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November 5, 2024

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PJM PC/TEAC Briefs: Jan. 9, 2024

Planning Committee

PJM Presents Long-term Planning Proposal

PJM presented a quick fix proposal to introduce a new long-term transmission planning approach that would include a longer 15-year horizon and consider state legislation that could affect generator participation in RTO markets. 

In giving a first read of the proposal during the Dec. 9 Planning Committee meeting, PJM’s Michael Herman said it would establish five long-term scenarios:  

    • Two base cases 8 and 15 years in advance; 
    • Two 8- and 15-year scenarios assuming a medium amount of new entry prompted by state legislation; and 
    • One high new-entry scenario looking 15 years in advance and including policy goals not backed by legislation. The proposal includes changes to Manual 14B and 14F. 

The base scenarios would focus on the grid’s future reliability needs based on load forecasting, expected generation deactivations, and new resources in the interconnection queue and expected to be online within the scenario’s horizon.  

Thermal and voltage analysis would be performed on the 8-year base scenario, replacing the existing 10-year model for voltage analysis, and would be used to inform the 5-year Regional Transmission Expansion Plan (RTEP) near-term process. Thermal and some voltage analysis would be performed on the 15-year scenario. 

PJM’s Jonathan Kern said the proposal is meant to bolster PJM’s process for addressing localized reliability issues on the transmission grid rather than targeting global resource adequacy and create new scenarios to meet various goals. The RTO also would make changes to the near-term planning process to ensure the long-term approach is harmonized. 

“We want to have an efficient planning process, so we don’t want to have a big disconnect,” Kern said. 

The current two-year planning cycle would be extended to three years to reflect the increased number of scenarios and sensitivities. 

Exelon’s Alex Stern said this was the first time stakeholders had the opportunity to review proposed manual changes. He identified three challenges that have not been addressed:  

    • How projects that address both grid reliability needs and state policy goals would fit into the planning process;   
    • How PJM proposes to delineate between local reliability and regional reliability; and 
    • Where and how economic reviews will be applied. 

PJM plans to seek PC endorsement of the quick fix proposal during its Feb. 6 meeting and, if endorsed, bring it to the Markets and Reliability Committee later that month for a first read. The quick fix process allows an issue charge and problem statement to be voted on concurrently with a proposed solution. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, expressed concerned about how often PJM has been using the quick fix process to propose manual changes in recent months and questioned the necessity of using it in this case. 

Stern said he was focused on providing substantive feedback, but conceded the manual changes likely will require a level of discussion beyond the quick fix process. He worried that questions surrounding PJM’s legal authority could put a cloud over any planning that flows from the changes, such that the long-term regional transmission planning analysis will be unable to produce feasible transmission projects. 

PJM reviewed proposed updates to the TO/TOP Matrix, which indexes standards that transmission owners and PJM must comply with and delineates responsibilities to ensure compliance. 

The changes include revisions to reflect emergency operations standards NERC approved in October under EOP-011-4, which includes operating plan requirements for emergencies related to “critical natural gas infrastructure loads that fuel a significant portion of … generation.” (See NERC Board Approves Cold Weather Standards.) 

If approved by the Transmission Owners Agreement-Administrative Committee (TOA-AC), the revised matrix would become effective April 1. 

Transmission Expansion Advisory Committee

PJM Presents 2024 RTEP Timeline

PJM is building base cases for its 2024 Regional Transmission Expansion Plan (RTEP) and accepting proposed changes to its basic assumptions, such as modeling, as long as they are expected to have a significant impact on baseline studies. It also will accept corrections to its analytical files. Feedback can be provided through March, when PJM plans to begin the baseline studies.  

The RTO seeks to open an RTEP competitive window in June or July, including a potential retool of the baseline analysis if needed. Review and approval of project proposals is planned to occur between October and February 2025. 

Supplemental Projects

Exelon presented a project to replace a 230/69-kV transformer at its Atlantic City Electric Mickleton Substation for $5.9 million. The existing transformer was installed in 1987 and is experiencing insulation wear and cooling issues. The project, which has a projected in-service date of May 31, 2025, is in the engineering phase. 

Dominion presented a $12.3 million project to construct a new 230-kV Lost City substation to serve a data center planned in Henrico County, Va. The proposed facility would cut into the existing White Oak-Techpark Place 230-kV line and has an estimated in-service date of July 1, 2025. 

FirstEnergy presented several projects to replace transformers experiencing consistent maintenance issues or at the end of their lifespan. A 230/34.5-kV transformer at the Kittatinny Substation would be replaced with a 90-MVA unit for $7 million; two 230/34.5-kV transformers at the East Flemington Substation would be replaced with 125-MVA units for $14.36 million; and a 230/115-kV transformer at the Raritan River Substation would be replaced with a 224-MVA unit for $5.4 million. The projects also include related upgrades to relaying and breakers. 

The utility also proposed a project to replace relays and conductors at its Whippany Substation for $2.33 million to replace outdated equipment lacking spare parts. 

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PJM MIC Briefs: Jan. 10, 2024

Simulation Analysis of PJM CIFP-RA Filing

PJM’s Market Implementation Committee discussed the RTO’s analysis of how proposed Critical Issue Fast Path (CIFP) filings before FERC might have impacted the 2024/25 Base Residual Auction results.

The item was originally listed as informational only, but stakeholders voted to add it as a full agenda item for further discussion.

A total of 136,232.7 MW of unforced capacity (UCAP) was procured in the simulated auction, a 11,246-MW decrease from the actual results. However, the cost to procure that capacity increased from $2.2 billion to $2.4 billion. That trend was on display in the “rest-of-RTO” region, where the clearing price increased from $28.92/MW-day to $47.70/MW-day while the amount procured fell. (See PJM Capacity Prices Jump in 5 Regions.)

“There are a lot of moving pieces here. This is in part because the changes in accreditation types hit some regions differently,” Walter Graf, PJM’s senior director of economics, told the MIC during its Jan. 10 meeting.

PJM’s Skyler Marzewski said the CIFP changes are intended to increase the reliability value of a megawatt of accredited capacity, so even with fewer megawatts clearing the auction, reliability could improve as more efficient units received capacity commitments. In regions where capacity prices declined, Marzewski said, the more efficient resources being picked up in the simulated auction could allow for the same degree of reliability at a lower price.

Calpine’s David “Scarp” Scarpignato said that may account for some of the difference, but the sharp drops in some regions indicated there must be other factors. He pointed to the Eastern Mid-Atlantic Area Council (MAAC) region, where the clearing price fell from $54.95/MW-day in the actual auction to $47.70 in the simulation, while the simulation declined 9% from the 39,303 MW actually committed.

“It’s just so overwhelming, the difference … it looks to me like the amount of reliability you’re purchasing is going down,” he said.

Several stakeholders questioned how the resource mix differed in the simulated auction, but PJM said the information was not yet available.

Marzewski said the analysis is not meant to be taken as a trend or indicative of future auction results, which likely are to be influenced by changing market conditions.

Real-time Temporary Exceptions Manual Revisions Proposed

PJM’s Lauren Strella Wahba presented proposed revisions to Manual 11, which pertains to energy and ancillary services market operations, to reflect FERC’s Nov. 30 approval of a process for market sellers to submit temporary exceptions from their unit-specific parameters.

The revisions would replace the real-time values process PJM used for market sellers to submit changes to their ability to operate according to their parameters during the operating day. (See “Temporary Exceptions Supplant Real Time Values,” PJM MIC Briefs: Dec. 6, 2023.)

Wahba said only one temporary exception should be submitted for an issue preventing a resource from operating according to its parameters. If the issue is expected to last more than 30 days, a period exception instead should be submitted with accompanying documentation showing the disruption is persistent. The market seller should notify both PJM and the IMM of any changes in the physical condition of a resource operating with a temporary exception or the ability to return to normal operations.

Because FERC’s order had an effective date of Nov. 30, Wahba said, the manual changes are conforming language codifying a practice put in place last year.

Quick Fix Proposal on Interface Pricing Points

PJM presented a quick fix proposal to revise Manual 11 to reflect existing practices for interface pricing points, a mechanism that groups buses together when calculating LMPs for energy imports to, or exports from, external areas.

The quick fix process allows a proposed solution to be brought and voted on concurrent with a problem statement and issue charge.

The revisions also would include a recommendation from the Independent Market Monitor to monitor all interfaces as needed — language that exists in the Operating Agreement but is not mirrored in the manuals.

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned the need for using the quick fix process in this instance and said PJM increasingly has been relying on the expedited process, making it difficult to ensure stakeholders fully understand changes being made.

“Here we are again, with yet again another issue that we’re using the quick fix process for without a meaningful discussion of how these changes are going to be made so people can understand them,” he said. “I want to express more and more concern about PJM’s use, and I dare say abuse, of the quick fix process.”

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PJM Requests 2nd Talen Generator Delay Retirement

PJM has asked Talen Energy to enter into a reliability-must-run (RMR) contract to continue operating its oil-fired H.A. Wagner generator, located outside Baltimore, three years beyond its requested retirement date in 2025. 

In its Oct. 16 deactivation request, Talen asked to take the generator offline on June 1, 2025, citing air quality restrictions that limit its run time and the economics of PJM’s capacity market as prompting the retirement. Wagner is configured with three oil units and one gas-fired combustion turbine; PJM’s request would retain the oil-fired Units 3 and 4, which output 305 and 397 MW, respectively. 

“The Wagner facilities’ [Clean Air Act] Title V air permit limits operation to capacity factors under 15% when operating on oil. … The combination of low margin energy market economics, low capacity prices and significant Capacity Performance penalty risk due to run hour limitations results in the economics being outweighed by the risk associated with continued operation,” Talen said. 

During the Oct. 9 Transmission Expansion Advisory Committee meeting, PJM’s Perry Ng said the RTO’s reliability analysis found that taking the 844-MW generator offline in 2025 would cause voltage and thermal violations throughout the Baltimore Gas and Electric region. The projected issues were identified when the Wagner retirement was combined with the deactivation of Talen’s 1,283-MW Brandon Shores generator, which the company also requested to go offline in 2025 and is adjacent to Wagner. 

By delaying the retirement by three years, Ng said planned transmission upgrades could be completed and resolve the violations without any new Regional Transmission Expansion Plan projects. In particular, he said a component of the $5 billion package of transmission projects that the Board of Managers approved in December would resolve the violations. That component, the construction of the 65-mile, 500-kV North Delta-High Ridge line and upgrades to both substations, is projected to be in service between 2026 and 2028. (See PJM Board Approves $5 Billion Transmission Expansion.) 

PJM has also asked Talen to continue operating Brandon Shores on an RMR contract through 2028, though Senior Manager of Transmission Planning Sami Abdulsalam said the discussions on the contract are still in progress. (See “Brandon Shores Deactivation to Require $786M in Grid Upgrades,” PJM PC/TEAC Briefs: June 6, 2023.) 

Since the start of December, Ng said an additional four generators have requested full or partial deactivation: 

    • Constellation Energy has requested deactivation of Eddystone Units 3 and 4, totaling 760 MW, on May 31, 2025. The generator is a dual-fuel resource located outside Philadelphia. 
    • Archaea Energy requested deactivation of its 11-MW, methane-powered Virginia Beach LF generator on April 1. 
    • GenOn Energy Management requested (here and here) deactivation of four CTs, amounting to 216 MW, at its Morgantown Generating Station near Newburg, Md., on June 1. 
    • Heritage Power requested deactivation of its four dual-fuel CTs at the Sayreville Energy Center, amounting to 217 MW. The company cites a New Jersey Department of Environmental Protection rule limiting emissions effective June 1, which is the date the company requests that the generator goes offline. The notice suggests the possibility the company may make modifications to the site to allow it to resume operations in compliance with the regulations or that it may permanently retire.
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PJM OC Briefs: Jan. 11, 2024

RTOs Submit Comments on EPA Rules

PJM reviewed comments it submitted jointly with other RTOs on EPA’s proposed regulations on greenhouse gas emissions from power plants to the Operating Committee during its Jan. 11 meeting.

The comments also were signed by MISO, ERCOT and SPP and largely focused on allowing them to maintain their ability to ensure resource adequacy and call on specific units during emergency scenarios.

PJM’s Gary Helm said the grid operators warned that the timeline for requiring carbon capture or hydrogen fuel blending for coal and gas resources could quicken the pace of generator deactivations. They recommended rethinking the requirements for new combustion turbine units, as EPA’s proposed rule would require that new CTs include either carbon capture or hydrogen blending when they are brought online. They argued that the infrastructure to support either of those capabilities does not yet exist. Rather than looking at what technologies exist, they urged EPA to also consider what infrastructure is available to make that technology accessible to generators. (See FERC Dives into Reliability Implications of EPA’s Power Plant Rule.)

The proposal “is pretty far reaching, and because of the stringency of the requirements, we’re looking at seeing retirements … as well as limitation on the operation of gas-fired generation,” Helm said.

The grid operators also provided recommendations for creating a “safety valve” to ensure that resource adequacy is not compromised by the rule, including identifying units that may be needed to maintain reliability; a “regional bank” of reliability credits that could be used to operate during emergencies; guidance for states to create resource adequacy and reliability plans; and direction on the agency’s thinking on the remaining useful life of assets.

System Operating Metrics

PJM saw two days outside its 3% target load forecast error during December, according to the system operations report delivered by Stephanie Schwarz, manager of markets coordination.

The RTO underforecast load by just over 4% on Dec. 3, while the forecast for Dec. 24 was about 3.5% above actual conditions. December also saw a shortage case approved Dec. 1, which Schwarz attributed to load, interchange and intermittent generation being affected by shifting weather patterns.

Two spin responses were implemented Dec. 14 and 19 lasting 12 minutes and 15 seconds and 6.5 minutes, respectively. The Dec. 14 event had an assignment of 2,712 MW and a response rate of 1,436 MW, leading to 1,276 MW of penalties being assessed. The Dec. 19 event had a full response from the 2,687 MW it deployed.

Other Committee Business

PJM Director of Enterprise Information Security Jim Gluck urged market participants to remain vigilant for possible social engineering and phishing intrusion attempts aimed at gaining access to computer systems and locking users out for a ransom. He said there have been a growing number of attacks that include individualized research into companies in an attempt to make messages more authentic, including impersonating employees.

The RTO also presented a quick-fix proposal to revise Manual 3A to change language pertaining to the Bulk Electric System to conform to NERC-approved definitions.

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Oregon RA Rules Could Favor WRAP Participation

Oregon regulators are moving closer to adopting resource adequacy rules that would incentivize load-serving entities to join the Western Power Pool’s WRAP. 

But during an Oregon Public Utility Commission rulemaking hearing Jan. 11, stakeholders continued to debate transmission forward-showing requirements and the need to allow a capacity backstop charge. 

OPUC filed the proposed resource adequacy rules in September, following an informal process that began in December 2020. 

OPUC staff contend that “resource adequacy concerns are best addressed through regional coordination,” Curtis Dlouhy, senior economist and policy analyst with the agency, said during the hearing. In particular, Western Power Pool (WPP) offers the Western Resource Adequacy Program (WRAP), the West’s first regional reliability planning and compliance program.  

FERC approved the WRAP tariff in February. (See FERC Approves Western Resource Adequacy Program.) 

OPUC’s proposed rule would incentivize WRAP participation by including more stringent resource adequacy planning for those not involved with WRAP, Dlouhy said. 

OPUC-regulated entities that are not WRAP participants would face a two-year forward-showing requirement for resource adequacy. In contrast, WRAP participants must submit resource adequacy forward showings seven months ahead of a season. WPP then evaluates the submission to ensure the participant is meeting its share of the WRAP planning reserve margin. 

“Entities not attached to a regional program have a greater resource adequacy risk and thus should be subject to uniformly stricter requirements,” Dlouhy said. 

“Staff also believes that requirements consistent with WRAP, albeit stricter, provide a clear incentive to join WRAP and thus benefit from a diverse set of energy producers that are involved in WRAP,” he added. 

Capacity Backstop Discussed

The proposed resource adequacy rules would apply to two types of load-serving entities: investor-owned utilities and electric service suppliers (ESSs). Oregon’s Direct Access program allows nonresidential consumers to buy electricity from an OPUC-certified ESS. 

In written comments, the Northwest & Intermountain Power Producers Coalition (NIPPC) said the commission should give ESSs the option to meet their resource adequacy obligations through a capacity backstop charge. Under that option, direct access customers would pay an RA charge to the utility. 

In addition, NIPPC wrote, WRAP’s firm transmission requirement is “very problematic” and shouldn’t be mandatory. NIPPC represents competitive electricity market participants, including ESSs. 

During the hearing, Greg Adams, representing Calpine Energy Solutions, said that WRAP “requires a real shift in regional transmission practices toward advanced procurement of firm transmission.” 

That’s an issue, Adams said, because of Bonneville Power Administration’s current practice of releasing substantial transmission for purchase less than seven months ahead of delivery. 

“There is significant concern with the ability of all load-responsible entities to meet the WRAP’s forward-showing transmission requirement, given the general … inability to obtain incremental, firm, point-to-point Bonneville Power Administration transmission in the forward-showing timeline — seven months in advance of the time of delivery,” Adams said. 

‘Equal Playing Field’

But Pam Sporborg, director of transmission and market services at Portland General Electric (PGE), noted that under FERC’s open access policy, “all entities are on an equal playing field when it comes to acquiring transmission rights.” She said it was unclear what was preventing direct-access LSEs from procuring long-term, firm transmission. 

“We do recognize that procuring long-term, firm transmission on an annual basis … can be more expensive,” Sporborg said. “But we believe that this is a necessary investment to provide really reliable load service.” 

As for the capacity backstop charge, PGE’s Sam Newman said the utility had concerns. 

“We are very uncomfortable with a scenario where the utilities are required to offer a backstop charge, but as a backstop charge there would be considerable flexibility for direct access load to choose or not choose to lean on that charge,” Newman said. “That puts the utilities in a difficult position.” 

Dlouhy with OPUC said there aren’t currently plans to include a capacity backstop charge in the resource adequacy rules, although that could be reevaluated later. He said the rules would be able to function without it. 

“Staff was not confident that significant excess IOU capacity or transmission existed at the moment,” Dlouhy said. 

The proposed rules also include information filing requirements. Oregon’s IOUs would be required to include a resource adequacy assessment covering at least four years in their integrated resource plans. Electric service suppliers would add the RA information to their emissions planning reports. 

Written comments on OPUC’s proposed rules are due Jan. 25 at 3 p.m. 

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NY State Reliability Council Executive Committee Briefs: Jan. 12, 2024

Gas Constraints

NYISO briefed the New York State Reliability Council Executive Committee (NYSRC EC) on an upcoming white paper to propose updates to the ISO’s resource adequacy modeling, including a recommendation to use a tiered load-based approach to estimate gas availability during the coldest winter days. 

Slated to be released by the end of the first quarter, the white paper comes in response to findings by NYISO’s Market Monitoring Unit, Potomac Economics, which found that eastern New York faces significant gas availability issues during peak cold conditions due to regional pipeline constraints. 

Con Edison’s Howard Kosel, the new chair of the NYSRC’s Installed Capacity Subcommittee (ICS), told the EC that NYISO is likely to recommend incorporating a tiered methodology based on load levels in its winter RA modeling to determine gas availability. This approach would assume no gas availability at loads exceeding 26,000 MW.  

The recommendation is based on Potomac’s observation that constraints in eastern New York during the coldest peak winter days were not being accurately modeled. Consequently, the ISO’s RA modeling during these periods was undervaluing certain generators and failing to anticipate the necessary level of gas procurement before peak winter days. 

The ICS will track the ISO’s progress and plans to share the white paper’s findings with the EC once published.  

PRR-151

The Reliability Rules Subcommittee (RRS) also briefed the EC about comments received on Proposed Reliability Rule 151 (PRR-151), which includes suggestions for adjustments to attestation requirements and the introduction of exemptions for evolving technologies. 

The NYSRC developed PRR-151 to address gaps in NYISO’s current interconnection criteria for inverter-based resources (IBRs) and establish standardized rules for IBRs larger than 20 MW. The committee endorsed industry comments on PRR-151 late last year. (See NY Reliability Council OKs Interconnection Standards for Large IBRs.) 

AES Clean Energy, Ørsted, GE and Alliance for Clean Energy New York submitted comments, aiming to ensure PRR-151 remains flexible and does not hinder the integration of IBRs in the future. 

Roger Clayton, chair of the RSS, said the plan is to modify PRR-151 based on the comments received, with the expectation that the revised rule will be presented to and approved by the EC at its next meeting in February. 

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Appeals Court Rejects Review of AEP Transmission Rates

The D.C. Circuit Court of Appeals last week rejected four Texas cooperatives’ request to review a 2019 FERC decision over American Electric Power’s (AEP) transmission rates, saying the commission properly interpreted the terms of AEP’s tariff (22-1166).

The Jan. 11 order is part of a proceeding that stems from FERC’s approval of a settlement allowing AEP to transition its rates from a historical formula rate to a forward-looking formula rate and remove directly assignable transmission costs related to generation. East Texas Electric Cooperative, Northeast Texas Electric Cooperative and Golden Spread Electric Cooperative agreed to the settlement. Arkansas Electric Cooperative Co. intervened but did not join the settlement or oppose it.

AEP’s 2020 annual update filed with FERC included the true-up calculations to be charged for transmission services provided in 2019. The cooperatives challenged the update and raised several issues that could not be resolved through the preliminary challenge process. The commission rejected several of the asserted error claims and a request for retroactive relief, leading to the cooperatives’ petition for review. (See FERC Partially Grants Challenges to AEP Transmission Rates.)

The cooperatives appealed four rulings in the order: one concerning FERC’s interpretation of the protocols to preclude relief for errors that allegedly occurred in prior rate years and three arguments that took issue with the inclusion of certain cost inputs in the 2019 charged rate.

The appeals court agreed with FERC that refunds for errors made in previous rate years are barred under its governing protocols and that the protocols are controlling. It rejected the cooperatives’ other three arguments, saying FERC’s order is reasonable and “adequately explained.”

“We are ‘particularly deferential to the commission’s expertise’ in making highly technical rate classifications,” Circuit Judge Florence Pan wrote.

Pan was one of three judges who heard former President Donald Trump’s immunity claims from criminal charges Jan. 9.

FERC Approves SPP Revisions

FERC on Jan. 11 accepted SPP’s tariff revisions that clarify the RTO’s multiday reliability assessment (MDRA) process, how the day-ahead market consumes commitments made through the process, and how those commitments are compensated through settlements (ER23-2927).

The commission said SPP’s proposal gives it flexibility in addressing system needs through the MDRA process ahead of extreme weather events and helps incentivize resources to perform when the grid faces reliability risks. FERC said the revisions help resources committed during the MDRA process manage fuel price volatility during extreme weather events.

The MDRA process is SPP’s only way to commit resources in advance of its day-ahead market. It studies systems to help determine whether to commit resources and to provide notice to resources that they be online and should procure fuel. SPP said the revisions do not fundamentally change the process’ core concepts.

The RTO said its proposal was informed by its experiences during the 2021 and 2022 winter storms, when it was forced to import capacity from neighbors to meet demand.

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FERC’s Clements Gets GETs’ Benefits to Grid

AUSTIN, Texas — FERC Commissioner Allison Clements is no rock star, but observing her appearances during a gathering of federal and state regulators last summer, you might be mistaken.

Heads turned as she entered a large conference room with several of her staffers, taking a front-row seat for a National Association of Regulatory Utility Commissioners’ discussion on grid-enhancing technologies (GETs). Attendees whispered and nodded in Clements’ direction. Some regulators approached her. Others gave her space. 

Asked if the attention makes her feel like she’s in the same orbit with Mick Jagger or Bruce Springsteen, Clements breaks into a smile and turns toward one of her staffers. 

“Well, I like to go see rock stars,” she answered, noting she did catch Western swing band Asleep at the Wheel’s performance the night before. 

Her day job does take precedence, however. From the moment she joined FERC in 2020, Clements has focused her energy on GETs, such as sensors, power flow control devices and analytical tools that maximize the existing transmission grid. She has taken a key role in helping FERC establish the appropriate incentive mechanisms for the technologies’ adoption.  

Clements earnestly watched the discussion during the NARUC summit. Offered a chance to comment, she stressed the importance of financial incentives to help utilities roll out GETs and said it’s important to dispel the “myth” that GETs are rife with risks when deployed. 

“The existence of those risks shouldn’t stop us from starting to require consideration of deployment, and certainly the many cases we’ve heard so far about entities that have used dynamic line ratings to the benefit of customers have found ways to manage those,” she said. (See FERC-state Transmission Task Force Examines Barriers to GETs.)

A more relaxed Allison Clements | © RTO Insider LLC

And then there are the economic benefits. 

“As I spoke with providers of grid-enhancing technologies and learned anecdotally the amount of savings that people were getting … as well as the amount of capacity they were freeing up on the system, it was a no-brainer to me,” Clements said. “The light bulb went on and I said, ‘You can’t stand up as an economic regulator on behalf of customers if you don’t try and squeeze the savings out of the existing system that has already been paid for.’ 

“The cost of these investments are so modest relative to alternatives that they’re an excellent complement to the development of the transmission system,” she added. “They can’t replace the need to modernize our system with new transmission, but certainly they’re an important complement to that investment.” 

During FERC’s July monthly meeting, Clements referred to a Grid Strategies report estimating that congestion cost the country about $20.8 billion in 2022, up $14 billion since 2020. She also mentioned a Brattle Group white paper that says using GETs to unlock additional capacity on the grid would save customers $8.3 billion. 

She says GETs are a topic “that was once relegated to small windowless conference rooms full of energy grid geeks,” but are now “front of mind” in big rooms before the nation’s regulators.  

“GETs will be a win for customers, and states are taking notice,” she said in July. Recalling NARUC’s discussion of the technologies, Clements added, “My team and I had fun brainstorming technology that came after some of the early GETs, like the floppy disk and the Walkman. Today, utilities around the world have proven experience and results. 

“I came away with the sense that the regulators, as a group, are open to more systematic deployment of these GETs solutions and I look forward to working with them.”  

Noting that part of an engineer’s job description is to be conservative when it comes to reliability, Clements said it’s incumbent on regulators to align financial incentives to encourage the risks of using GETs. 

“[Regulators] don’t have to attach a synchrophasor to every line, but to start getting comfortable and educating and understanding their benefits and limitations,” she said. 

Clements cited as an example PPL Electric Utilities and PJM using a dynamic line rating (DLR) solution to resolve congestion on two transmission lines. She said they spent $500,000 on one line and avoided a $12 million reconductoring. PPL and PJM spent several million dollars on the two lines, which have saved more than $23 million annually, exceeding projections. (See Grid-enhancing Technologies Poised for Growth with Federal Funds.) 

FERC has responded with several initiatives to help facilitate GETs’ deployment. In July, the commission approved Order 1023, which reforms interconnection procedures and included language requiring transmission providers to consider advanced power flow control, transmission switching, and static synchronous compensators and VAR (Volt-Amps reactive) in their studies. 

“It’s a great start for grid-enhancing technologies, or as the rule calls them, alternative transmission technologies,” Clements said during FERC’s July meeting. “The rule’s requirement sets only a low bar: ‘evaluation’ of these technologies. I encourage utilities and grid operators to embrace the opportunity this rule provides, learn more about how to grow your consideration and deployment of these grid-enhancing technologies, and share your learning with your neighbors.” 

The commission has opened a DLR inquiry (AD22-5) to examine whether their use would help ensure just and reasonable wholesale rates by improving the accuracy and transparency of line ratings. It also has a proposed rulemaking (RM21-17) that mandates DLRs and advanced power flow control devices be more “fully” considered in regional transmission planning processes. 

“I would love to see all those things get done,” Clements said. “Grid-enhancing technologies happily provide that modest investment cost. The return on investment is a fraction of the time of a traditional infrastructure expenditure. And they’re dynamic, they’re modular, you can move them, you can use them where they work. There’s just a lot of options to make the grid smarter. The numbers are striking. The dollar savings are striking.” 

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ERCOT Appeals for Conservation as Winter Roars in

With demand projections and available capacity changing by the minute as a winter storm rolled into Texas, ERCOT and state officials spent last week assuaging Texans that the grid will remain standing this week.

Speaking to residents who remember well the devastating February 2021 winter storm that killed hundreds and caused billions in damages when the ERCOT system failed, Texas Gov. Greg Abbott said during a press conference Friday, “I know a lot of people are concerned, ‘Is the power going to stay on?’

“We feel very good about the status of the Texas power grid and ERCOT to be able to effectively and successfully ensure that the power is going to be able to stay on throughout the entirety of this episode,” he added.

The National Weather Service has placed much of the state under a winter weather advisory through Monday, warning of “dangerous” temperatures in the 20s as far south as the Gulf Coast. However, unlike three years ago, little snow or ice is expected.

ERCOT CEO Pablo Vegas said Friday he expects renewable energy to perform as normal, given the lack of precipitation statewide. He said there were no expectations of energy emergencies or conservation calls.

“Things can change and if it does change, we’ll continue to communicate openly over the course of this weekend,” Vegas said.

Sunday evening, things changed. ERCOT issued a conservation appeal for Monday morning due to the freezing temperatures, demand and low reserves. The ISO asked Texans to conserve their electric usage between 6 a.m. and 8 a.m., when solar resources start ramping up and temperatures are forecasted to be below 10 degrees Fahrenheit in North Texas.

ERCOT expects conditions to be similarly tight Tuesday morning. As of 7 p.m. Sunday, the grid operator was projecting a record peak of 86.1 GW, with only 83.8 GW of seasonal available capacity. However, the forecasted curves have changed frequently in the days leading up to the storm’s arrival.

Demand that high is the norm during the summer, having peaked at 85.5 GW in August. ERCOT set its record winter peak of 74.5 GW during the December 2022 winter storm.

The ISO stressed the conservation appeal does not indicate it is experiencing emergency conditions. It said in a press release staff will “remain vigilant and communicate further if conditions change.”

ERCOT also has asked all state and local government agencies to reduce energy use at their facilities until at least 10 a.m. Monday.

The grid operator previously issued a weather watch that went into effect Sunday and expires Wednesday. It said it made the advance notification because of “forecasted significant weather with higher electrical demand and the potential for lower reserves.”

Vegas has said the grid “is as ready and reliable as it has ever been for the winter season.” Legislation passed since the disastrous 2021 winter storm has strengthened the ISO’s weatherization practices — staff have completed nearly 1,800 facility inspections over the past couple of years — and created new ancillary services that can be brought to bear.

SPP Expects Near-record Demand

SPP said it projects to have sufficient capacity to meet anticipated demand this week, despite minimum temperatures in its 14-state Great Plains footprint similar to those observed during the December 2022 storm.

“We have substantial systems and procedures in place and our staff stands ready to mitigate any risks related to maintaining electric reliability,” Senior Vice President of Operations Bruce Rew said in a statement.

With temperatures that could be 30 to 50 degrees below normal, the RTO was expecting load to be as high as 45 GW on Monday and 46 GW on Tuesday. Its all-time winter peak is 47.2 GW, set during Winter Storm Elliott in 2022.

SPP said high pressure building into the Plains behind the cold-weather system may bring a sharp reduction in wind power generation, elevating the risk of outages. The grid operator on Friday issued a conservative operations advisory for its balancing authority area, effective 4 a.m. CT Sunday through 9 p.m. Tuesday.

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NEPOOL Markets Committee Briefs: Jan. 11, 2024

Analysis Group Presents Final Report on Capacity Market

WESTBOROUGH, Mass. — Adopting prompt and seasonal capacity auctions would provide a range of benefits that would help enable New England’s clean energy transition, Todd Schatzki of Analysis Group told the NEPOOL Markets Committee on Jan. 11.

Schatzki presented the consulting firm’s final report on significant potential changes to ISO-NE’s Forward Capacity Market. While the Forward Capacity Auction is currently held more than three years prior to the annual capacity commitment period (CCP), ISO-NE is considering a transition to holding the auction as close as a few months prior to the CCP, as well as dividing the CCP into distinct seasons.

Responding to stakeholder questions based on a draft report the firm presented in December, Schatzki reiterated Analysis Group’s recommendation to adopt a prompt and seasonal market for the 2028/29 CCP. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)

A prompt format would provide a “technology-neutral platform for competition among resource types,” Schatzki told the MC. This would benefit new clean energy resources with shorter development timelines compared to new gas plants, which the existing forward market was originally designed to accommodate, he said.

Schatzki added that a prompt, seasonal market would also more accurately forecast load growth from electrification and the effects of counterbalancing state policies intended to reduce demand. He also noted that a seasonal format would also increase incentives for resources that provide winter reliability benefits.

A seasonal market “creates price signals for the development of capacity resources to complement the variable output of resources important to states’ decarbonization efforts, such as solar PV and offshore wind,” Schatzki said.

Responding to stakeholder questions about the merit of holding seasonal auctions simultaneously or sequentially each year, Schatzki said sequential auctions could result in a small percentage of resources obtaining only a capacity supply obligation in one season, creating a risk that these resources would struggle to recover their annual costs.

In contrast, holding the auctions simultaneously could enable generators to dictate annual revenue requirements that need to be recovered through one or multiple seasons.

Analysis Group declined to recommend either design. It noted that holding the auctions simultaneously “offers many conceptual advantages, but the auction structure decision requires a thorough and careful assessment.”

The firm made some changes to the methodology of the quantitative analysis for the final report, finding that alternatives to the FCM resulted in lower prices in eight out of nine scenarios, by 8% on average. A prompt and seasonal market showed the most significant price reductions, with payments projected to be 12% lower — equal to more than $200 million annually — relative to the FCM.

ISO-NE is planning to make a recommendation on whether to move to a prompt and seasonal market at the MC’s meeting next month, with a vote by the committee on whether to further delay FCA 19 projected to occur in March.

Resource Capacity Accreditation Impact Analysis

Throughout the three-day MC meeting, NEPOOL discussed several aspects of ISO-NE’s ongoing Resource Capacity Accreditation (RCA) project, which would bring major changes in how the RTO calculates the capacity value of several resource classes.

Dane Schiro of ISO-NE presented the RTO’s updated impact analysis framework, which is intended to “provide quantitative insights into the RCA design.”

The analysis will provide information on how the RCA changes would affect accreditation values and capacity supply obligations for different resource types, as well as metrics related to capacity market prices and loss-of-load expectations. ISO-NE performed an initial version of the impact analysis in April 2023 before a software issue derailed the project for several months.

In a change from the initial impact analysis methodology, gas resources will now be studied at the fleet level instead of at the individual level, while the risk assessment for oil resources will include a two-week inventory limit.

The analysis will use a base case that employs the resource mix associated with the upcoming FCA 18 and the load forecast for FCA 19. Imports will be based on the level cleared in FCA 13, which represents the median amount from the past five auctions.

The first phase of the analysis will focus on resource accreditation in the base case, while the second phase will look at different sensitivity scenarios, including changes to the amount of fossil fuel resources replaced by renewables and an increased winter peak load. The third phase is intended to give quantitative insight on auction results, including demand curves, clearing prices and LOLE.

Marginal Reliability Impact Calculations

As a part of the ongoing RCA project, Steven Otto of ISO-NE detailed the RTO’s proposed approach to calculating the marginal reliability impact (MRI) and qualified MRI capacity (QMRIC) values for different resource classes.

MRI aims to quantify how small changes to a given resource’s output would affect grid reliability. MRI is an input to QMRIC, which represents a resource’s overall accredited capacity.

MRIs will be calculated for two seasonal periods: a June-September summer period and an October-May winter period. Seasonal MRI values for existing thermal resources “will be driven by their equivalent forced outage rate on demand excluding events out of management control,” ISO-NE said.

For new thermal resources, MRI values will be calculated based on the averages associated with their resource class. MRI values for new storage and large wind and solar resources will be created by modeling the marginal addition of a proxy resource. Small existing intermittent resources with a nameplate capacity of less than 10 MW will be combined into aggregations for their MRI assessments.

Gas Accreditation

Prior to the MC meeting, ISO-NE issued a memo detailing several potential methodologies for accounting for gas system constraints in the RCA updates. The current accreditation approach does not account for gas system constraints when determining a resource’s capacity value.

The RTO is recommending a derating approach for gas resources, which “decreases the accredited capacity of all gas resources so that their total accredited capacity equals the gas constraint,” ISO-NE wrote.

ISO-NE also discussed the possibility of a “market constraint approach,” which would not decrease the accreditation of gas resources based on a lack of firm fuel commitments, but instead would “decrease the amount of gas capacity procured in the winter … and would pay that capacity a lower price.”

“The market constraint approach achieves the same level of reliability as current rules, but at least cost,” ISO-NE said. “The awards determined by the market constraint are cost minimizing: No other set of awards could achieve the same level of reliability at lower social costs.”

ISO-NE proposed to conduct additional analysis into implementing a market constraint approach, while adding that the derating approach would be easier to quickly implement and makes sense as a “as a reasonable transition mechanism.”

“Overall, the market constraint approach is preferred but is not implementable for FCA 19 or a one-year delayed auction timeline and likely requires a seasonal market construct,” the RTO wrote.

ISO-NE also included the possibility of an “MRI=0 approach,” which would not award any accredited capacity to gas resources that lack firm fuel arrangements. The RTO wrote that this approach “would not procure a socially optimal quantity of gas capacity, nor would it pay the gas capacity an appropriate price.”

Tom Kaslow, vice president at FirstLight Power Resources, presented to the MC on the company’s concern that ISO-NE’s proposed approach would not provide adequate incentives for firm gas contracts.

Kaslow told RTO Insider that ISO-NE’s proposal to determine the maximum reliability contribution from gas resources based on the expected available gas supply could “undermine the forward contracting for firm gas supply access that would assure that the future year assumed gas supply is realized.”

“While there is a history of a certain level of available gas supply to gas-fired generators, without advance contracting, circumstances can change, as evidenced by the possible retirement of the Everett Marine Terminal,” Kaslow added.

The company is asking ISO-NE and NEPOOL for additional analysis into how the different approaches to accounting for gas system constraints would impact incentives for firm fuel contracts.

Committee Votes

The MC voted to support an update to ISO-NE’s compliance with Order 2222 that would make distributed energy resource aggregations responsible for submitting their own metering data to ISO-NE.

FERC clarified in October that this metering information could “come from or flow through distribution utilities.” (See FERC Responds to ISO-NE Rehearing Request on Order 2222.) ISO-NE’s current proposal would allow a DERA “to designate itself, a party acting on its behalf or the host participant to be the assigned meter reader.”

The committee also voted to recommend updating the forward reserve offer cap to $7,200/MW-month and delay the publication of forward reserve auction offer data for 12 months to address market power concerns.