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October 30, 2024

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Ariz. Utilities Required to Report on Day-ahead Market Activities

When Arizona utilities file their next integrated resource plans, they’ll be required to include an analysis of cost savings and other benefits they could realize from Western regional market participation. 

And starting Nov. 1, utilities must report to regulators at least twice a year on their activities related to joining a day-ahead market. 

The Arizona Corporation Commission voted Oct. 8 to approve an order acknowledging IRPs filed last year by Arizona Public Service (APS), Tucson Electric Power (TEP) and UNS Electric (UNSE). But as part of the approval, commissioners adopted a slew of amendments that create new requirements for future IRPs. The utilities’ next IRPs will be due in 2026. 

One of the approved amendments, from Commissioner Nick Myers, requires utilities to include in their next IRPs an analysis of cost savings and other benefits resulting from regional market participation. The analysis will show the impact of market participation on utilities’ portfolio development, reserve margin, resource adequacy, reliability during extreme weather events, transmission planning and capacity needs. 

APS and TEP are members of CAISO’s Western Energy Imbalance Market (WEIM) and are weighing the choice of two day-ahead markets: CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+.  

“Most of our utilities might even be participating already in those markets by the time the next IRP is due,” Myers said during the meeting. “But I would love to see the analysis of how it’s affecting them at that point in time and, if they’re not in the market, how they think it will.” 

Myers said his amendment was in response to stakeholder requests for a market analysis in future IRPs. 

Semiannual Reporting

An approved amendment from Commissioner Lea Marquez Peterson also addressed regional market participation.  

It directs utilities to include in their future IRPs portfolios that capture the benefits of joining a day-ahead market. For their preferred portfolios, utilities must state their market enrollment assumptions. 

Marquez Peterson’s amendment also will require utilities to report on their day-ahead market activities semiannually, including “metrics and other decision-making elements.” 

The amendment had the support of stakeholders including Western Resource Advocates (WRA). 

“If we are going to decide to go into EDAM or we’re going to decide to go into Markets+, how are we making that evaluation?” Alex Routhier, WRA’s senior policy adviser in Arizona, said during the meeting. “What metrics are we using … and what benefits do we expect to capture?” 

APS and TEP have participated in the development of EDAM and Markets+. UNSE joined WEIM in 2022 through participation with TEP, which acts as its balancing authority. UNSE also has worked with TEP on day-ahead market development. 

Another Arizona utility, Salt River Project (SRP), has been involved in day-ahead market development but is not regulated by the Arizona Corporation Commission. 

Coal Plant Closures

The integrated resource plans show how the utilities plan to meet their customers’ energy needs over the next 15 years. The IRPs are updated every three years. 

The utilities forecast growing demand and at the same time are planning for the retirement of coal-fired power plants. APS pledged in its 2023 IRP to exit by 2031 from the coal-fired Four Corners plant, which it operates and partly owns. 

TEP owns and operates Units 1 and 2 at the coal-fired Springerville Generating Station and owns 7% of Four Corners Units 4 and 5. 

An amendment that commissioners adopted Oct. 8 requires APS to show in future IRPs that it has a “sufficient dependable and dispatchable capacity” to ensure resource adequacy before it exits Four Corners, where the utility has 970 MW of capacity. 

The amendment from Myers and Commissioner Kevin Thompson also requires an annual progress report from APS, starting on Aug. 1, 2025, on ensuring resource adequacy in 2031. 

The amendment initially said the dependable capacity it calls for should not include battery storage.  

But Thompson said during the commission meeting that the battery-storage restriction was dropped. He noted that technology is rapidly advancing and the commission should be consistent in applying its philosophy of being technology- and generation-neutral. 

“I don’t want to micromanage APS’ decision as they deploy new generation,” Thompson said. 

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New England Clean Energy Developers Struggle with Order 2023 Uncertainty

The suspension of ISO-NE‘s Order 2023 implementation due to FERC‘s inaction has caused uncertainty and stress for some clean energy developers in New England, who worry a significant delay in the rollout of the new interconnection process could slow the rapid deployment of renewables needed to meet state clean energy goals.   

When ISO-NE submitted its compliance package for FERC Order 2023 in May, it received significant support from clean energy associations, who praised the RTO for its “extremely robust stakeholder engagement” and willingness to consider and adopt amendments to its proposal. (See Clean Energy Groups Respond to ISO-NE Order 2023 Filing.) 

But the compliance proposal depended in part on quick approval from FERC, requesting an Aug. 12 effective date. 

While the New England grid is dominated by natural gas generation, ISO-NE’s interconnection queue almost entirely consists of solar, wind and storage resources, making reforms to the queue to address backlogs a key component of the clean energy transition. 

With Order 2023, FERC aims to streamline and add certainty to the interconnection processes, requiring grid operators to evaluate interconnection requests using group studies with pre-determined timelines.  

But in the short term, with ISO-NE’s requested effective date long past, the RTO and project developers remain in the dark regarding when FERC will rule on the filing and whether this ruling will require more work. ISO-NE’s effort to comply with the order has been on pause since early September. (See With FERC Inaction, ISO-NE Delays Order 2023 Implementation.) 

“We really need FERC to act on this and issue an order to limit the damage,” said Alex Lawton of Advanced Energy United. “The uncertainty is the biggest killer here.” 

The ISO-NE queue has been closed since mid-June and is unlikely to open to new interconnection requests until at least fall 2025. According to the RTO’s proposal, only projects that already have submitted a validated interconnection request would be able to take part in the initial “transitional” cluster study.  

Despite the cutoff on new interconnection requests, a large group of projects already are eligible to participate in the transitional cluster. According to ISO-NE, 118 projects are eligible for the cluster, totaling more than 40,000 MW in nameplate capacity.  

ISO-NE initially planned to begin the transitional cluster study Oct. 11, but it rescinded the study agreements in September due to FERC’s inaction. As proposed, the transitional cluster study process would take nearly a year from when ISO-NE issues cluster study agreements to the final cluster study report. 

Delaying the start of the transitional cluster likely also will delay the start of the subsequent cluster study, which would open after the end of the transitional process. Even if FERC rules relatively soon, the commission could require significant changes to the compliance proposal that further delay the start of the transitional cluster study. 

Ada Statler, associate attorney at Earthjustice’s clean energy program, said a short delay is not necessarily a huge deal, but “the cascade effect on the queue is really concerning.” 

While imminent FERC action is essential, ISO-NE should conduct a “careful examination” of the work they can do to move interconnection along during the delay, Statler said. She also expressed her hope that ISO-NE will communicate with stakeholders as much as possible to minimize negative impacts of the delay.  

Along with the direct delay on the start of the cluster studies, the confusion regarding timelines and what additional work FERC may require is a major challenge, said one battery developer. They added that the delay has caused significant uncertainty for a group of projects that have already signed interconnection agreements but were relying on a supplemental process included in ISO-NE’s filing to qualify for capacity reconfiguration auctions. 

An extended delay, however, could help some developers who have projects in the late stages of interconnection under the current rules.  

“The ISO is continuing to negotiate interconnection agreements for projects with completed system impact studies and, until such time as the Order No. 2023 rules are in effect, will tender a draft interconnection agreement under the current tariff to any project that receives a final system impact study report and chooses to forgo a facilities study,” said ISO-NE spokesperson Mary Cate Colapietro. 

That means some projects could avoid needing to enter the transitional cluster, potentially saving them time and money. 

“The suspension will be a problem for many stakeholders, but not all; some projects, both at the transmission scale and distribution scale, will be hoping that a delay allows studies in progress to complete and that the final order respects the studies,” said Aidan Foley of Glenvale Solar.  

Whether a project can reach an interconnection agreement prior to the start of the transitional cluster study could have a major impact on its development timeline. 

In late August, GDQ, the developer of a 203-MW battery project in Rhode Island, wrote in a petition to FERC that requiring the project to enter the transitional cluster “may cause delays in excess of a year and certainly would delay the execution of an interconnection agreement until no sooner than August 2025 (ER24-2926).” 

The delay also has created uncertainty for state-jurisdictional resources looking to connect to the distribution grid. ISO-NE has initiated changes to its planning procedures to coordinate affected system operator (ASO) studies with cluster studies, creating set windows for ASO reviews.  

“With the suspension of Order 2023 implementation, DG [distributed generation] interconnecting facilities are left without regulatory certainty of whether ASO studies will commence during the suspension period and, if commenced, whether those studies will be required to restart upon the resumption of the transitional cluster study process,” said Kate Tohme, director of interconnection policy at New Leaf Energy. 

“This uncertainty leaves DG interconnecting customers across New England at risk of loss of project viability and is a deterrent to continued DG development within the region,” Tohme added.  

ISO-NE has said it “will continue ASO study coordination according to current rules and practices until receiving and evaluating an order from the commission on the compliance proposal.” 

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PJM OC Briefs: Oct. 10, 2024

VALLEY FORGE, Pa. — The annual winter study conducted by the Operations Assessment Task Force (OATF) found no identified reliability risks for the 2024/25 season, PJM’s Mark Dettrey told the Operating Committee. 

The study will be presented in full during the OC’s Nov. 8 meeting and includes a detailed power flow analysis to determine whether conditions such as the largest gas contingency or low/no renewable output could prompt a reliability emergency. While no such issues were found, a preliminary case replicating some of the factors at play in the December 2022 Winter Storm Elliott found the RTO could fall under the reliability requirement if the high forced outage rate were to repeat. 

PJM’s Chris Pilong said the case was a “numbers game” looking at available capacity and forced outage rate without getting into the same detail as the power flow analysis. 

The power flow analysis was built on the 50/50 non-diversified peak load base case of 141,233 MW and exports of 4,462 MW. It includes a preliminary installed capacity (ICAP) of 179,821 MW and forced outages of 17,955 MW. Pilong said the capacity figures used in the analysis include resources that do not hold a capacity obligation but historically have been available, including generation not obligated to offer into the capacity market. 

The gas contingency case held a 7.1-GW reserve margin over the 90/10 diversified load forecast and a 6.4-GW day-ahead scheduling reserve requirement — the low/no renewables scenario had an 8.7-GW margin. The analysis assumed an 18-GW forced outage rate and 5.5 GW of exports. 

The extreme winter storm scenario increased the forced outage rate to 46 GW to simulate the impact of a storm similar to Elliott. Exports were cut to the 3-GW firm interchange and 7.1 GW of load management added to the modeling, resulting in the reserve margin falling 13.8 GW below target.

PJM Seeking More Prompt Data Request Responses from Generators

PJM’s Eli Ramsay encouraged generation owners to self-schedule units for cold weather preparation exercises ahead of the winter and presented an overview of the data request process, which could result in members being found in breach of the Operating Agreement if they do not respond. 

PJM will open a data request for generation owners Nov. 1 with a checklist of cold weather preparation steps and asking for any improvements that have been made to resources since Winter Storm Elliott. The request will be open through Dec. 15, with a reminder one week before the deadline. 

Generation owners who do not respond to data requests will be notified they may be in breach of the OA, with 48 hours to supply the information through a remediation data request. Pilong said the response rates for the Cold Weather Preparation Checklist and Fuel and Emissions annual survey historically have been around 80%, which has trended in the mid- to high-90% range in recent years. Pilong said the increase followed outreach to generation owners, which PJM is trying to step back from, instead relying on members to report that information when requested.

PJM’s Kevin Hatch said operators rely on generators to update their parameters in eDART when cold weather advisories are issued, which provides dispatchers with visibility into unit availability. Self-scheduled drills ensure those parameters can be relied on if a generator is needed.

Monitor Presents Results of Synchronized Reserve Performance Inquiry

Joel Romero Luna, senior analyst with PJM’s Independent Market Monitor, presented the findings of outreach to synchronized reserve resources that failed to perform during a July 8 event, finding that a majority of the shortfall was due to communication failures or delays. 

Synchronized reserve performance has lagged in recent years, leading PJM to increase the reserve requirement by 30% last year after backtracking on an earlier doubling of the target. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)

The Monitor spoke with 146 resources, representing about 93% of the total 1,755-MW shortfall during the July 8 synchronized reserve event, in an effort to better understand what led to the underperformance. More than 800 MW of shortfall could be attributed to communication issues, with most of those units following signals in PJM’s Automatic Generator Control (AGC) system. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)

Luna noted that stakeholders have approved a PJM proposal to send synchronized reserve deployment signals through AGC, which he said could address some of the underperformance seen in July. If all units following their basepoints through AGC had responded to the synchronized reserve deployment, Luna said the performance rate would have been 76%, rather than the 46% seen July 8. While that would be an improvement, he said that would remain inadequate. 

Inaccurate parameters, delayed action by plant workers, lacking knowledge of business rules and modeling issues all contributed to underperformance as well. In some cases, changes in ownership caused knowledge gaps about how to respond or resources were assigned reserve commitments for the first time and did not know how to respond. 

“We saw a lot of that: units that were not aware that they were being assigned reserves and were required to respond,” he said. 

The use of phone calls within companies to relay reserve deployment information contributed to the delays, Luna said. PJM Director of Operations Planning Dave Souder responded that the RTO’s All-Call signal results in a call to committed reserves within seconds of a deployment and the issue lies in how companies receive and process that information.

Quick Fix Proposal on Day Ahead Schedule Reserve Calculation

Hatch presented revisions to Manual 13: Emergency Operations seeking to clarify how PJM calculates the annual Day Ahead Scheduling Reserve (DASR) and uses the figure to determine when the 30-minute reserve target is insufficient. PJM proposed the change through the quick fix process, which allows a solution to be brought concurrent with an issue charge. Approval may be sought at the Nov. 8 OC meeting. 

Hatch said the reserve target does not account for the varying risks and needs PJM can experience day to day, which can result in additional reserves being needed in some circumstances. The 30-minute target is set at the greater of the primary reserve requirement, the largest active gas contingency or 3,000 MW, whereas the DASR is based on underforecast load error and generation forced outage rates. 

“We need to look for a percentage-based approach,” he said. 

Souder said the revisions would codify existing practice around the reserve adequacy run and no changes would be made to market-based reserve procurement. 

Stakeholders rejected an earlier PJM proposal to allow it to replace the 30-minute target with a formula that would select the greater of the load forecast error and forced outage rate together multiplied by the forecast peak load, the primary reserve requirement or the largest active gas contingency. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)

First Read on Several Changes to Generator Operational Requirements

PJM’s Madalin How presented a package of revisions to Manual 14D: Generator Operational Requirements drafted through the documents’ periodic review. 

New language was added requiring generation owners to provide PJM with information about changes to wind resources that may impact their characteristics without modifying the resource’s output to the extent to require going through the interconnection queue. PJM’s Joe Mulhern said information about changes in turbine technology could affect forecasting. 

The revisions also include reformatting the Cold Weather Preparation Guideline and Checklist for readability, clarifying how generation owners should proceed if they lose remote control of MW or MVAR output and clarifying the requirement that all generators must provide PJM with reactive capability curves before entering operation and complete reactive testing within 90 days after coming online. 

Several stakeholders questioned whether the changes were too substantive to be appropriate for the periodic review process and requested more time to review the language before moving to a vote next month.

September Operating Statistics

PJM experienced a 1.23% hourly forecast error in September, with a peak error of 1.74%, according to the RTO’s monthly operating report. PJM’s Marcus Smith, lead engineer for load forecasting, said Sept. 19 saw an approximately 6% underforecast due to weather forecast error, while Hurricane Helene contributed to overforecasting Sept. 27 and 28. 

Two shortage cases were approved Sept. 4 due to high load and a reduction in dispatchable generation. 

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PJM PC/TEAC Briefs: Oct. 8, 2024

Planning Committee

LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk

VALLEY FORGE, Pa. — Tom Hoatson, of LS Power, presented to the Planning Committee the third in a “trilogy” of issue charges seeking changes to PJM’s effective load carrying capability (ELCC) accreditation paradigm, focusing on aligning the capacity emergency transfer limit (CETL) with PJM’s winter-skewed risk modeling. 

LS Power presented two issue charges at the September Markets and Reliability Committee meeting addressing the transparency of ELCC and how it is applied to individual units. (See “LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance,” PJM MRC Briefs: Sept. 25, 2024.) 

The issue charge states that PJM models transfer limits for locational deliverability areas (LDAs) looking at their summer peaks, which is incongruent with a risk modeling approach that has shifted the bulk of risk into the winter. The issue charge is set to be voted on at the PC’s Nov. 6 meeting. (See FERC Approves 1st PJM Proposal out of CIFP.) 

“Having switched now to a model that assesses risk throughout the year, using a summer peak-based CETL calculation without reference to the EUE [expected unserved energy] distribution creates a misalignment between the periods when capacity is most valuable and the transfer limits for LDAs during those periods,” the issue charge reads.

Hoatson said that during the December 2022 Winter Storm Elliott, it appeared there was insufficient west-to-east transfer capability despite no such transmission constraints being modeled in the CETL analysis. The winter power flow issues were not modeled in CETL for that LDA.

Stakeholders Endorse Dual Fuel Manual Definitions

The PC endorsed by acclamation a proposal to revise the definition of dual-fuel combustion turbines and combined cycle resources to reflect the Reliability Assurance Agreement (RAA) definitions accepted by FERC in July (ER24-1988). (See “First Read on Manual 21B Revisions,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.) 

The change would allow dual-fuel resources that are capable of starting on their primary fuel before shifting to their secondary to qualify as dual-fuel. During the earlier stakeholder process, Calpine’s David “Scarp” Scarpignato said some gas units can start on a small amount of fuel already purchased and packed into the portion of the gas pipeline on generator property, even if the regional pipeline is offline. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.)

Transmission Expansion Advisory Committee

2024 RTEP Window 1 Projects Include Expansion of 765-kV Network

PJM has closed the solicitation period for transmission developers to propose projects in its 2024 Regional Transmission Expansion Plan (RTEP) Window 1, which focuses on addressing heavy power flows from west to east driven by load growth in Dominion being served by power in the western half of the footprint. 

Senior Manager of Transmission Planning Sami Abdulsalam said past RTEP windows have resolved much of the need to import power from the east and are performing well in the analysis. But load growth is continuing to accelerate and driving more transfer needs. 

“Data centers are a strong influencer toward the increasing load forecast,” he said, as well as electrification and electric vehicles.

PJM received 88 project components, with an additional six packages of components, all of which include expanding the RTO’s 765-kV network either toward the area of the Joshua Falls and Acton-Morrisville substations or into northern Virginia near the John Amos substation. The proposals include 48 upgrades of existing facilities, 40 of which are mostly new greenfield infrastructure. 

Staff will begin shifting toward building the components into a package they believe meets the regional needs most effectively, with an eye toward future expandability. Once that has been completed, Abdulsalam said Board of Managers approval of a recommended package is being targeted for the first quarter of 2025, with first reads at the TEAC expected in December and January. 

Several residents in the northern Virginia region spoke out against the proposed expansions, saying that constructability will be inhibited by the impacts to residents already being affected by several projects and asking whether new generation could be an alternative.

Status of Supplemental Projects

FirstEnergy has reduced the scope of a project to upgrade equipment at its Beaver substation in the ATSI zone to replace a 345/138/13.2-kV transformer with a higher-rated unit. The original scope included replacing two existing transformers and installing two more 138/13.2-kV units. The change reduces the project cost estimate from $12.7 million to $10 million with an in-service date of March 23, 2029. 

American Electric Power (AEP) presented a $185 million project to build two new 345-kV substations to accommodate 1,100 MW of new load in the New Carlisle, Ind., region expected to come online by Dec. 15, 2026. Both of the new substations would cut into the Elderberry-Dumont and Dumont-Olive Bypass 345-kV lines. 

Toward Elderberry, the new Larrison Drive facility would be configured as a breaker and a half, with 16 345-kV breakers and six bus ties to the new customer for $70.4 million. The New Prairie substation would be similarly configured and cost $79.5 million. 

Five overtaxed 345-kV breakers would be replaced at the Olive substation and three new breakers would be added for $29.3 million. End work also would be required at the Sorenson, Elderberry and Dumont substations for $1.72 million for each facility. A sag study and mitigation for the Kenzie Creek-Thomson 345-kV line would cost $620,000 more. 

AEP also presented a need to serve a 1,000-MW data center near Granger, Ind., which aims to come online initially with 300 MW of load in December 2027 and ramp up to its full consumption in January 2029. 

PPL presented an $81 million project to build a new 230-kV switchyard to serve a 1,000-MW customer near Hazleton, Pa. The load is expected to come online in 2027 with 250 MW, growing to 1,000 MW in 2030. 

The new Tresckow switchyard would be cut into the Harwood-Siegfried and Harwood-East Palmerton 230-kV lines for $8 million. The facility itself would cost $45 million and be configured as a breaker and a half with four bays and a 125-MVAr capacitor bank. Three 230-kV lead lines would stretch four miles to the customer for $28 million. 

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PJM MIC Briefs: Oct. 9, 2024

PJM Proposes Changes to Demand Response Availability Window

VALLEY FORGE, Pa. — PJM’s Pat Bruno presented three initial design components to rework the availability window for demand response (DR) resources. The window determines when the curtailment capability is evaluated as accredited capacity and expected to be online for dispatch. (See PJM Stakeholders Discuss DR Winter Availability.)

Demand response providers have argued the winter availability window, which spans 6 a.m. to 9 p.m., misses a significant amount of capability and artificially constrains the value DR can provide.

“As long as they commit to curtail in those hours, we believe there’s additional reliability value,” Bruno said.

PJM proposed expanding its analysis to a 24-hour availability window and creating estimated load and curtailment capability values for each hour. Separate summer and winter availability values still would be determined.

Bruno said the change would better improve incentives for curtailment service providers to enroll customers with flatter load profiles and the ability to reduce their consumption any time of day.

Calpine’s David “Scarp” Scarpignato said DR participants’ firm service level (FSL) is based on load during peak hours, and the further an increment is from that time the less accurate their FSL values will be. For DR that is offline or has significantly lower load at night, he said this could result in participants being paid to be available for curtailment when they would be offline. In the event of a performance assessment interval during the night, he said it also could result in capacity performance (CP) bonus payments to consumers that would have been offline regardless of their commitment.

“If they don’t take any action, they shouldn’t get a bonus … but if they take an action, they should get paid,” Scarp said.

PJM also proposed modifying the winter peak load (WPL) calculation to be based on load during five winter coincident peak days when modeling DR winter capability. Bruno said this would address an overstated WPL.

The third proposal would create an hourly winter DR load shape using aggregate hourly load profiles to account for the different patterns between system and DR load. No change would be made to the summer process.

Bruno said PJM plans to run effective load carrying capability (ELCC) analysis on the impact the proposals may have on resource accreditation and present the results at future stakeholder meetings.

Independent Market Monitor Joe Bowring said PJM’s proposals could create inconsistencies with generator ELCC values that are based on actual performance data for a small number of very high-demand winter hours, while DR would be accredited based on expected capability.

“Actual performance data should be used consistently for all resource types under the current PJM approach to ELCC in order to avoid creating preferential treatment for any resource class,” he said.

Issue Charge Rethinking External Resource Capacity Rules Endorsed

Stakeholders endorsed by acclamation an issue charge brought by the North Carolina Electric Membership Corp. to revise several aspects of how external, pseudo-tied generators interact with PJM’s capacity market. (See “External Resource Capacity Clearing,” PJM MIC Briefs: Sept. 11, 2024.)

Presenting the issue charge on behalf of ACES Power, Executive Director of Regulatory Strategy John Rohrbach said it seeks to harmonize the regional clearing price external resources receive with how CP penalties are calculated. Under the status quo, he said external resources are assigned to the rest-of-RTO zone when determining the clearing price they receive. But the penalty rate they are held to can be based on the specific locational deliverability area where their energy is delivered.

Responding to stakeholders questioning whether the CP penalty rate and annual stop-loss limit calculations would be in scope, Rohrbach said the issue charge does not seek to modify the calculations, but rather ensure they are applied consistently between internal and external generators.

Rohrbach said the issue charge also seeks to recognize the expected output of external resources when determining load serving entities’ self-supply obligations — in other words, counting those units toward meeting their reliability requirement.

Third Phase of Market Rules for Hybrid Resources Endorsed

Stakeholders endorsed a PJM proposal to establish rules for non-inverter generators paired with storage — the third phase of its hybrid resource paradigm. The changes are set to go for a first read at the Markets and Reliability Committee Oct. 30 and a vote Nov. 20. (See “PJM Proposes Rules for Non-inverter Hybrid Resources,” PJM MIC Briefs: Sept. 11, 2024.)

Non-inverter hybrids participating in the energy and ancillary service markets would be modeled as storage akin to PJM’s Energy Storage Resource Participation Model detailed in Manual 11. PJM’s Maria Belenky said staff examined how this would interact with gas fuel availability.

Accreditation would be based on the battery as the primary resource, while also considering the availability of the non-inverter resource. That combination may lead to a final result differing from the ELCC values for standalone storage.

Hybrids with a component that would be subject to the requirement that resources offer into the capacity market also would be required to offer.

The changes also seek to generally fine tune hybrid rules, such as allowing the generation owner to determine whether the storage component would be offered as a closed or open loop. Belenky said current rules categorize storage based on physical capability, but there may be instances where a battery capable of charging from the grid instead may be contractually limited to drawing from the generator it is paired with.

PJM Presents Conforming Revisions to Manual 28

PJM’s Suzanne Coyne presented a first read on revisions to Manual 28: Operating Agreement Accounting to codify the lost opportunity cost (LOC) payments for hybrid resources.

The changes include the formula for LOC credits and the deviation calculation. Both were added to the Tariff and Operating Agreement as part of PJM’s Phase 1 of hybrid resource rules, which was accepted by FERC in September 2023 (ER23-2484).

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Maryland Building Emission Rules Face Owner Opposition

Proposed regulations to create a benchmarking system and strict carbon emissions levels from buildings of more than 35,000 square feet in Maryland face tough criticism from real estate interests concerned with the cost, feasibility and timeline of compliance. 

The Building Energy Performance Standards (BEPS), required by the state’s Climate Solutions Now Act (CSNA), passed in 2022, cover about 9,000 buildings, which would have to begin reporting emissions and electricity use in 2025 as part of a benchmarking program. 

The rules also require that from 2030, owners take steps to comply with a three-step set of increasingly restrictive carbon emissions standards. The standards vary for different categories of buildings, but, by the third phase in 2040, require that buildings reach zero emissions. Certain categories of buildings, such as schools, water treatment plants and fast food restaurants, are exempt from the emissions standards, as are historic buildings and manufacturing and agricultural buildings. 

Environmental groups were among speakers in an Oct. 9 hearing that lauded the standards, drafted by the Maryland Department of the Environment (MDE), as essential to combating climate change. 

“Electrifying buildings is the only way to reap the benefits of transitioning our electricity grid to cleaner energy,” said Brittany Baker, Maryland director of Chesapeake Climate Action Network. “These regulations must be moved forward without any delay and without any weakening provisions.” 

Several owners of apartments in condominiums or cooperative buildings, however, said complying with the emissions reduction rules would create an excessive burden on their owners. 

Lawrence Bernard, an owner and a resident of a Chevy Chase condominium, urged the MDE to redraft the rules to create special conditions for “common ownership communities,” with less stringent standards than the general multi-unit buildings standards. 

“We have limited financial resources to achieve substantial reductions in our greenhouse gas emissions and energy use,” he said, adding that to do so would “substantially deplete our financial resources so that we cannot meet legal requirements for maintaining our building.” 

Jeanne Anderegg, president of the association at another condominium, said the organization had looked at converting the 413-unit high-rise building from gas to electricity and found the “net benefits versus the costs are totally out of line.” 

“The costs are astronomical and the physical barriers an impossibility,” she said. “Converting our boilers is not feasible, no matter how much money we throw at it, because we don’t have available space to house the boilers that would be needed.” 

She said the building would need “four times the electrical capacity we currently have. Even doing something as modest as converting glass stoves to electric ones would cost between $5 [million] and $8 million and displace residents for unknown numbers of weeks.” 

Financial Burden

Buildings are the third-largest source of emissions in Maryland, and the CSNA requires the building sector covered by BEPS to cut emissions by 20% by Jan. 1, 2030, and reach zero emissions by 2040. 

The MDE cites a study by the U.S. Department of Energy’s Lawrence Berkeley National Laboratory that concluded that about a third of the buildings covered by BEPS already meet the 2040 emissions standards. 

“As building owners implement these measures, they or their tenants may begin to save money,” said Zachary Berzolla, building decarbonization section head for MDE. 

But several speakers said they expect some building owners to take a severe financial hit under the BEPS regulations. 

Rick Briemann, owner of Atlantic Realty Group, a family-owned business that owns and operates about 2,000 multi-unit apartments, said the rules would put an “unnecessary financial burden on multi-family owners and the residents they service.”  

Compliance would cost upward of $40,000 per apartment, resulting in an increase of $600 for rents, and there are “not enough subsidies available to property owners in order to lower the investment and to keep rent levels affordable,” he said. 

Brian Anleu, a lobbyist for the Apartment and Office Building Association (AOBA) branch that represents 133,000 apartment units and more than 23 million square feet of office space in the Washington, D.C. area, expressed concern the BEPS rules would “result in deeper emissions reductions” in the first five years than does CSNA.  

“This creates a near-term crisis for building owners,” who would have to conduct “deeper levels of retrofit work than otherwise necessary.” He urged the MDE to reduce the early emissions reductions targets so building owners could “implement less costly efficiency measures in the short term while planning for electrification to meet the subsequent targets.” 

Setting Goals

BEPS supporters expressed confidence that building owners would adapt to the required changes. 

Jeannie Morris, vice president of government affairs for Vicinity Energy, which owns and operates district energy systems (which provide heat and hot or cold water from a central location to nearby buildings), said the company “fully supports” the rules. About half of the energy used by Vicinity, which serves 35 million square feet of commercial space used by hospitals, universities and other clients in Baltimore, is renewable energy, and the company expects to reach zero emissions by 2045, she said. 

That will be done through the installation of “centralized electric boilers and industrial scale heat pumps,” she said, suggesting the efficiencies from centralized systems could help meet the requirements of BEPS. 

“Electrifying every building individually in Baltimore would place a tremendous strain on the electric grid,” she said. 

Chris Parts, director of the American Institute of Architects Maryland branch, said the association’s analysis of 23,000 member projects showed they already had cut emissions by 48%, and could reach a 60% emissions reduction by 2031. 

“Having goals arms us with the information and goals to meet the targets,” he said. “Hesitation to adopt the BEPS program simply prolongs the needed transition.” 

Two speakers from religious organizations echoed the need to commit to the BEPS standards. 

Aaron Mintzes said it would cost $2.5 million to comply with the regulations at his 118,000-square-foot synagogue in Baltimore, but “we’re going to get it done.” He urged state officials to make sure buildings like the synagogue have access to federal funds from the Inflation Reduction Act and matching state funds. 

Maddie Smith, Clean Energy Shepherd at the Interfaith Power and Light for Washington, D.C., Maryland and Northern Virginia, said there had been discussion leading up to the passage of the CSNA of exempting houses of worship, which she had not supported. 

“Our faith communities want to be part of the solution,” she said. “They want to be leaders on this, and especially they want to save energy and money so that they can use their limited resources to serve their community.” 

The benchmarking data required under BEPS can help economically strapped houses of worship with their financial planning, she said. 

“It incentivizes efficient electrification, which lowers energy bills and makes sure that upgrades made are done with the newest and most efficient technologies available,” she said. 

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Batteries, Energy Transfers Support ‘Uneventful’ Summer in West

The addition of new resources and broader support from the Western Energy Imbalance Market (WEIM) led to an “uneventful” summer for the Western grid, industry experts said — despite record peak loads and July being the hottest month ever recorded across the region. 

A key factor in that success: more batteries. 

“A big benefit that we found from this summer was the growth of battery energy storage within the California ISO,” Scott Olson, director of policy, regulatory and markets at Avangrid Renewables, said during a Sept. 25 Western Energy Markets (WEM) Governing Body panel discussion. “Having 10 gigawatts of batteries … helped us to the uneventful outcome that we actually appreciated.”  

Battery storage is playing an increasingly important role as the industry continues to replace conventional resources with intermittent renewables. California will need around 50 GW of batteries to meet its 2045 greenhouse gas reduction goals, according to a CAISO special report, and it’s well on its way. Battery storage capacity in the ISO has grown from 500 MW in 2020 to 11,200 MW as of June 2024, and the WEIM includes an additional 3,500 MW. 

“Our growing battery fleet was instrumental in balancing supply and demand throughout the heat wave,” CAISO spokesperson Anne Gonzales told RTO Insider in an email.  

Pam Syrjala, senior director of supply and trading at Salt River Project, agreed that while summer was challenging due to extreme heat, conditions were better than the prior summer, largely thanks to battery storage.  

“Last summer, we were trying to implement a large number of battery resources into our system, so we were bringing on almost 450 MW of batteries” Syrjala said during the panel discussion. “This summer, we brought on probably over 650 MW of batteries, and it was a night-and-day difference.”  

Temperature variation also contributed to more manageable grid conditions, with certain parts of the West, like Southern California, experiencing above-normal but not historically high heat, compared with the central part of the state, which broke temperature records.  

“That variation, while small, was enough to tamp down demand and maintain grid reliability,” Gonzales said.  

Assistance Energy Transfers

Relying on the transfer capability of the WEIM and on the market as a whole also contributed to smooth summer operations. In a Sept. 25 market update discussing second-quarter performance, Guillermo Bautista Alderete, CAISO director of market performance and advanced analytics, highlighted that WEIM transfers were substantial, and that expansion of the market “unlocked increasing volumes of economic transfers.”  

The assistance energy transfer (AET) program, which allows WEIM areas to receive energy transfers when they don’t meet the market’s resource sufficiency requirements ahead of a delivery interval, played an important role this summer. Six WEIM balancing areas opted into the AET program in June, followed by 10 more in July and August, and nine in September. The total surcharges assessed were about $72,000 for all the balancing authorities involved.  

WEM Governing Body Chair Rob Kondziolka said that while the ISO discourages BAs from leaning on the AET program too heavily, it helped a lot.  

“Assistance energy transfers has been a great benefit, we think, to the market design,” Olson said. “We only use it in small amounts, but, boy, when it’s there relative to the alternative in the real-time market … it’s absolutely a huge benefit to us.”  

Kelsey Martinez, manager of system operations at PNM Resources, backed up Olson’s view.  

“It just allows you that peace of mind that you’re not going to have to change your operating process in the midst of an energy crisis,” Martinez said.  

The AET program was pushed by NV Energy and heavily debated in its beginning stages, said Kondziolka, who expressed satisfaction with its benefits, despite the associated costs.  

‘We Can’t Let Our Guard Down’

Even with record peaks and high temperatures, CAISO issued no energy emergency or flex alerts. And while wildfire danger was high, there were no disruptions to the bulk electric system, Gonzales said. 

California energy officials — including those at CAISO — entered summer ‘cautiously optimistic’ about grid conditions, and the ISO is approaching fall with a similar mindset, she said. (See Calif. Officials ‘Cautiously Optimistic’ on Summer Reliability.)  

“We need to be cautious about the successes of the grid this summer. We can’t let our guard down,” Gonzales said. “We were closely monitoring equipment fatigue and ambient de-rate (reduced output) from the prolonged heat waves. When generators are running at high rates of output for multiple consecutive days, we start to get concerned about equipment failure and outages. And we continue to closely track wildfire activity extending into October.”  

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ERCOT, CPS Energy Negotiating RMR, MRA Options for Retiring Units

ERCOT staff and CPS Energy continue to work “very closely” in negotiating reliability must-run contracts (RMR) for three aging coal-fired units that the grid operator says are necessary for reliability in the San Antonio area. 

General Counsel Chad Seely told ERCOT’s Board of Directors on Oct. 10 that the ISO is positioning itself to come before the board during its December meeting for a “full evaluation” of whether the directors want to select one or more of the RMR units. 

“This is a big decision for the board to evaluate the local reliability impacts that we have identified as a result of these resources going away and making sure that you have a complete set of information to evaluate the cost/benefits of what your decision may be,” Seely said. 

San Antonio’s municipal utility told ERCOT this year that it planned to retire the three coal units, which date back to the 1960s, in March 2025. However, ERCOT said the Braunig Power Station units, with a combined summer seasonal net maximum sustainable rating of 859 MW, were needed for reliability reasons and issued a request for reliability must-run proposals in July. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.) 

Complicating matters is that CPS Energy has said each unit must be inspected and repaired — consecutively, not concurrently — if it is to operate beyond its retirement date.  

Rick Urrutia, the utility’s vice president of generation operations, said the inspection outage for Braunig Unit 3, the largest (412-MW maximum summer rating) and most desirable RMR resource, will take at least 60 days. That could be delayed by long lead times for needed parts for repairs, he said. 

“That schedule can change if we find any major ‘discovery work,’ in which some of that equipment or systems has to have extensive repairs,” Urrutia said. 

Negotiations between the two parties have focused on the lost opportunity cost if Unit 3’s outage begins before any RMR service; the outage, inspection and repair processes for all three units; and the costs of any potential RMR service. 

CPS Energy agreed to move Unit 3’s suspension date up to March 2 under what ERCOT is characterizing as a pre-RMR agreement. That would improve the odds for its availability and potentially one of the other units for next summer, should the board choose that path, Seely said. 

ERCOT says the RMR units will be important in addressing the South Texas export interconnection reliability operating limits (IROLs) staff established this year. Their analysis revealed that under certain conditions, such as when high system demand coincides with an outage of a major transmission line or one or more generation units, lines that deliver power from South Texas into San Antonio could be overloaded and possibly lead to cascading outages. 

Potential RMR or must-run alternative service would reduce the loading on the 345-kV lines subject to the IROLs. 

An ERCOT solicitation for must-run alternatives (MRA) to the Braunig units resulted in one response. A 200-MW multi-hour energy storage resource responded within minutes of an Oct. 7 deadline, proposing to start in the summer of 2026 and end March 1, 2027.  

“That’s a little disappointing that we weren’t able to get more interest from the industry because ultimately, the consumers of Texas will have to pay for any type of solution the board deems appropriate,” Seely said. 

The grid operator says the ESR would provide a positive shift factor for the IROL in that it’s north of the South Texas constraint and would reduce loading. Staff will conduct eligibility and qualification analysis of the proposed MRA. 

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Stakeholders Reject Granting PJM Authority to Revise Capacity Auction Rules

VALLEY FORGE, Pa. — The Market Implementation Committee rejected a PJM issue charge that envisioned adding notice that Base Residual Auction (BRA) rules are subject to change, with two-thirds of stakeholders opposed. 

PJM Associate General Counsel Chen Lu said the issue charge was borne of a 3rd U.S. Circuit Court of Appeals March opinion. Allowing PJM to revise the reliability requirement for the DPL South locational deliverability area (LDA) after the parameter had been posted would violate the filed rate doctrine, the court ruled. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.) 

The issue charge deliverables include notice that PJM may “correct capacity auction rules, provided FERC has approved such rules,” and that such rules are known in advance of the auction “to allow those submitting offers to do so in reliance on conclusive rules and the orderly administration of the capacity market. Market sellers would be permitted to revise any pre-auction elections that occurred prior to FERC approval of any auction rule changes.” 

The scope includes adding language that there are no legal consequences associated with the posting of the planning parameters, which Lu said was intended to address the court opinion that once a posting is made, it is binding unless there was prior notice of the potential for changes. The issue charge states that member recommendation would be required for changes to the installed reserve margin (IRM) or forecast pool requirement (FPR). 

Prior to the vote, Lu said the issue charge would seek proposals allowing PJM to ask FERC to change any relevant deadlines for pre-auction activities or the commencement of the auction. If the commission granted changes to auction rules or parameters that already had been set, the issue charge called for proposals to allow market participants to revise their elections. 

Several stakeholders argued that granting PJM the change would undermine market certainty by allowing PJM to set dates certain for auction parameters and the rules defining them, only to change them after the fact. There also were questions of how much review stakeholders would have before PJM files possible changes with FERC. 

Independent Market Monitor Joe Bowring said allowing such changes to the conduct of capacity auctions would be a drastic change that would undermine market certainty and might limit the time available for the PJM and Monitor to review offers into the auction. He argued the issue charge would be an “overreaction” to the court decision. 

“PJM explicitly created a period of 60 days at the end of the offer submission process to permit anyone to take issues with market offers to FERC prior to an auction. PJM’s proposed approach could eliminate that period that was designed to reduce the probability of any party challenging auction results,” he said.  

Calpine’s David “Scarp” Scarpignato said PJM already makes changes to auction postings and parameters and questioned what additional changes would be in scope. 

Lu responded that PJM’s reading of the court opinion is that changes can be made only within the existing rules governing the auction, while the proposal would allow petitioning FERC to change those rules. 

Scarp also said the language allowing relevant deadlines and auction elections to be changed was vague, stating that modifying a parameter could change the viability of bilateral transactions or make it worthwhile for a generation owner to seek an exemption from the requirement that resources offer into the capacity market. 

Vistra’s Erik Heinle said the revisions made to the issue charge would improve market certainty and parameters occasionally may need revising when new data comes in or if it’s determined that posted data is incorrect. He added that it’s important that stakeholders are involved in the process. 

Lu pointed to FERC Chair Willie Phillips’ concurrence in the commission’s order reversing its authorization of the reliability requirement change, in which Phillips called for changes to allow for corrections of errors in auction design. (See Following Court Ruling, FERC Reluctantly Reverses PJM Post-BRA Change.) 

“This proceeding should lead all stakeholders, including both PJM and the generators that will reap the more than $100 million windfall due to the court’s decision, to take all necessary steps to ensure that we never find ourselves in this position again,” Phillips wrote. “That includes putting in place controls to ensure that a similar error does not reoccur and, should it somehow happen again, that PJM or the commission has the authority to correct that error and protect customers from such a manifestly inequitable result. Basic equity, and the public interest, demand nothing less.” 

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PJM Stakeholders Endorse Coalition Proposal on CIR Transfers

VALLEY FORGE, Pa. — The Planning Committee narrowly endorsed a coalition proposal to rework how generation owners can transfer capacity interconnection rights (CIRs) from a deactivating unit to a new resource. (See “Voting on CIR Transfer Proposals Deferred to October,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)

The coalition proposal received 51.8% support during the Oct. 8 vote, beating out a PJM proposal that received 40.6% support and a package from the Independent Market Monitor that received 11.1%.

The coalition proposal would create a technology agnostic process for new resources to replace gas generation being forced to deactivate in states with strong clean energy requirements. It has a nine-month timeline for applications to be reviewed, a replacement impact study identifying any potential network effects and the drafting of an interconnection agreement. The proposal was modified based on feedback at the Sept. 12 PC meeting to include thermal alongside the voltage and short circuit analyses in the replacement impact study.

Unlike PJM’s proposal, replacement resources would be permitted to proceed with the expedited process if minor network upgrades are identified and all resource types would be eligible. PJM’s proposal would bar storage from participating on the basis that the original generator’s deliverability analysis did not envision charging.

The coalition proposal also was revised since September to add a three-year requirement on the commercial operation date, although development milestones may be extended for delays outside the developer’s control or resources that have “industry-recognized elongated construction timelines.”

The PJM proposal would have had a longer study timeline of about 13 months and tighter requirements, not allowing any projects with “material adverse impacts,” such as requiring network upgrades or consuming transmission headroom above the deactivating generator. Any proposals with such impacts would be required to go through the full interconnection process.

Several stakeholders argued shifting projects to the queue if there are adverse impacts would be overly onerous and they instead should be given an opportunity to revise the scope of the project to fit PJM’s requirements. The coalition proposal would allow such changes to projects.

The Monitor’s proposal would have created a CIR transfer process administered by PJM where any generation project in the queue that could resolve transmission violations prompted by a deactivation would be studied in an expedited process. Generation developers also would be permitted to propose new resources or alterations of existing queue projects to resolve the violations.

When selecting projects, PJM would consider their cost, reliability contribution and construction risks such as permitting.

The Monitor’s proposal was modified since September to abide by the scope of the issue charge, which allows only proposals that focus on replacement resources interconnecting at the same substation as the deactivating resource. The Monitor’s package previously would have allowed replacement resources to be considered regardless of point of interconnection, so long as they addressed reliability issues associated with a deactivation.