply and demand in the capacity market. An alternative would have made the changes effective for the 2026/27 BRA. But some stakeholders argued that would complicate planning parameters and rules already subject to many changes with just months before the auction is set to be run in July. Bruno said PJM preferred the alternative to realize the reliability and risk modeling benefits sooner.

Calpine’s David “Scarp” Scarpignato said any change to the timeline on which planning parameters would be published would disrupt the ability for load serving entities to engage in bilateral transactions ahead of the auction, noting that the “R” in BRA stands for residual in recognition of its role in procuring capacity not secured through those trades.

“Even when it’s in our financial interest, we don’t always propose moving these parameters around,” he said. “You’re screwing up the market when you’re moving these timelines around like people are talking about.”

Had the alternative been endorsed, Bruno said PJM would have sought expedited treatment at FERC to minimize any impact on the planning parameters. Were that not granted, he said PJM could either publish two sets of parameters with and without the changes or delay publishing specific parameters that could be impacted by the filing. Those parameters are the installed reserve margin, forecast pool requirement, accredited unforced capacity factor, RTO-wide reliability requirement, and the capacity emergency transfer objective.

CPower’s Aaron Breidenbaugh said the proposal goes beyond paper changes to the amount of capacity DR could provide. Eliminating the availability window would require participating consumers to be ready to curtail at any time, he said, including hours they are not accustomed to thinking about.

“There’s going to be a lot of effort to try to accommodate that, but that’s exactly where the reliability benefit comes from,” he said.

Susan Bruce, representing the PJM Industrial Customer Coalition, said the 74% support for the package undercounted support for the actual changes proposed. Because the MRC votes on the main motion first and alternatives are considered only if that fails, she said some consumers voted in opposition in an effort to have an opportunity to vote on the faster implementation included in the alternate.

Market Monitor Joe Bowring opposed the PJM proposal. He noted that PJM does not use DR’s actual performance during the same critical hours that are used for all other capacity resources.

“The experience with DR during Winter Storm Elliott demonstrated that customer loads were already very low when DR was called and that DR provided only a very limited response,” he said in an email to RTO Insider. “PJM is crediting DR with an ELCC higher than gas fired combined cycles because PJM is assuming a response that is not supported by the data. PJM treats DR as an emergency only resource unlike all other capacity resources.

“PJM does not know the nodal location of DR. PJM simply ignores increases in DR load above WPL for DR when it is called. PJM fails to apply the same DR ELCC method for the summer as it proposes to apply in the winter. There is no reason to make an expedited and inadequately supported change to the DR ELCC while ignoring other ELCC issues. All ELCC issues are interdependent and should be part of an overall review,”

Bowring said the Monitor estimated that DR resources would be paid about an additional $235 million under the new ELCC if the next auction clears at the maximum price, an increase of about 36%. He agreed with PJM’s proposed use of a single coincident peak hour, elimination of the aggregate scaling factor and expansion of the performance obligation to all hours of the year.

Posted on

FERC OKs CAISO Implementation of EDAM Access Charge Rules

FERC has approved CAISO’s proposal for implementing the Extended Day-Ahead Market (EDAM) “access charge” within its own balancing authority area. 

Approved by FERC in June 2024, the access charge is a market mechanism designed to allow transmission owners (TOs) to recover revenue shortfalls they incur from transitioning their assets into EDAM, such as the loss of revenues stemming from reduced sales of short-term transmission service in the West’s existing bilateral electricity market. (See FERC Approves EDAM Tx Revenue Recovery Plan.) 

The access charge framework is available to all EDAM participants. But because EDAM is not a full RTO, each participating entity is responsible for developing its own rules for implementing the mechanism within its BAA and filing the related tariff revisions with FERC. For that reason, the commission’s Feb. 20 order covers only CAISO and the treatment of the ISO’s participating transmission owners (PTOs) (ER25-437).   

The EDAM access charge framework approved by commission in 2024 comprises a “three-component rate structure.” 

    • Component 1 allows a TO to recover revenue shortfalls related to the transition from bilateral market transmission service to day-ahead market service, including market transfers that displace revenues expected from sales of short-duration non-firm and firm point-to-point transmission service. 
    • Component 2 allows a TO recover a portion of the costs not reflected in the three-year “lookback” associated with the first component. That can include revenue shortfalls “from foregone sales of non-firm and short-term firm transmission service over certain new network upgrades and associated with the release of transmission capacity resulting from the expiration of EDAM legacy contracts,” FERC’s June 2024 order noted. 
    • Component 3 enables a TO to recoup sales losses attributable to wheeling through an EDAM BAA or the CAISO BAA in excess of the total net EDAM transfer of the BAA, with costs based on the transmission used to wheel energy completely through the TO’s system.  

CAISO-specific Elements

CAISO’s specific application of the access charge must differ from that of other EDAM participants because the ISO already is functioning with an organized day-ahead market, so its PTOs will not be transitioning out of the bilateral market upon launch. 

The CAISO proposal contains some standard elements of the approved access charge framework, such as a provision allowing the ISO’s PTOs to conduct an annual EDAM access charge “true-up” process to ensure they are compensated when other EDAM BAAs benefit from using the PTOs’ systems for transfers. 

The proposal also stipulates that each CAISO PTO will use the three-component rate structure to establish its EDAM recoverable revenue requirement within its existing high- and low-voltage transmission revenue requirement. The aggregate of those estimates will make up the “EDAM recoverable revenue” for the entire CAISO BAA, the ISO said. 

But because CAISO already has a day-ahead market, application of the three recovery components will differ from other EDAM participants.  

For example, in non-CAISO BAAs, Component 1 is intended to capture an “approximation” of transmission services displaced by EDAM transfers — such as firm or non-firm point-to-point transmission services. But those services don’t exist in the ISO. Instead, a similar displacement will occur in CAISO when scheduling points at the ISO’s border are converted into internal interties in EDAM. 

As CAISO explained in its filing, the wheel access charge (WAC) revenues that ISO PTOs historically have collected at those scheduling points no longer will accrue when those points become EDAM internal interties. To compensate for that lost revenue, CAISO proposed to allow each PTO to include within its Component 1 estimate the “appropriate portion” of historical WAC revenue for each scheduling point that corresponds with an EDAM internal intertie, subject to a true-up calculation. 

“CAISO states that this is the equivalent of the limit equation established for the EDAM transmission owners under the accepted EDAM framework, but reflects the unique situation of the PTOs in CAISO,” FERC noted in its order, which accepted the ISO’s treatment of all three rate components with no requested changes. 

“We find that CAISO’s proposal is appropriately tailored to the unique circumstances of the PTOs, which differ from that of EDAM transmission owners,” the commission wrote. “For instance, because the specific types of transmission service that Component 1 revenues are intended to capture do not exist in CAISO, we find reasonable CAISO’s proposal to enable each PTO to include within Component 1 of its EDAM recoverable revenue requirement the appropriate portion of the historical wheeling access charge revenue forgone for each scheduling point that corresponds with an EDAM internal intertie.” 

The commission also approved CAISO’s proposal to allocate any EDAM access charges assessed to the CAISO BAA by other EDAM entities back to CAISO scheduling coordinators based on their share of gross load in the ISO.  

“We find that the proposed approach allocates costs at least roughly commensurate with estimated benefits, because it allocates EDAM transmission costs to beneficiaries within the CAISO BAA in proportion to their benefit from EDAM,” the commission wrote. 

Posted on

DNV Report Charts Path Forward for Lighting Efficiency as LEDs Become Common

Energy efficiency upgrades in the commercial and industrial sector have made LED lighting so common that additional upgrades require more than just swapping old bulbs for new technology, according to a report DNV released Feb. 20. 

DNV worked with 12 power industry participants from around the country and interviewed 112 program implementers, vendors, manufacturers and lighting contractors to develop a bottom-up stock turnover model for its study, according to the report. 

“Lighting has long been a staple of energy efficiency programs, providing a low-cost and -effort means to reduce energy consumption for homes and businesses. However, the widespread availability and adoption of LEDs has eroded these savings potential,” DNV’s Richard Barnes said in a statement. “This study outlines new ways that lighting can be used to provide customers and utilities with deeper energy savings while using established and effective utility energy programs.” 

The C&I lighting market has reached the “late majority stage” on average around North America, representing 60% of lighting fixtures and 75% of national sales. 

“While a large number of facilities across North America still have legacy technologies in place, upgrading lighting in those facilities will require program adaptations to target smaller buildings in harder-to-reach communities where much of the remaining potential lies,” the report says. 

Outside of getting to those lagging areas, the report lists six areas that utilities and efficiency programs should focus on to get more efficiency as the market becomes saturated with LEDs. 

The first is to replace older LEDs with newer, more efficient models that produce more lumens per watt; that would save 1.28 million MWh. The data show a 20% efficiency improvement between baseline LEDs now and the most efficient products over the next five years. 

Advanced lighting controls, including network lighting and luminaire-level lighting without networking, would save 1.9 million MWh. The savings tend to be bigger in larger buildings with larger lighting demand. 

While past efforts have focused on switching out the lights themselves with LEDs, swapping out the entire ceiling grid with new products could save 545,381 MWh. Such complete redesigns typically require hiring a “lighting designer,” and the feasibility depends on customer-to-customer, site-specific conditions. 

“This differs from a one-for-one replacement of fixtures which often requires much less labor but cannot realize as much savings due to the persistence of improper lighting levels which only redesign can address,” the report said. 

Another option is to make it so lighting can also be used for demand management by installing controls that can dim or turn off lights based on grid conditions and power prices, which would save more money than megawatt-hours. 

Deploying UV lighting technology would help to sterilize the air in commercial buildings, which would lead to savings from HVAC systems. 

Finally, the report recommends tunable lighting that allows modulations to the spectral output or color temperature independently from the total lumen output of lights. That offers potential health benefits from human-occupied buildings and can achieve savings in the afternoon and evening hours. It also can benefit marijuana grow houses, the report says. 

Posted on

Texas Supremes Hear Arguments in Last Uri Case

The Texas Supreme Court heard oral arguments Feb. 19 from distribution utilities seeking to dismiss what may be the final lawsuit stemming from the deadly February 2021 winter storm, also known as Winter Storm Uri.

At issue is whether another Texas court should have dismissed the plaintiffs’ claims of gross negligence and intentional nuisance on the part of the utilities, Oncor, CenterPoint Energy and AEP Texas (24-0424).

More than 1,000 plaintiffs from across Texas alleged various claims against the companies that included negligence, gross negligence and nuisance following the storm, which is thought to have killed more than 200 people. Their cases were consolidated into a multidistrict litigation court, meaning they can be heard at once.

The utilities contend the claims are barred by ERCOT’s protocols governing their operations. A Texas trial court dismissed some claims but refused to dismiss those of negligence, gross negligence and nuisance. The 14th Court of Appeals in April 2024 granted mandamus relief in part, ordering dismissal of the negligence and strict-liability nuisance claims. However, it allowed the more severe gross negligence and intentional nuisance claims to proceed.

The plaintiffs’ attorney, Ann Saucer with the Nachawati Law Group, argued that the utilities failed to roll the outages during Uri, when ERCOT was desperately trying to stabilize the grid after it lost much of its gas generation. Instead, some customers were left without power for up to 80 hours.

Vinson & Elkins’ Michael Heidler, representing the utilities, said the plaintiffs “misunderstand” how ERCOT’s load-shed protocols work. He said utilities were told to avoid shedding load on lines equipped with underfrequency load-shedding circuits, which trip off if the frequency drops.

“When we get into load shedding or manual load shed, and the load shed obligation is sufficiently large, it becomes difficult, if not impossible, to rotate out the remaining load in a way that’s safe to the grid and complies with ERCOT’s load-shed protocol,” he told the court. “One of the things complainants say … is when we left certain neighborhoods on for the entirety of the load-shed event where, while others were subjected to load shedding, that’s exactly what ERCOT protocols require. We do have duties. We have regulatory duties.”

Heidler noted that the protocols require utilities maintain power to hospitals and other critical infrastructure, law enforcement and nuclear plants.

The justices appeared skeptical of the plaintiffs’ arguments that the utilities intentionally kept the lights on in some neighborhoods at the expense of others.

Justice Brett Busby | Supreme Court of Texas

“They did that because they were consciously indifferent to people freezing to death,” Saucer alleged. “The only way that I’ve heard that these defendants are defending this is to just simply deny the truth of the petitions. I haven’t heard them actually say, ‘We thought everyone was going to be OK if we left them in this cold without power for two days.’”

“I think what they’re saying is, ‘We didn’t have a choice,’” said Justice Brett Busby, who directed most of the questions to the legal counsels.

“There is no proof of that,” Saucer countered.

“That does seem to be what they’re saying,” Busby responded. “Maybe on summary judgment, if we get that far, both sides would have some evidence of that. But it doesn’t sound like they’re saying, ‘We don’t have any excuse for this.’ … They’re saying, ‘We’re required by the Nodal [Protocols].’”

The Supreme Court last year overruled an appeals court in saying ERCOT and the Public Utility Commission were within the law when they raised wholesale prices to more than 300 times above normal during Uri. (See Texas Supreme Court Rules for ERCOT, PUC During Uri.)

A decision is not expected to be rendered for several months, but the high court normally issues judgments on all proceedings it takes up. Its current term ends in late June.