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November 18, 2024

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PJM MRC Briefs: Sept. 25, 2024

PJM Proposes Reopening Discussion of Storage as a Transmission Asset 

VALLEY FORGE, Pa. — About four years after PJM stakeholders shelved deliberations on rules around how battery storage can be used to address transmission constraints, PJM Director of Stakeholder Affairs Dave Anders presented a first read on reopening the topic with a refreshed problem statement and issue charge.  

Anders framed the issue charge as the second phase in developing market rules for battery storage, following on the implementation of rules for how storage can participate in the markets. A possible third phase could consider how a battery installation could serve simultaneously as transmission and a market asset. But PJM’s Becky Carroll said staff prefer to develop clear rules on the market and transmission sides before trying to create a dual-use structure. 

“It’s not a never, it’s just not right now for the dual-use piece of it,” she said. 

Vistra’s Erik Heinle questioned whether stakeholders should embark on developing a new structure for a class of transmission assets while tackling several other major efforts. He suggested instead waiting six months before initiating the work. 

Anders said staff also was concerned about inundating stakeholders with additional meetings, which played into the issue charge designating the work to the Operating Committee. 

Tom Hyzinski, of the GT Power Group, said the classic use case could be a substation where a transformer failure could lead to excessive loading on other facilities. Rather than installing an additional transformer, he said a battery could alleviate the loading while potentially being cheaper and easier to install. He agreed that transmission rules should be developed before considering how that same battery could participate in the markets. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said there are advocates who believe it should be a priority to enable dual-use storage as quickly as possible. He said the possible elimination of energy efficiency as a resource class and de-rating of demand response have limited the ability for load to respond to market signals and that increased storage could present an ability to mitigate capacity prices. Some advocates may seek an amendment to PJM’s issue charge or an alternative with dual use included. 

Exelon’s Alex Stern said he believes it’s best to take “crawl before we walk approach” to avoid consideration of storage as a transmission asset (SATA) being derailed by arguments over dual use. 

Bowring said market-oriented assets, including storage and generation, can be used as transmission, such as when PJM dispatches them to provide voltage support. He said the capability to install SATA could be practically limited to transmission owners. 

The dual-use concept presents even greater concerns, Bowring said, by creating an “impossible task” of determining if one side is subsidizing the other, either markets or transmission with a regulated return. 

LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance

LS Power presented two issue charges focused on PJM’s marginal effective load-carrying capability (ELCC) accreditation framework. One would focus on making the calculations more transparent and replicable for market participants. The other would aim to replace class accreditation with adjustments for each unit with unit-specific ELCC ratings. (See FERC Approves 1st PJM Proposal out of CIFP.) 

Vice President of Wholesale Market Policy Dan Pierpont said a more comprehensive understanding of how ELCC values are determined and how they influence final unit accreditations could allow generation owners to make investments that would improve unit capacity. 

Pierpont said the issue charge seeks a way for generation owners to validate their accreditation values, understand how physical or managerial changes to a unit would affect accreditation and a set date for PJM to lock in changes to ELCC values to provide more market certainty ahead of auctions. 

“The complexity of the marginal ELCC methodology remains an important determining factor in the ability of PJM’s capacity market to send transparent price signals and attract investment where needed,” the transparency issue charge states. “To make that determination, significantly more data and analytical transparency is needed.” 

The document would hold discussion of alternative accreditation frameworks and a sub-annual capacity market to be out-of-scope. It targets having any changes approved to be implemented for the 2028/29 Base Residual Auction (BRA), scheduled for December 2025. 

Susan Bruce, representing the PJM Industrial Customer Coalition (PJM ICC), said more transparency around ELCC could be beneficial for all market participants and suggested an amendment to provide more data access for all members. LS Power Director of Project Development Tom Hoatson said the company would be open to such an amendment to the issue charge, as long as market sensitive information is protected.  

The unit-specific ELCC issue charge seeks to expand the data considered in the ELCC unit-specific performance adjustment to allow accreditation to reflect any changes made that could improve performance. Pierpont said the adjustment considers a narrow number of hours in which load drop occurred, which in practice results in accreditation values weighted toward performance during the 2014 Polar Vortex and weather and load during winter storms in 1994. Investments made in resources since that event would have minimal impact on how that unit’s potential performance is evaluated compared to the rest of the resource class, he said. 

The problem statement argues the issue is twofold: The incentive for generators to make investments to improve performance could be limited if accreditation values would remain static, and maintenance costs may be ignored if no capacity derate is likely. The issue charge targets a FERC filing in the first quarter of 2025.  

The issue charge focuses on how much historical data PJM includes in its performance, load and weather data; the unit-specific performance adjustment and possible use of a unit-specific ELCC accreditation; how ELCC class average values are applied to new resources; and how transmission headroom factors into ELCC values. 

PJM CEO Manu Asthana said it takes a long time for performance improvements to be reflected in resource accreditation and it’s a valid inquiry to look at how investments can be accounted for more quickly. 

LS Power Senior Vice President of Wholesale Market Policy Marji Philips said if a turbine fails during a performance assessment interval (PAI) and the generation owner replaces the equipment and makes changes to avoid that happening again, that event can lead to diminished accreditation for years. 

“That bad experience during a PAI haunts us for years,” she said. 

The PJM Public Power Coalition’s Carl Johnson said the ELCC construct can be improved upon, but any stakeholder efforts must be approached cautiously to ensure they do not conflict with changes likely to be made through the second phase of PJM’s capacity market redesign. 

Vitol’s Jason Barker said it’s logical to reflect capital expenditures, but the issue charge seems focused on speeding accreditation for thermal resources without addressing the increased accreditation for renewables resources that could be unlocked through a sub-annual market design. He also questioned whether it’s reasonable to expect changes to the ELCC structure could be accomplished within the envisioned 4.5-month timeline. 

Independent Market Monitor Joe Bowring said stakeholders discussed related issues at length during the Critical Issue Fast Path (CIFP) process last year, and he said membership is capable of acting in a disciplined and focused way. 

Poulos said the compressed capacity auction schedules makes the implementation timeline especially important and recommended prioritizing working areas to ensure changes can be in place for the earliest auction possible. 

Stakeholders Endorse Creation of Electric Gas Coordination Subcommittee

The MRC endorsed the sunsetting of the Electric Gas Coordination Senior Task Force (EGCSTF), to be replaced with a new Electric Gas Coordination Subcommittee (EGCS), which is intended to have a wider scope and be more flexible in the topics it can address. (See “PJM Proposes Sunsetting Electric Gas Coordination Senior Task Force,” PJM MRC/MC Briefs: Aug. 21, 2024.) 

The MRC voted in June to endorse part of a proposal drafted by the EGCSTF, greenlighting changes to the day-ahead energy market commitment cycle to align with daily gas pipeline nomination deadlines. Stakeholders rejected a second component that would ask generators to voluntarily notify PJM of whether they have procured fuel necessary to meet their commitments or intend to do so. (See “Stakeholders Endorse Revised Proposal to Align Energy, Gas Schedules,” PJM MRC/MC Briefs: June 27, 2024.) 

A subcommittee would allow a more long-term focus on harmonizing aspects of PJM’s markets with how gas pipelines are operated and consider revisions to a broader swath of PJM’s market rules. 

The draft charter states that the responsibilities and scope of the subcommittee include reviewing market and operational conflicts between the electric and gas sectors, assessing and updating participants on state and federal initiatives affecting gas-electric coordination, and “[recommending] necessary enhancements to PJM rules, systems and procedures which can improve grid reliability, efficient market operations, and greater availability and flexibility of natural gas-fired generating resources.” 

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned how it can be ensured that stakeholder efforts to improve market rules around gas generation do not become siloed between different working groups. Anders said part of subcommittee’s charge would be to keep tabs on those efforts with regular updates. 

“The important part is to keep the communication lines open … and frankly I think that’s one of the things this new subcommittee can do, to make sure we’re thinking across the whole horizon,” Anders said. 

Hourly Notification Times in Day-ahead Market Endorsed

Stakeholders endorsed a proposal to add hourly notification times to the day-ahead (DA) energy market, expanding the capability from the real-time (RT) market. (See “Hourly Notification Times,” PJM MRC/MC Briefs: Aug. 21, 2024.) 

PJM’s Joseph Ciabattoni told the MRC that generators are limited to daily notification in the DA market. But reserve price formation market changes have increased the importance of notification times for determining the eligibility and capability of offline resources to be committed as non-synchronized and secondary reserves. 

Sotkiewicz said notification times are an important factor for gas resources and more discussion is needed to continue to refine how they are committed. 

PJM Proposes Elimination of Two Interface Pricing Models

PJM’s Brian Chmielewski presented a first read on tariff revisions to remove the high/low and marginal-cost proxy interface pricing options. (See “PJM Proposes Elimination of 2 Interface Pricing Options,” PJM MIC Briefs: Aug. 7, 2024.) 

Both were designed for pricing imports and exports with neighboring nonmarket regions. But they have gone unused since July 2019, when Duke Energy Progress terminated its dynamic interface, which used marginal-cost proxy pricing. Chmielewski said a nodal aggregate pricing approach has since been implemented, which PJM believes creates accurate price signals based on other interfaces. 

The proposal is set to be voted on by the MRC on Oct. 30 and the MC on Nov. 21 and to be filed at FERC in December. 

First Read on Increased Review of Credit Risk for Bilateral Capacity Transactions

PJM presented a first read on a proposal to strengthen its ability to collect capacity performance (CP) penalties from market participants who have bilaterally sold their capacity rights and revenues. 

Assistant General Counsel Eric Scherling said bilateral transactions separate the payments received by the buyer from the performance obligations held by the seller, which can present issues if the seller does not have proper credit or revenues to cover any possible performance penalties. 

PJM would conduct a credit review of bilateral capacity transactions before they can be completed and both parties’ creditworthiness and the impact the transaction might be considered before PJM signs off. Transactions where both the buyer and seller have external investment grade ratings, and the total notional value of the transaction is less than their unsecured credit allowance would be considered approved unless PJM states otherwise. 

If PJM is notified of a transaction before 1 p.m., it would complete the credit review by the end of the next business day; if the notification came after 1 p.m., PJM would have two days to complete the review. 

PJM’s Gwen Kelly said the intent is not to create any changes to the credit risk evaluation, but to provide more visibility into the transactions before they’re created to allow proactive, rather than reactive, actions to be taken if issues are identified. 

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Texas PUC Approves Permian Reliability Plan

Texas regulators have approved ERCOT’s reliability plan for the petroleum-rich Permian Basin that could rely on the state’s first use of 765-kV transmission facilities.

The plan includes 765- and 345-kV infrastructure to support the region’s current and future power needs and new and upgraded local projects, as well as new import paths that will bring additional power to the region. The Public Utility Commission approved the plan during its Sept. 26 open meeting (55718).

Commissioner Lori Cobos, a native West Texan who has taken the lead on the proceeding, filed a memo recommending the PUC authorize the region’s transmission service providers (TSPs) to begin preparing applications for infrastructure along eight import paths into the basin to serve its projected load in 2030.

She said that would preserve the plan’s “optionality” after recent ERCOT analysis indicated that installing transmission elements capable of either voltage would require additional months of engineering studies. The grid operator initially hoped to use interchangeable import paths capable of both 345- and 765-kV lines.

“The whole goal remains the same in terms of preserving optionality at this time on the import paths into the Permian Basin region, so that ERCOT and the commission can continue their evaluation of EHV [extra high voltage], primarily 765-kV transmission lines,” Cobos said.

She said directing ERCOT to work with the TSPs on the import paths that would be needed for 2030 will provide certainty by prioritizing the applications for certificates of convenience and necessity. At the same time, she said, the grid operator and PUC will be able to continue their evaluation of EHV transmission and determine the import paths so CCNs can be filed. ERCOT has designated five of the import paths as 345-kV and the other three as 765-kV.

Cobos set a date certain of May 1, 2025, for the commission to approve the 765-kV lines. Should the PUC decide not to move forward with the EHV buildout, the 345-kV import paths would be considered approved and the TSPs allowed to file their CCNs, she said.

The grid operator has projected oil and gas load peaking at nearly 15 GW by 2038 and an additional 12 GW of data center and other non-petroleum load by 2030. Based on those projections, ERCOT has said building the transmission facilities to meet that load could cost more than $15 billion. It currently is considering 4,481 miles of 765-kV lines and 20 associated substations. (See EHV Tx Lines Coming into Focus for ERCOT.)

“If you look at some of the cost estimates for building out a 765 backbone throughout the state, it’s going to cost a lot of money just because of how large the state is,” PUC Chair Thomas Gleeson said in a keynote address Sept. 25 at Infocast’s Texas Clean Energy summit in Houston. “I think it’s important for us, for ERCOT, for the transmission and distribution utilities to not only show that cost, but also speak intelligently and clearly about what the benefits of all these transmission upgrades are, because you don’t get all the economic development here unless you’re willing to invest in the infrastructure.”

“It’s going to be a tremendous boon for our state in so many ways,” Cobos said of the plan.

Commissioner Jimmy Glotfelty continued to push for EHV lines, saying he was ready “to do 765.”

“I continue to believe that the deeper we get involved in the process and the deeper ERCOT’s involved in the process, the longer it’s going to take,” he said. “If we continually kick things to ERCOT, I fear that there are things that we can get tripped up on and slow down, and that makes me fearful of the default back to 345. I don’t think that’s the right default. The amount of congestion that we see in West Texas that this could help solve is somewhere between $100 [million] and $300 million a year. That obviously would pay for these lines, not even considering the economic development in the Permian.”

PUC to Review 4CP Program

The commission signaled it is ready to discuss doing away with ERCOT’s Four Coincident Peak (4CP) program, a demand charge that alerts industrial users to high energy costs during peak demand periods and was intended to allocate transmission costs to the drivers of new facilities (34677).

Staff said they were “supportive of opening the dialogue about 4CP.” They noted the program has been in existence for more than two decades and suggested it can be revised to maintain an ERCOT-wide rate based on demand but still “modify the allocation method away from 4CP.”

“I think it’s definitely time to talk about it and be proactive about … reviewing that decision that was made 20 years ago and make sure that it remains the correct one. And if not, then what should we be moving to?” Barksdale English, the PUC’s deputy executive director, told the commissioners, while also noting there is not “uniform [staff] opinion” on the program.

The grid operator’s Independent Market Monitor has recommended since 2015 in its annual market reports that 4CP be changed to better reflect the true drivers for new transmission. It said again in its latest report that the current method “does not apply transmission costs equitably to all loads.”

Under 4CP, pricing signals are sent to industrial customers who might want to avoid peak transmission costs. ERCOT looks at the peak demand over four 15-minute intervals from each of the summer months — June, July, August and September — and then assigns transmission costs to transmission and distribution service providers (TDSPs) based on their share of total peak load.

The TDSPs recover their transmission-cost obligations through wires charges on all loads. Staff use those obligations to calculate 4CP demand charges for industrial customers based on the facilities’ peak demand during the four 15-minute windows. The 4CP charges are then distributed over a 12-month period as part of the facility’s bill over the next year.

“Customer demand during the peak summer hours is no longer the main driver of new transmission in ERCOT today,” the Monitor said in its 2023 State of the Market report. “Decisions to build transmission are based on transmission congestion patterns throughout the year and an analysis of whether generation can be delivered to serve customers reliably.”

Cobos agreed the discussion on 4CP is worth having, given the need to build out the grid to meet demand that continues to increase.

“We have to make sure that we start proactively looking at how we are allocating costs and developing cost allocation and rate design in our rate cases now,” she said. “I’m concerned that all of the massive transmission infrastructure that we’re looking at as a future will be primarily allocated to the small business and residential consumers, so I think that the 4CP discussion needs to start as soon as possible.”

Staff made the suggestion as part of a response to the IMM’s latest market report. They gave an opinion (support, neutral or disagree) on each of the Monitor’s 16 recommendations from the current and previous reports.

The PUC also approved a proposed rulemaking that establishes procedures for utilities outside ERCOT’s footprint to apply for grants from the Texas Energy Fund. The TEF includes an Outside ERCOT Grant Program that will award grants for the modernization of infrastructure, weatherization, reliability and resilience enhancements, and vegetation management for facilities outside ERCOT.

The commission will accept comments on the proposal through Nov. 7 (57004).

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Utilities Working to Restore Power After Helene Tears Through 10 States

The U.S. Department of Energy said Sept. 30 about 2 million customers still were without power after Hurricane Helene knocked out power to about 6 million across 10 states stretching from Florida to Ohio. 

The most affected states were Georgia, North Carolina and South Carolina, which sustained more than half the outages. As of the morning of Sept. 30, about half of those customers remained without power, said a report from DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER). 

The storm hit Florida’s Gulf Coast late on Sept. 26 and moved north the next two days through Georgia, South Carolina, North Carolina, Virginia, West Virginia, Tennessee, Kentucky, Ohio and Indiana. It brought strong winds and heavy rains, which led to flooding in some states, DOE said. 

Restorations remain underway as utility mutual assistance crews totaling about 50,000 workers from 27 states, the District of Columbia and even Canada were working to restore power, although the hardest-hit areas were expected to be without power through the end of this week.

“Restoration efforts after Helene will be a complex, multiday effort in many locations due to the extent of damage and ongoing access issues,” CESER said. “Utilities have been encountering widespread flooding and debris impeding access to damaged infrastructure. Communications disruptions are also impacting restoration efforts.” 

Duke Energy owns utilities in several states the storm affected, including its Florida subsidiary’s territory covering the area where Helene landed — the state’s “Big Bend” region where the panhandle meets the peninsula. Florida saw more than 1.3 million customers lose power, but Duke reported that 95% had been restored by Monday afternoon. 

Georgia Power reported it had 15,000 personnel working to restore power to all of its customers, having completed restoration to 840,000 customers by the afternoon of Sept. 30, with 370,000 still without electricity.  

Those remaining without power were in the hardest-hit parts of Georgia, in its eastern, southern and coastal regions, including Augusta and Savannah. The Southern Co. Affiliate has to replace more than 7,000 power poles, 15,000 spans of wire equivalent to 700 miles and more than 1,200 transformers and also remove more than 3,000 trees from power lines, it said. 

By 4 p.m. on Sept. 30, Duke Energy Carolinas reported it had restored power to 1.35 million customers, with 443,000 still without power in South Carolina and an additional 346,000 out in North Carolina. It expects to restore service to most of the 790,000 customer outages by the night of Oct. 4. 

“We’re beyond grateful to the state and local government workers who have been on the job 24/7 to clear debris, re-open roadways and help those whose lives have been changed forever by this storm,” Jason Hollifield, Duke Energy’s storm director for the Carolinas, said in a statement. “Our thousands of lineworkers and other storm workers are gaining better access to the destruction — allowing them to remove trees, broken poles and downed power lines, log each piece of damaged electrical equipment, and begin repairing and rebuilding major portions of the power grid that were simply wiped away.” 

North Carolina’s Electric Cooperatives reported an additional 90,602 customers among its members without power the afternoon of Sept. 30. 

Around the same time, Duke Energy Ohio still had 1,180 customers out, according to its outrage map, while American Electric Power subsidiary Appalachian Power, which serves western Virginia and parts of West Virginia, reported 110,197 customers still without power. 

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PJM Working to Speed Development of New Capacity

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee discussed how the development of new capacity can be sped, as a growing number of resources have cleared the interconnection queue but not entered commercial operation. 

PJM Vice President of Planning Paul McGlynn said the cluster-based approach to studying interconnection requests has increased the pace of processing projects, estimating that 72 GW of new generation will clear the queue by the end of 2025. Thus far, only 2 GW has actually come into commercial service, and most of that is solar resources with a relatively small capacity contribution. 

Lead time for equipment, local opposition and financing all remain obstacles for developers, McGlynn said, adding that this represents a call to action for stakeholders to identify and work to remove those barriers. 

“We need to get the resources that are going to move forward, we need to get them connected to the grid so they can help us out with the resource adequacy issues that we are having,” he said. During the Aug. 6 Planning Committee, PJM stated that generation deactivations, rising load forecasts and sluggish resource entry are contributing to a possible capacity shortfall in the 2029/30 delivery year. (See “PJM Models Suggest Capacity Shortfall Possible in 2029/30 Delivery Year,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

The growing number of resources with service agreements that have not entered operation presents planning staff with challenges when identifying possible transmission reliability violations. PJM’s Jason Shoemaker said planned generation resources are modeled the same as operating units, creating instances where resources are assumed to be injecting MWs onto the grid when they actually still will be under development. That is driving up the number of violations and their complexity, he said. 

Vitol’s Jason Barker said PJM has implied that developers are moving through the interconnection process and leaving projects idle, a characterization he said misses work like permitting and siting that must be completed before the “boots on the ground” phase can begin. While some of the legwork used to be done while projects moved through PJM’s interconnection queue, he said the amount of time it now takes for projects to be processed has transformed a concurrent interconnection, permitting and siting process into a serial one. 

“Permitting is time consuming [and] costly, and permits expire. So the development community, as I think you’ve acknowledged, has real work before the shovels go in the ground, boots go on the ground. So, we have a really strong concern with the messaging that PJM has provided here,” primarily because it misleads the stakeholder community as to the diligence developers have in completing their projects, Barker said. 

Some of the same procurement challenges developers have faced also are affecting transmission owners’ ability to complete network upgrades necessary to allow resources to come online, with transformers, breakers and other components in short supply worldwide.  

“We very much want to bring our projects to completion and are working diligently to do so,” he said. 

Rather than focusing on the number of projects that still are in some phase of development, Barker said the focus should be on PJM’s success in canceling the queue positions of projects it has determined are not advancing toward commercial operation. 

Shoemaker said PJM has a cure process when a project misses development milestones, which typically lasts a few months before either a suspension is granted, the breach is remedied or the project is removed from the queue. He said about 75% of developers’ requests to change their agreements are granted by PJM. 

Tangibl Group Director of RTO and Regulatory Affairs Ken Foladare said PJM is making good progress in clearing projects faster. But the amount of time projects already have been in the queue has affected their ability to progress with permitting and financing. He said one project was seeking commercial operation in 2027, but the transmission owner said the earliest that would be possible was 2030 to 2031. Any permits received that far out would expire before work could begin. And financing also is unlikely to materialize that far in advance. 

Shoemaker said transmission delays can happen, and projects affected would be considered in the engineering and procurement phase. He said PJM’s focus when negotiating milestone deadlines is a project-specific review of whether a developer is doing everything in its power to move projects toward completion. On the other hand, he said granting delays can affect other developers in line behind that project, who need to be given a fair shot at advancing as well. 

Calpine’s David “Scarp” Scarpignato said there have been issues with how project suspensions and delays affect others in the queue, as well as possible reliability impacts as PJM models the injection of power from resources that are not built according to schedule. Even if network upgrades are completed on time, he said that could lead to energy not being available where it was expected. 

PJM CEO Manu Asthana said blame is irrelevant and the focus should be on what would improve completion rates. Capacity costs increased in the last Base Residual Auction (BRA) and the price cap is set to increase in the 2026/27 auction, stressing consumers. On the other side, he said forecasts of load growth continue to accelerate and could remain an undercount. 

He said PJM views a recent transaction in the footprint to purchase power outside the market for 20 years as a data point showing that demand is real. He encouraged stakeholders to deconstruct the deal and its implications on the capacity market. On Sept. 20, Constellation Energy announced an agreement with Microsoft to reopen and rename its 835 MW Three Mile Island Unit 1 the Crane Clean Energy Center with a 20-year power purchase agreement. (See Constellation to Reopen, Rename Three Mile Island Unit 1.) 

While solar and wind are viable in PJM and more renewables are beneficial, Asthana said they don’t provide the capacity needed by the end of the decade. If new construction is needed, he said there should be a corresponding price signal and that resource adequacy solutions must come through the interconnection queue. 

“I think it’s a generational challenge for us and we’re going to have to solve it together,” he said. 

Foladare commented that PJM’s wholesale market rules and price signals are leading developers to drop the storage component of some hybrid resources, leaving products that have limited utility as capacity. How batteries are accredited under PJM’s marginal effective load carrying capability (ELCC) approach has made standalone and hybrid installations less economically attractive. 

“Something has to be done in this area if you want to see more solar with storage or wind with storage,” he said. 

Asthana pointed to record-high clearing prices in the 2025/26 BRA and said he is hearing that high prices are needed to enable widespread storage development while consumers are stating prices are unsustainable. 

“We want more storage … but we hear it loud and clear that consumers don’t want high prices and right now those two things do not match,” he said. 

Foladare said capacity prices make up a relatively small portion of the potential revenue for storage. The overall cash flows from energy, ancillary services and capacity are not sufficient to cover the incremental cost of installing storage, he said. He suggested a fast-ramping product could fit the capabilities of storage better. 

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PIO Complaint Faults PJM Treatment of Deactivating Generation

Several public interest organizations (PIOs) have filed a complaint with FERC contending PJM’s capacity market inflates consumer prices by not counting generators operating on reliability must-run (RMR) agreements as a form of capacity (EL24-148).

The complaint argues that RMR contracts already require units to be online and available to PJM dispatchers in a capacity emergency, which positions them similarly to committed capacity.

The PIOs said consumers are being asked to pay for capacity twice: once for an RMR unit’s availability and again to procure the capacity the unit would have offered had it participated in the RTO’s Base Residual Auctions (BRAs).

The complaint was submitted by the Sierra Club, Natural Resources Defense Council, Public Citizen, Sustainable FERC Project and Union of Concerned Scientists.

“Failing to account for resource adequacy provided by RMR units produces capacity market price signals that are disconnected from the actual supply and demand balance on the grid,” the complaint says. “This distorted supply-demand balance is economically inefficient because it signals a degree of scarcity that does not exist. The result is artificially elevated prices that harm the markets by encouraging inefficient decisions by both supply and demand side market participants.”

The complaint also argues that PJM’s position on modeling RMR resource capacity is inconsistent because it does not include RMR units’ output when analyzing the amount of generation available within a locational deliverability area (LDA) when analyzing transmission capability during potential capacity emergencies.

The PIOs present two visions for how RMR resources could interact with capacity markets. The most straightforward would be requiring them to offer into the market at $0/MWh as price-takers; however, the complaint acknowledges the change could make generation owners wary of accepting an RMR agreement — which is a voluntary election in PJM. The alternative they propose would be to model RMR units when determining the reliability requirement and reduce the amount of capacity that must be procured through BRAs.

The complaint also requests the commission delay the 2026/27 BRA, currently scheduled for December, to allow the changes to be implemented for that auction.

RMR Impact Set to Increase

The impact of RMR agreements on consumer rates is likely to increase substantially in the 2025/26 delivery year, when agreements take effect between PJM and Talen Energy to keep the 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators online from June 1, 2025, through Dec. 31, 2028.

The complaint cites analysis from Synapse Energy Economics, on behalf of the Maryland Office of People’s Counsel, and a separate report from the Independent Market Monitor, which found that not counting RMR units as capacity could cost PJM ratepayers $4billion to $5 billion in 2025/26. (See Maryland Report Details PJM Cost Increases for Ratepayers.)

The terms of the Talen agreements are being negotiated through settlement judge proceedings the commission ordered in June. The company requested $175 million in annual fixed costs and $29.9 million in project investments for Brandon Shores and $40.3 million in fixed costs and $4.5 million in additional investments for Wagner. (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.)

Stakeholders also are discussing changes to PJM RMR resources in the Deactivations Enhancement Senior Task Force (DESTF), which is set to open a vote on five proposals during its Oct. 2 meeting. The DESTF packages largely focus on extending the notice generation owners must provide PJM ahead of their desired deactivation dates and how compensation under RMR contracts is determined.

None of the DESTF proposals include a capacity must-offer requirement for RMR units, but a proposal from the Sierra Club would model the expected output of RMR resources that do not participate in the capacity market when determining the reliability requirement.

The parties to the complaint argued that even if a proposal passed that satisfies their concerns, changes are unlikely to be implemented in time for the December auction. The PIOs also noted that the PJM Board of Managers rejected a request from six state consumer advocates in an Aug. 30 letter to launch a Critical Issue Fast Path (CIFP) process to require RMR units to participate in the capacity market. In its Sept. 19 response, the board wrote that doing so would undermine the capacity market’s price signals to replace the outgoing generator or make investments to keep units operational.

In the first of a series of reports on the 2025/26 BRA, the Monitor estimated that not including RMR units in the supply stack as capacity price takers would have increased the cost of capacity procured by more than $4 billion, or 41.2%. The Monitor said this would recognize that RMR resources provide reliability while transmission upgrades to address their deactivation are constructed.

“There are times when a price signal for the entry of generation is not needed or appropriate, e.g. when PJM has committed to the construction of new transmission that will eliminate the price signal when complete,” the Monitor wrote.

Monitor Joe Bowring told RTO Insider that requiring an RMR unit to offer into the capacity market also could lead to costs for consumers, as generation owners would be more wary of entering into RMR agreements and would seek to recover the risk of being subject to capacity performance (CP) underperformance penalties. Instead, he suggested including them in the supply curve as a zero-cost offer.

Bowring said one of the issues with how generation deactivations are treated in PJM is the lacking ability for merchant generation to compete with transmission to address any identified reliability violations. He argued that an expedited interconnection process is needed to give new resources a chance to provide a solution to violations or when reliability issues are identified in general, such as the capacity shortfall PJM has been warning about in the 2029/30 delivery year. He has proposed a similar concept at the Planning Committee for allowing PJM to transfer capacity interconnection rights (CIRs) from a deactivating resource to resources which could resolve associated violations. (See “Voting on CIR Transfer Proposals Deferred to October,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)

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CAISO Seeks to Dispel CRR ‘Myths’ Around January Cold Snap

CAISO focused on congestion revenue rights when it served up the latest volley in the ongoing dispute over what played out on the Western grid during the January cold snap that forced Northwest utilities to import unusually high volumes of energy to avoid blackouts. 

“Given all the nuances and complexities with all the dynamics at play during that event, it is always useful to step back and have the opportunity to provide some basic facts of how things actually happened,” Guillermo Bautista Alderete, CAISO director of market performance and advanced analytics, said during a Sept. 27 presentation to the Western Energy Imbalance Market’s Regional Issues Forum (RIF).  

“But in order to reach that point in the discussion, it is critical that we first differentiate between the fact and the myth,” Alderete said.  

The cold snap over the Jan. 12-16 Martin Luther King Jr. holiday weekend saw record low temperatures along with historically high peak demand, prompting five different balancing authority areas (BAAs) to declare energy emergency alerts. Stressed grid conditions also produced price separation between the Northwest and California, with extremely high bilateral prices in the Northwest and at the Malin intertie in particular.   

Central to the dispute over the event was CAISO’s role in supporting the Northwest during extreme weather conditions, as the disagreement quickly became a proxy for the broader competition for members between the ISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+. (See NW Cold Snap Dispute Reflects Divisions Over Western Markets.) 

A Feb. 8 report by the Western Power Pool found that while CAISO and other California BAs exported nearly 3,000 MW of energy to the Northwest, they also were net importers, suggesting the Desert Southwest and Rockies regions — and not California — were the origin of most of the Northwest’s supporting imports.  

That was followed by a Feb. 23 letter from the Portland, Ore.-based Public Power Council (PPC) to Bonneville Power Administration CEO John Hairston, which critiqued the ISO’s allocation of congestion revenue rents (CRRs) during the event. The PPC wrote that “CAISO’s congestion policies resulted in over $100M of congestion revenues being collected by the CAISO BAA, despite most of the generation serving the Northwest coming from outside California.” 

In a March 6 report, Powerex expanded on the CRR complaint and even called on Northwest entities to develop ways to circumvent flowing energy through California, while CAISO that same day issued its own 80-page report defending its actions during the cold snap and explaining the mechanisms used by the WEIM to move power around the grid.    

‘Myth Busting’

Alderete’s Sept. 27 “myth-busting” presentation to the RIF drilled further into the CRR issue, offering a series of seven “facts” and “myths” about what occurred and focusing on the congestion occurring at Malin and on the California-Oregon Intertie (COI) — the main interface between BPA and the ISO. 

The first “myth” Alderete addressed was the assessment that the ISO unilaterally decides on Malin limits to influence congestion. He emphasized that both BPA and the ISO are path operators on the COI and that there is an agreement between the two operators to have a “coordinated operation of the path” and “always enforce the most limiting constraint on the path.”  

According to Alderete, this first “myth” set the stage for the second one: that the ISO directly influenced day-ahead congestion on the Malin intertie. His presentation said the day-ahead congestion occurred “simply because the volume of exports requested for the Northwest exceeded the full Malin capability. Exports at Malin were twice as much as the full Malin capacity, and through the day-ahead market, the ISO positioned internal supply economically to support exports to the Northwest.”  

A third “myth” further perpetuated the belief that CAISO limited COI flows to influence congestion, but Alderete said that COI transfer capability during the MLK weekend was fully available and used in the day-ahead market for the share of the line operated by the ISO.  

“Here is the simple fact for these critical days of the MLK weekend: There were no derates on the Malin intertie. The full capacity of the intertie was used and made available in the day-ahead market,” Alderete said. “I can see how this myth could have been created out of confusion and maybe not appreciating the time frames of the event, and I can clarify that, specific to the MLK weekend, there were indeed weather-related forced outages in the BPA area, and those eventually resulted in derates to the path.”  

But the forced outages and derates affected only the real-time market, Alderete said.  

Delving further into the weeds, Alderete contested the “myth” that CAISO “charged excessive prices to exports flowing to the Northwest, reiterating that congestion prices on Malin were set by export bids, which reflected the price exports were willing to pay to flow.  

Alderete also provided additional color to the process of allocating congestion, saying that while a fifth “myth” holds that parties outside the ISO market have a right to day-ahead congestion revenue, the fact is that it’s sourced “only from re-dispatch of participating resources in the ISO market, including exports.”  

CAISO doesn’t have access to resources outside of its market, such as those north of Malin, to re-dispatch and alleviate congestion on ISO constraints, meaning that the sixth “myth,” that CAISO collected congestion rents on all Malin capability, is incorrect. 

“Congestion on Malin is only collected for the capacity made available to the market, lower than the full capability,” the presentation read. “The ISO operates two-thirds of COI capability; only that portion will be managed in the ISO market with Malin intertie.” 

The final and “biggest myth” that caused significant concern among some Western entities was that CAISO kept all $100 million of day-ahead CRRs collected on the Malin intertie. But Alderete emphasized that CRRs are given to their holders and that any surplus is allocated to demand and exports. Because the Malin capacity wasn’t fully exhausted in the CRR release, over $50 million in surplus congestion rents were allocated to measured demand. 

Alderete’s presentation came after a group of Markets+ supporters released a series of “issue alerts” favorably comparing the SPP day-ahead market with the EDAM. The latest alert, focused on market seams, covered the congestion rent subject. (See Markets+ ‘Equitable’ Solution to Seams Issues, Backers Say.)   

Alderete told RTO Insider in an email that the ISO will continue the conversation about the issue at the RIF’s October meeting, for which an exact date has not yet been announced.  

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BOEM Postpones Oregon Offshore Wind Auction

The U.S. Bureau of Ocean Energy Management has postponed its Oct. 15 Oregon offshore wind energy auction due to limited commercial interest. 

The move marks the second scratch out of the four auctions BOEM had scheduled in 2024 — the Gulf of Mexico auction targeted for September also was called off, also due to lack of competitive interest. 

BOEM canceled the Gulf sale outright but held out the possibility that the Oregon sale could go forward in the future. 

Five companies had been qualified to participate in the auction of two lease areas off the Oregon coast, but only one submitted bidding interest. 

The Oregon plan stands out as particularly controversial amid the growing pains and opposition facing the offshore wind industry in the United States as the Biden administration and some states try to build a new emissions-free power sector. 

BOEM’s plans for Oregon met with the familiar concerns voiced by the fishing industry, but it also drew a federal lawsuit from tribal nations trying to block the auction and a plea from the state’s Democratic governor to pause the initiative. 

Gov. Tina Kotek wrote to BOEM Director Elizabeth Klein asking that BOEM halt all leasing activities off the Oregon coast and terminate the auction. 

Kotek in her Sept. 27 letter said Oregon would withdraw from the BOEM Oregon Intergovernmental Renewable Energy Task Force to ensure the state’s interests are protected and to be certain there is adequate time to complete the state’s road map. 

She expressed disappointment in BOEM’s “accelerated process” over the past year and said she remains convinced offshore wind holds exciting promise for the nation’s clean energy future. But if it is built in Oregon, Kotek said, it would have to be done “the Oregon way.” 

BOEM in its Sept. 27 postponement announcement did not allude to the opposition. It emphasized that the auction was the result of engagement with the task force, including coordination with the state government, and said it would continue to collaborate as it determined the prospects of rescheduling the auction. 

Offshore wind power development has been a signature initiative of the Biden administration; all 10 of the BOEM project approvals have come in the past 40 months. 

This initiative has run up against sharp increases in the already-high cost of construction, shortcomings in the infrastructure and ecosystem needed to support the endeavor, project delays and cancellations, and extensive pushback from people who do not want to look at massive wind turbines or who fear their impact on the sea and its ecology. 

The Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians sued BOEM in federal court Sept. 16, seeking to halt the auction. They praised BOEM’s Sept. 27 decision, saying they would reconsider their lawsuit and would engage with the state and federal governments to ensure tribal interests were addressed before future lease sales were considered. 

The Midwater Trawlers Cooperative said Oregon’s seafood industry, tribes and coastal communities were breathing a “sigh of relief” over the “welcome news.” 

The BlueGreen Alliance also applauded BOEM’s decision, explaining that offshore wind is a potentially critical tool for the state to meet its 100% clean energy goals by 2040 but that creating the infrastructure needed to support it would take time. 

Oceantic Network supported BOEM’s decision, saying it would allow time for technologies and supply chains to develop and saying it was confident Oregon soon would join other states in the embrace of offshore wind. 

The organizations’ choice of words aligned squarely with their positions: BlueGreen and Oceantic said the auction was “paused” and “delayed,” respectively, while the tribes and fishers said it was “canceled.” 

Any wind farms built in the two Oregon lease areas would need to employ floating turbines, a further complicating factor. While the fixed-bottom towers being installed in shallower waters along the Northeast coast benefit from a 30-year history worldwide, floating towers are only now beginning to be deployed at scale in areas too deep for fixed-bottom technology. 

BOEM had planned four auctions this year: Central Atlantic, Gulf of Maine, Gulf of Mexico and Oregon. 

Only one company expressed in interest in participating in the Gulf of Mexico auction. (See BOEM Cancels Gulf of Mexico Wind Lease Auction.) 

Seventeen entities were deemed legally, technically and financially qualified to bid in the Aug. 14 Central Atlantic Auction; six submitted bids for two leases areas. (See Dominion and Equinor Win OSW Lease Auction.) 

Fourteen entities are deemed qualified to participate in the Gulf of Maine auction, which is scheduled for Oct. 29. (See BOEM Announces Gulf of Maine Offshore Wind Lease Sale.) 

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NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern

NYISO made significant updates to its assumptions as part of its final Reliability Needs Assessment, which now shows no concern of a capacity deficiency and a loss-of-load expectation of less than 0.1 in 2034.

The dramatic change came from considering certain large loads as flexible, with the ability to reduce total consumption during summer and winter peaks by about 1,200 MW, the ISO told the Electric System Planning Working Group and Transmission Planning Advisory Subcommittee on Sept. 27.

“Based on recent operating experience and outreach to load developers, cryptocurrency mining and hydrogen-production large loads are considered as flexible during peak load conditions,” NYISO said. “This type of load is assumed to be more price responsive and likely to participate in demand response programs than other loads.”

The change in assumptions reduced the forecasted LOLE in 2034 from the preliminary 0.289 that the ISO expected in July to 0.094. NYISO had warned of a potential shortfall of as much as 1 GW in its preliminary results in July. (See Prelim NYISO Analysis: 1-GW Shortfall by 2034.)

“We feel comfortable in certain large loads, primarily like cryptocurrency and hydrogen-producing large loads, to consider them flexible,” said Ross Altman, senior manager of reliability planning for NYISO. “When you have peak load conditions due to either price responsiveness or participation in demand response programs, they would curtail under peak conditions.”

Altman said semiconductor plants, other data centers and most other large loads were not assumed to be flexible.

Several stakeholders asked whether the flexible loads also were modeled as special-case resources formally enrolled in the DR program. Altman replied they were not, merely that they were assumed to be price responsive in some manner.

One stakeholder asked whether there was anything binding cryptocurrency miners to stay as cryptocurrency miners. He made the point that the servers could be put to other, less flexible uses than arbitraging the cost of energy against the purported value of the currency.

“If one or two of them change their use case, it’ll produce a very different outcome in this study,” they said. “You’ll lose that flexibility.”

“That is true,” Altman said. “Hold on to that thought. I’ll show scenarios that will show what things change on the higher end of the forecast, which includes large loads that are not flexible.”

NYISO stressed that “there is a lot of uncertainty about key assumptions over the next 10 years.” In a high-demand forecast risk scenario, the LOLE would jump to 2.744. The delay of the Champlain Hudson Power Express transmission project also is a concern.

“This still seems to be somewhat gambling,” another stakeholder said. “If these loads aren’t in the SCR [program] or they’re not participating in the emergency demand response program, unless you have a tariff or contract under a dynamic load management program, you don’t have any commitments to them to vary their load.”

The working group will review the full draft Reliability Needs Assessment report on Oct. 4. The Operating Committee and the Management Committee will review and vote on the final report on Oct. 17 and 31, respectively, and the Board of Directors will review and post the final report in November.

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NYISO ICAP Working Group Briefs: Sept. 24, 2024

Demand Curve Reset and Transmission Security 

NYISO’s Market Monitoring Unit, Potomac Economics, presented its recommendations for addressing what it calls inefficient market outcomes caused by setting locational capacity requirements based on the transmission security limit (TSL).  

The MMU told the Installed Capacity Working Group at its meeting Sept. 24 that the current rules overvalue surplus capacity, setting “inefficiently high prices” while also overcompensating resources that don’t help satisfy transmission security requirements.  

“We focused in on the last couple of years here,” said Joe Coscia, a director at Potomac Economics. “It’s possible that the current LCR is quite a bit higher than it would otherwise be as a result of the TSL. … We expect that divergence to grow in the coming years with the entry of [the] Champlain Hudson [transmission project] and other resources like offshore wind as well.” 

The Monitor first made the recommendations in its 2023 State of the Market report, after NYISO had changed how it calculates the TSL floor. 

“Large resources and SCRs [special-case resources] are overcompensated when the LCR of their locality is set at its TSL floor,” it said in the report, released in May. “This is because the presence of these resources causes the TSL floor to increase, so they provide less net supply towards meeting capacity requirements than they are paid for in the capacity market.” 

Thus, the MMU recommended paying resources for capacity based on the requirements they actually contribute to meeting. SCRs should be compensated at the price that would prevail in their locality absent the TSL floor, while large, intermittent and storage resources should be paid the full capacity price for the portion of their capacity that does not cause the TSL floor to increase and the capacity price that would prevail absent a TSL floor for the rest of their capacity. 

Coscia said bulk electrical consumers would save roughly $380 million if the Monitor’s recommendations were implemented. The payments for reliability assurance and transmission security should be paid for and determined with separate curves, he said. Implementing sloped demand curves that reflect the marginal value of capacity for transmission security would avoid excessively high prices. 

Multiple stakeholders representing the generation sector asked whether this suggestion would be compatible with the proposed peaker unit being a storage resource for the upcoming demand curve reset. 

“I’m thinking through a lot of how you would set one, particularly with a two-hour battery, and I’m getting a lot of circular reference errors in my mind while thinking through it,” said Shawn Picard, vice president of engineering for TigerGenCo, which operates in the Bayonne Energy Center in New Jersey.  

“The short answer for that is that you put in a different value for the CAF [capacity accreditation factor] [than] is used in the model, and you would get a different value if you assume that the battery, or any of the other technologies, would have a different CAF for [transmission security] than what it has for [resource adequacy],” Coscia answered. “I just don’t want to speculate on what that value might be.”  

Others brought up that making a separate demand curve for transmission security would probably involve creating additional proxy units and make the whole system more complicated. Howard Fromer, director of regulatory affairs for TigerGenCo, asked how real the savings to consumers were that Potomac had calculated. 

“Did you take into account the potential that what you’re ending up doing is creating this much more complicated system and simply shifting payment dollars from the market to subsidies?” Fromer asked. “How much of this $380 million is real versus just a shift, and we just end up having to pay a higher incentive to attract those resources?” 

“I think our position is that it plays a useful role in sending signals accurately: What are the subsidy values that different resources require?” Coscia said. “It may have an effect on what policy-sponsored projects come in based on how much they can get from the market, or from other sources of payment.” 

Final Demand Curve Reset Recommendations

Both NYISO and its consultants presented their final recommendations for the demand curve reset for a last look before stakeholders make oral arguments to the Board of Directors next month.  

Some changes were made to assumptions in response to stakeholder feedback, including the following: 

    • Peak load window hours for the battery energy storage system (BESS) peaker unit were updated to reflect the seasonal periods for 2024-2025. 
    • Voltages assumptions for the BESS were revised downward for all zones outside Long Island. 
    • Operations and maintenance estimates were revised to include land lease payments for the construction period.  
    • Sales tax was added to O&M expenses.  
    • Costs associated with the mortgage reporting tax were added. 

Fromer asked why the consultants had apparently ignored FERC precedent of discretionary programs not being available for offsets for potential developers. He said that when his company built the last peaker plant in New York City, it could not get an exemption. 

Daniel Stuart, a manager at the Analysis Group, replied that they had tried to come up with a reasonable scenario to model that might fit a potential developer. 

“We do think it’s reasonable and perhaps standard for new developers seeking to build batteries or gas turbines in New York,” Stuart said. “That is the logic we applied for the mortgage reporting tax.” 

Fromer and other stakeholders brought up several other issues they felt had been left out, including investment tax credit eligibility, whether a battery system would need to be removed at the end of a land lease, government incentives and future cost reductions. Analysis Group members said that they had not ignored or dismissed these suggestions but that not all of them were convincing enough to warrant revisions. 

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SPP’s Desselle to Retire After 18 Years at RTO

Michael Desselle, SPP vice president and chief compliance and administrative officer, is retiring after 18 years with the RTO and 40 in the industry. His departure will be effective Jan. 2. 

“We’ll definitely miss Michael,” SPP CEO Barbara Sugg said in a Sept. 30 statement. “His dedication to SPP is clear. He’s respected by his peers, as exemplified by his service as chairman of the Board of Directors and CEO of the North American Energy Standards Board. We wish him the best in his well-deserved retirement.” 

Mike Riley, SPP senior director and deputy general counsel, has been promoted to vice president of corporate services and chief compliance officer to fill Desselle’s position. He begins a transition period Oct. 1. 

Attorneys Tessie Kentner and Chris Nolen have been named associate general counsels with Riley’s promotion.