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November 5, 2024

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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.

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PJM Proposes Expedited Interconnection Studies for High-capacity Factor Generation

VALLEY FORGE, Pa. — PJM presented to the Planning Committee on Oct. 8 an overview of a concept it is developing to allow high-capacity factor resources to be accelerated into the Phase 1 study period of Transmission Cycle 2 (TC2). If approved by the PJM Board of Managers and FERC, a new application window would be opened for generation developers to propose new projects.

The Dec. 17 application window for TC2 would not be changed with the goal of having little to no impact on the milestones for projects that already have been sorted into that cycle. A special session of the PC has been scheduled for Oct. 18 to discuss the proposal in more detail.

“We’ve been having a lot of internal discussions on what we can do and address the potential resource adequacy concern that we have,” PJM Vice President of Planning Paul McGlynn said, adding that the RTO sees the concept as a one-time opportunity to use TC2 to allow more resources to enter the study process to get interconnected more quickly.

Director of Interconnection Planning Donnie Bielak said staff have looked at every technical approach to getting significant quantities of capacity online soon enough, and this was the only one that met the reliability needs projected toward the end of the decade. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.)

Bielak said there would be strict reliability criteria to determine which projects are eligible, with it likely that only a “very, very select few” would qualify. More specific details about eligibility will be presented Oct. 18.

Vitol’s Jason Barker said he’s concerned about the precedent this would set and the possibility PJM may seek similar modifications to the queue structure in the future.

Barker asked if developers who are offered accelerated queue positions will be required to post security to assure timely commercial operation or if an accelerated project fails to meet the promised commercial operation dates, it will be liable for damages to prior queue participants for cost shifts caused by the discriminatory acceleration of the so-called reliability projects.

Even with expediting, he said there are supply chain issues affecting the entire industry that could affect the preferred projects.

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MISO Argues to FERC for 2nd Look at Crypto-stressed Flowgate Management

MISO wants FERC to reconsider its decision to let a jointly managed flowgate with SPP stand, with the RTO arguing the North Dakota cryptomining facility burdening the line is SPP’s responsibility alone.  

FERC in September denied MISO and Montana-Dakota Utilities Co.’s separate complaints over the Charlie Creek flowgate. The two wanted market-to-market (M2M) coordination lifted after the Atlas Power Data Center opened and brought a 200-MW load to SPP’s transmission-constrained northwestern North Dakota load pocket. MISO and MDU maintain the congestion management the data center is instigating shouldn’t extend beyond SPP. (See FERC Refuses MISO, MDU Complaints Regarding Crypto-strained MISO-SPP Flowgate.) 

In an Oct. 10 rehearing request, MISO continued to insist SPP is misapplying the two’s interregional coordination process in the joint operating agreement by insisting on interregional help for a provincial issue it is powerless to resolve (EL24-61).  

“By summarily rejecting the complaints, and by refusing to properly examine the evidence submitted by MISO and MDU, the Sept. 10 order failed to engage in reasoned decision-making, thereby allowing SPP’s unjust and unreasonable rate practice to continue unabated in violation of the FPA,” MISO said.  

MISO said its members have made more than $40 million in undue payments to SPP because of congestion on the flowgate. It pointed out the flowgate consists of two SPP transmission lines owned by the Western Area Power Administration in “a load pocket where the RTO has no regional flows and is unable to relieve congestion due to the lack of available generation.”  

MISO said it offered “extensive evidence demonstrating the local nature of congestion” in its original complaint and said SPP’s insistence on using M2M coordination to manage it is counter to good utility practice.  

MISO said FERC was wrong to read M2M coordination requirements as strictly those laid out in the joint operating agreement and not consider that the interregional coordination process dictates that M2M coordination should be reserved for issues that are regional, not local. 

“It is well-established that tariff and contract provisions should not be interpreted in isolation from each other,” the RTO argued.  

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Clean Grid Alliance Wants MISO Market Participation Rules for HVDC

CARMEL, Ind. — Clean Grid Alliance is asking MISO to incorporate rules for HVDC into MISO’s energy and ancillary services markets.  

“We think working out market participation rules for HVDC is timely and warranted,” Clean Grid Alliance Vice President of Transmission and Markets David Sapper told stakeholders at an Oct. 10 Market Subcommittee meeting.  

Sapper said many expect that the companion portfolio to MISO’s second long-range transmission plan will include HVDC lines, necessitating MISO to think about market-dispatchable HVDC.  

“The lack of rules is a hindrance to HVDC development, in particular MISO long-range transmission planning,” he said.  

The Market Subcommittee adopted the issue through general consent at the meeting.  

Sapper said HVDC lines can help quell system volatility, help deliver new resource types and improve efficiency across seams. He said HVDC-enabled resources shared between MISO zones versus from different grid operators could warrant unique rules.  

“This could get complicated, but at least the HVDC technologies are well understood,” Sapper said, adding that MISO could create a task team or force to recommend participation plans in markets. He said the work might borrow from MISO’s existing participation plan on asynchronous resources.  

Clean Grid Alliance’s ask continues a trend of MISO stakeholders asking the RTO to anticipate the contributions HVDC can make and how they could alter markets.  

The Southern Renewable Energy Association approached MISO and stakeholders at the July Resource Adequacy Subcommittee, asking them to consider that HVDC lines can be a source of external capacity. The nonprofit said lines are capable of infusing faraway generation into MISO’s local resource zones and could alter auction clearing. (See Renewable Group Asks MISO Community to Consider HVDC Capacity.)  

The subcommittee also ultimately took up the issue.

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ERCOT Board of Directors Briefs: Oct. 9-10, 2024

Although Texas recorded its sixth-hottest summer on record, ERCOT failed to set a new mark for peak demand despite loads similar to last year’s record. The grid operator came close when it registered a preliminary peak of 85.56 GW on Aug. 20, but it was later reduced to 85.12 GW. 

Dan Woodfin, vice president of system operations, told the ERCOT board that wholesale energy storage charging was included in the initial figure. ERCOT treats the charging as negative generation from a settlements perspective, he said. 

The ISO’s all-time demand mark remains 85.51 GW, set during August 2023. The ERCOT grid recorded 22 days of demand exceeding 80 GW through August, compared to 43 days of 80 GW last year. 

Natural gas prices and renewable energy helped keep prices low during the summer. Wind (27.85 GW), solar (20.83GW) and energy storage (3.93 GW) resources all set highs through August, according to Grid Status. 

More renewables are on the way. Solar and storage (155 GW each) and wind (34 GW) account for the bulk of capacity in ERCOT’s interconnection queue. The queue contains 25 GW of gas-fired capacity.

2025 AS Methodology OK’d

The board approved several measures previously endorsed by its Reliability & Markets (R&M) Committee and the Technical Advisory Committee (TAC). 

The minimum amount of ancillary service products to be procured in 2025, which will include three minor modifications to ERCOT contingency reserve service (ECRS). (See ERCOT Technical Advisory Committee Briefs: Sept. 19, 2024.) 

A real-time market price correction resulting from an incorrect recall of ERCOT contingency reserve service. Affected counterparties will receive more than $3.5 million in settlements. 

A real-time price correction after a resource was identified incorrectly as not being qualified for security-constrained economic dispatch. It will result in more than $323,000 in settlements to counterparties. 

The Public Utility Commission must approve all three actions. 

ERCOT CEO Pablo Vegas | ERCOT

The directors agreed with R&M and remanded back to TAC a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. 

The board asked TAC to gather more information on the initial market policy framework and reassess the need for the compensation mechanism introduced by NPRR649 in 2017 and whether it’s still needed in today’s market.  

TAC’s consumer segment opposes the change in its current form, saying it would reward overscheduling power that cannot be delivered. That will force consumers to subsidize insufficient hedging by other market participants in the face of changing grid conditions.

New CFO; Board Vacancies

The directors ratified Richard Scheel as an officer following his promotion as ERCOT’s new CFO and chief risk officer. Formerly the ISO’s controller, Scheel has more than 20 years of finance experience. He replaces Sean Taylor, who announced his retirement in August. 

The board also designated Scheel to join Chad Seely and Leslie Wiley as managers and officers of the two debt-financing mechanisms paying back $2.9 billion in market costs from the disastrous 2021 winter storm. 

The meeting may have been the last for independent director Bob Flexon, who says he will step down from the board when his term expires Dec. 1. That will leave the board with three vacancies. A selection committee has yet to name a replacement for former Chair Paul Foster, who left the board this year, and the Office of Public Utility Counsel (OPUC) does not have a CEO to fill its seat. 

The grid operator’s board consists of eight independent directors, two members from the Public Utility Commission, and single seats for the OPUC and ISO CEOs. Members are required by law to not have fiduciary duty or assets in the ERCOT market and to be Texas residents.

ERCOT Now on Instagram

ERCOT continues to expand its social media presence by joining Instagram, adding to its existence on X (formerly Twitter), Facebook and LinkedIn. 

“Please come and follow us,” CEO Pablo Vegas said. “That’s how you know you’re cool, if you’ve got a lot of followers.”

Board Approves 11 Revisions

The board unanimously approved a consent agenda with seven NPRRs, two changes to the Nodal Operating Guide (NOGRR), an Other Binding Document Request (OBDRR) and a single revision to the Retail Market Guide (RMGRR) that will: 

    • NPRR1188, OBDRR046: Modify the dispatch and pricing of controllable load resources (CLRs) in response to the PUC’s directive to increase the use of “load resources for grid reliability.” The NPRR revises the market-participation model of CLRs that are not aggregate load resources so they are dispatched at a nodal shift factor and settled for their energy consumption at a nodal price. 
    • NPRR1215: Clarify that the day-ahead market’s energy-only offer credit exposure calculation zeroes out negative values, with any zeroed-out values being included in the calculation of the depth percentile difference. 
    • NPRR1221, NOGRR262: Align manual and automatic firm load shed provisions; clarify the proper use and interplay of under-voltage load shed, under-frequency load shed and manual load shed; and address reliability concerns over the extent of transmission operators’ manual load-shed capabilities.  
    • NPRR1227, RMGRR181: Align defined protocol terms and add five definitions (“acquisition transfer,” “decision,” “effective date,” “gaining competitive retailer” and “losing competitive retailer”) that previously were in the Retail Market Guide (Acquisition and Transfer of Customers from one Retail Electric Provider to Another). The NPRR replaces the broadly titled terms “decision” and “effective date” with the specific terms “mass transition decision,” “acquisition transfer decision,” “mass transition effective date” and “acquisition transfer effective date” to provide clarity. The change also expands the “gaining competitive retailer” and “losing competitive retailer” definitions to apply beyond the mass transition and acquisition transfer processes.  
    • NPRR1236: Reflect Real-Time Co-optimization Plus Batteries (RTC+B) Task Force’s modifications to the reliability unit commitment capacity-short calculations and address limits in the current calculations by considering ancillary service sub-types. It changes the calculation process involving regulation down service and addresses changes required to align protocol language with recently approved NPRR1204 (Considerations of State of Charge with Real-Time Co-Optimization Implementation). 
    • NPRR1237: Document the scenarios in which market participants are required to successfully complete retail qualification testing, regardless of whether the market participant previously received a qualification letter from ERCOT from prior retail flight testing. 
    • NPRR1244: Align eligibility provisions for CLRs not providing primary frequency response (PFR) to provide ECRS. It also would include in physical responsive capability’s calculation only the capacity of CLRs when they are qualified to provide regulation service and/or regulation reserve service that requires the CLR to be capable of providing PFR. 
    • NOGRR263: Clarify that a CLR is required only to provide PFR when it is providing an AS that requires that resource to be able to provide PFR.