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November 9, 2024

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Maryland Report Details PJM Cost Increases for Ratepayers

The Maryland Office of People’s Counsel (OPC) has published a report on how a spike in capacity prices and generator deactivations will affect state ratepayers, finding monthly costs could increase by as much as 24% for some. 

The largest share of the impact is due to the significant jump in Base Residual Auction clearing prices seen in the 2025/26 auction results released last month, which saw prices across the RTO reach $269.92/MW-day from $28.92/MW-day the year prior. The Baltimore Gas and Electric (BGE) region surged higher to $466.35/MW-day due to a lack of internal generation, and transmission constraints. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

At the same time, ratepayers are expected to cover the cost of a reliability-must-run (RMR) agreement to pay Talen Energy to keep its Brandon Shores and H.A. Wagner generators operational while transmission upgrades are built to accommodate the plants’ deactivations. Talen has requested $774 million in a pending FERC filing to keep the generators online (ER24-1787, ER24-1790). (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.) 

The cost of those transmission upgrades also likely will fall squarely on Maryland ratepayers: Of the $726 million in upgrades required before the Talen generators can retire, 81%, or $630 million, is estimated to be allocated to the state. (See FERC Approves PJM RTEP Projects over State Protests.) 

In an announcement of the report, Maryland People’s Counsel David Lapp said the same resource deactivations are hitting Maryland ratepayers on multiple fronts, raising capacity costs and saddling them with high transmission upgrade and RMR costs while those plants are paid to remain idle, but not contributing capacity.  

“Customers are facing massive rate increases from potential retirements of old and uneconomic fossil fuel power plants — potential retirements that were entirely foreseeable and that PJM should have planned for,” Lapp said. “Customers will bear the brunt of PJM’s planning failures and other dysfunctional market rules, while generation companies will walk away with record profits.” 

Conducted by Synapse Energy Economics on behalf of the OPC, the analysis estimates that BGE rates could increase by 5% to cover the RMR costs and an additional 14% due to the higher capacity costs, which amounts to an additional $21 for the average residential customer. The capacity market impacts also will be felt in the APS, DPL-S and Pepco zones, which could see rates increase by 24, 2 and 11%, respectively. 

Taking Brandon Shores and Wagner out of the capacity market had a significant impact on prices in the BGE zone, Synapse wrote, stating that in the years running up to the 2025/26 auction, about a third of the capacity consumed in the region was produced locally. Removing the two generators brought that figure down to about 10%. The report estimated that if Brandon Shores and Wagner had remained in the capacity market, the BGE zone would not have seen price separation from the rest of the RTO, which would have seen the clearing price halved to $163.46/MW-day. 

“At that price, electric customers across the RTO would save over $5 billion in that delivery year. Further, comparing this counterfactual analysis to the actual results of the capacity market and Talen’s proposed RMR, we found that Talen’s revenues for the 2025-2026 delivery year are $360 million higher than what they would have been had Talen’s units participated in the capacity market,” the report said. 

Lapp said a small number of deactivations are causing an outsized spike in rates. 

“The fact that the retirement of such a relatively small amount of generation could cause capacity market price spikes that cost customers across PJM more than $5 billion shows … PJM’s market is stacked against the customers that pay the bills,” Lapp said. 

Market Changes and Queue Backlog Contributing to Higher Prices

The report notes that several changes to the capacity market structure were implemented in the 2025/26 BRA, including using a marginal effective load carrying capability (ELCC) approach to accrediting resources and risk modeling that shifted the riskiest hours toward the winter. Those redesigns had the effect of shifting the variable resource rate (VRR) curve to the left, reducing available supply and likely increasing costs. Forecast peak loads also increased by over 3 GW in the 2025/26 delivery year, increasing demand. (See FERC Approves 1st PJM Proposal out of CIFP.) 

The report also argues that PJM has left customers vulnerable to high prices by delaying capacity auctions while rule changes are implemented, compressing the auction schedule and leaving little time for generators to be planned to take advantage of high prices and to increase available supply. Under the current schedule, the 2026/27 BRA is scheduled to be conducted in December, 1.5 years before that delivery year begins. Paired with a backlogged interconnection queue, it says it’s unlikely any large generators will come online before Brandon Shores and Wagner are set to deactivate in 2028, potentially leaving high prices in place for years. 

“Thus, the strong price signal sent by the high-capacity market prices in the BGE LDA (and the RTO as a whole) may not induce timely new generation into service within the LDA before the completion of the transmission lines that end the need for these RMRs (or to help alleviate prices seen across the region). Instead, the clogged queue could lock in a windfall for the existing generating units continuing to operate in the BGE LDA and across the PJM region generally,” the report says. 

There are 13 projects pending in the interconnection queue that would be sited in the BGE zone, amounting to about 1.2 GW of capacity. Construction on those projects could begin in mid-2025, according to PJM’s queue timeline, to begin mitigating capacity prices in 2026/27. The amount of time needed for construction, though, could result in many units coming online after that auction. Historical completion rates also suggest a share of those projects will be canceled, the report says. 

The report states there’s a great deal of uncertainty on the transmission side, stating that 3.5 years to complete the upgrades necessary to allow the Talen generators to retire without issue could prove to be too short. If more time is needed, the RMR agreement could be extended. 

“If the transmission projects are not complete by the end of 2028, and/or the continued operation of the RMR units are required beyond December of that year, the RMR costs for electric customers would necessarily increase,” the report said. 

Deputy People’s Counsel William Fields told RTO Insider he doubts there will be time for the price signal sent in the 2025/26 auction to lead to new resources coming online ahead of future auctions. The interaction of a backlogged interconnection queue and compressed auction schedule leaves ratepayers with the worst of both worlds: paying generators to remain online without them being in the capacity supply stack to offset auction prices. 

“A price signal without an ability to respond to it doesn’t accomplish much other than customers paying more money,” he said. 

He said concerns about the auction outcome were mounting ahead of the posting of the results, leading the OPC to commission the report. While the spike in prices will have a significant impact, he said transmission costs have been steadily making up an increasing share of consumers’ rates. Some of those new projects could lead to reduced congestion, but whether that will come to pass is not yet apparent. 

Stakeholders Discussing Changes to RMR Rules

PJM stakeholders are considering changing several areas of how RMR agreements function, including the timeline generators must provide PJM ahead of their desired deactivation date, how the compensation rate is determined and possible alternatives to the RMR structure. The Deactivation Enhancement Senior Task Force met Aug. 19 to discuss proposals from the Independent Market Monitor and PJM that would seek to use actual incurred costs to be the basis of RMR compensation. 

The OPC sought a wider scope for the task force, including education on transmission technologies, such as energy storage or grid-enhancing technologies (GETs), that can provide an alternative to traditional upgrades, comparable structures RTOs employ to keep resources online when they are needed for transmission reliability and cost-effective alternatives to RMRs. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.) 

The office also has advocated for proposals that require RMR resources to participate in the capacity market, which both the Monitor and PJM have declined to include. In a May protest of Talen’s RMR filing, the OPC argued the agreement would not subject the generators to the same performance requirements resources participating in the capacity market are held to, raising the question of whether they would be capable of responding to a PJM deployment. (See FERC Orders Settlement Judge Procedures in Two PJM Generator Deactivations.) 

The Planning Committee also is considering proposals on how revising capacity interconnection rights (CIRs) can be transferred from a deactivating generator to a new resource. One aim would be reducing the need for RMR agreements by creating an expedited process for planned resources that could resolve identified transmission violations. The five packages are slated to be voted on during the Sept. 10 PC meeting. That could, however, be delayed to October if the components are changed substantially. (See “Manual 14B Revisions Include Change to Light Load Model,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

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NYISO Presents Initial 2025 Project Budget Recommendation

Kevin Pytel, NYISO director of product and project management, presented the ISO’s initial 2025 budget recommendations Aug. 13 to the Budget and Priorities Working Group. 

If approved, the 2025 budget for projects would be about $42.1 million. More than half of that would be spent on labor and professional services to execute projects. 

The projects selected for initial inclusion include: 

    • capacity market structure review: a look at whether changes are needed to send accurate price signals in the capacity market. 
    • engaging the demand side: a project that would let behind-the-meter solar supply energy to wholesale markets. 
    • balancing intermittency: an attempt to maintain reliability with intermittent, zero-emissions power via potential market rule changes. 
    • winter reliability capacity enhancements: a project intended to address the looming challenge of a winter peaking system to the ICAP market. 
    • winter fuel constraint study: a look at how extreme winter weather could affect the fuel available to natural gas generators and how fuel constraints could change over the next decade. 

Detailed project descriptions can be found here.  

“We’re really trying to maximize the value of the markets with this proposal and pay attention to stakeholder scores to ensure that we’re choosing projects that have stakeholder support,” Pytel said.  

“We recognize that there are a lot of high-priority projects that were scored that were not selected in the initial recommendation,” Pytel said. “If there are projects that you feel should be in the recommendations, which projects would you like to see come out to accommodate those?” 

Kevin Lang of Couch White drew attention to the operating reserves performance project that was cut. “There was one in particular that piqued our interest that isn’t about maximizing value; it’s about protecting people and making sure that we’re not giving certain market participants windfall profits that didn’t make your list,” Lang said.  

The operating reserves performance project would ensure that energy suppliers’ stated operating reserves were accurate and that suppliers were compensated to reflect actual performance. 

Pytel said all feedback would be shared with NYISO executives. He said NYISO’s CEO was available to speak with stakeholders who felt strongly about some particular project or other.  

This is the second-to-last phase of developing the budget before NYISO proposes its initial 2025 budget in September. NYISO will take feedback and return to stakeholders with revisions Aug. 27. The 2025 budget is scheduled to be finalized by Nov. 19.  

Pytel highlighted several high-priority projects that were not selected due to resource constraints. The hybrid aggregation model project, which would broaden the number of resources that could use on-site energy storage and share the same interconnection, was put on hold until 2026. 

A project to develop an operating protocol to integrate Champlain Hudson Power Express (CHPE) also was removed from the proposed budget. CHPE is a high-voltage connection between Hydro-Quebec and NYISO that’s expected to come online in 2026. 

Several continuing projects have been delayed until 2026, including the hybrid aggregation model project, which would allow for more generation and storage facilities to exist on the same site.  

“The hybrid aggregation model, it’s disappointing to see this getting delayed a year,” said Chris Hall of the New York State Energy Research and Development Authority. “On top of that … it’s a little bit surprising that we’re taking continuing projects and pushing them back.” 

Pytel said projects being pushed back weren’t being canceled, but deprioritized. He pointed to a data center project at NYISO headquarters that’s being slowed down to free up some money so NYISO can finish other projects. 

Pytel said some of the projects were dropped because of newly discovered resource constraints. One project, storage as transmission, was found to be more resource-intensive than NYISO initially estimated. A stakeholder pointed out that NYISO was working to comply with FERC Order 1920, which calls for incorporating non-transmission solutions into the transmission planning process. The dropped project could be rolled into the compliance process. Pytel said he would need to discuss that more with NYISO staff. 

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FERC Accepts Changes to SPP’s WEIS Market

FERC has accepted SPP’s revisions to its Western Energy Imbalance Service (WEIS) market’s tariff related to the residual supply index (RSI) and ensuring that affiliated market participants’ resources are evaluated together (ER24-2208).

In its Aug. 15 letter order, the commission found the revisions will help identify and address structural market power in the WEIS market by ensuring a market participant affiliate’s online resource capacity is evaluated in the RSI calculation. It said the proposed revisions modify the market’s existing definition of “affiliate” by incorporating FERC’s regulations and require market participants to affirmatively identify affiliates when they register in the WEIS market and on an ongoing basis.

SPP’s Market Monitoring Unit determined in 2020 that the WEIS market had a high level of structural market power when viewed through the RSI, or the ratio of residual supply to total market demand. The RTO said that under the calculation, affiliated market participants’ total capacity is not evaluated together and creates a situation in which an entity can split its fleet of resources into multiple market participant registrations to avoid any one of the market participants failing the RSI calculation.

The grid operator’s proposal addressed FERC’s concerns when it rejected SPP’s first attempt in December. The commission found that allowing the MMU to exclude affiliated capacity from the RSI calculation if the monitor determined there were sufficient safeguards and corporate controls was not just and reasonable. The MMU, which supported SPP’s revisions, now can exclude affiliated capacity from the RSI calculation.

The RTO still must make an informational filing notifying FERC of the revisions’ actual effective date no less than 30 days prior to their implementation.

SPP has administered the WEIS market on a contract basis since February 2021. It serves 12 participants.

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Stakeholder Soapbox: PJM Resists Battery Storage Reforms Given to Data Centers

Battery storage facilities and data centers added to existing generator locations have a lot in common, with both supply and demand on a single interconnection. Yet despite the similarities, PJM is refusing FERC Order 2023 requirements regarding flexibility on charging battery storage while offering data center co-location projects those same provisions. 

Mike Jacobs

PJM treats storage interconnection requests as an unavoidable driver of peak demand, while Order 2023 provides the option to assume the opposite. The PJM framing of interconnection causes batteries to appear to exacerbate transmission problems from plant retirement and require additional transmission upgrades, rather than meeting the system need caused by retirement. 

(PJM’s claims of unsolved problems with providing storage developers the ability to define operational limits are on Page 27 of Answer to Protests filed in July 2024.) 

This is in direct opposition to the Order 2023 directive (starting at paragraph 1,448) that allows energy storage projects to define their interconnection operational limits on charging. 

PJM claims that storage asset owner commitments, real-time monitoring equipment and system protection controls are all insufficient and incapable of limiting battery charging operations throughout its interconnection rulemaking comments and initial Order 2023 compliance filing. 

Simultaneously, PJM developed guidelines and interconnection agreements for data centers co-located with generation, allowing those asset owner commitments, real-time monitoring equipment and system protection controls to limit data centers from creating transmission system demand. 

In March, PJM published guidelines for co-located load with a new or existing generation facility. PJM includes data center loads as an example of a more sophisticated and flexible treatment of both a supply and a demand at a single point of interconnection. PJM now provides an interconnection agreement for such co-located facilities after study of their proposal. 

Meanwhile, PJM simultaneously argues it cannot modify interconnection manuals’ treatment of energy storage facilities as inflexible loads. This accommodation of co-located load illustrates PJM’s ability to establish sensible requirements through interconnection agreements that could allow both data centers and energy storage assets to contribute to the economy without undue obstacles.  

Neither the co-location guidelines nor the interconnection manuals have been filed at FERC, but the efforts by PJM to continue discriminating against storage interconnection were expressly rejected by FERC in Order 2023. 

PJM’s effort seeking reconsideration of this practice also was rejected by FERC. A third attempt by PJM to avoid compliance with the provision that storage be able to request to be limited from charging on peak, which is recognized elsewhere in the U.S., is included in FERC’s current refusal to accept PJM’s compliance filing for Order 2023. 

FERC has given PJM until late October to once again explain why its noncompliant load deliverability tests for storage interconnection requests, which also disqualify storage from surplus interconnection and CIR transfer opportunities, should be permitted. 

PJM’s refusal to comply with Order 2023 is a disservice to the millions of people who rely on the interconnection process to address supply needs and provide just and reasonable rates. 

FERC’s directive more accurately reflects a wholesale market where storage assets can arbitrage between charging in low-price, off-peak hours and selling only in peak periods. PJM’s disparate treatment of energy storage load is not based on science or engineering. 

Just as they negotiated provisions for data centers, they must do the same for storage. The RTO’s next Order 2023 compliance filing is the time to make this change. 

Mike Jacobs, of the Union of Concerned Scientists, advocates at PJM, FERC and state commissions for the reliable expansion of the grid for renewable resources. 

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Pathways Initiative Committee Floats Ideas to Protect Public Interest

Protecting the public interest while implementing the Extended Day-Ahead Market (EDAM) and expanding the Western footprint was central to the discussion in a West-Wide Governance Pathways Initiative workshop Aug. 15.

“How are we going to continue to serve the public interest with an expanded footprint and with alternative, different governance?” Alice Reynolds, president of the California Public Utilities Commission, asked.

Members of the launch committee sought feedback on a combination of tools that could protect the public interest across the footprint of the regional organization (RO) the Pathways Initiative seeks to establish.

Beyond regulation by FERC, members discussed five main components that could be integrated into the structure of a new RO, including a stakeholder process, an independent market monitor, consumer advocate engagement, a states committee and an RO board.

In the implementation of an RO board, members emphasized public interest protection language in the articles of incorporation and the charter provisions. Also deemed important: a commitment to expand public benefits by attracting new participants, protecting individual state and local generation preferences and climate policies, holding open meetings and adhering to open records requirements.

Board members should have a history of protecting the public interest in their official roles, said Ben Otto, consultant with NW Energy Coalition and a launch committee member.

“There can be standards of duty for the board that are incorporated, like they have to act to protect public interest, and that is then their obligation when they’re acting as a board member, to follow those requirements and not their own wishes,” Otto said.

The RO also could establish a states committee that would maintain the current Western Energy Imbalance Market Body of State Regulators structure with a charter requiring protection of the public interest. Under this structure, states individually or through the committee could continue to submit 206 pleadings at FERC.

Other aspects of the committee would be having access to market monitor data, having the power to originate a stakeholder initiative with support from half of the participating states or half the load, having a seat on the RO board, and having veto rights over RO board nominations with a two-thirds vote of states and load. A subset of the committee representing one-quarter of states or load could vote to trigger a requirement for a supermajority vote on a particular topic.

Consumer advocates also could play a role by participating in stakeholder processes, having access to market monitor data and obtaining a seat on the RO board.

“This is absolutely necessary to ensure that the board is well informed on consumer issues. Being informed on consumer issues, we think, is key to fulfilling the public interest mission that we’ve laid out here in Pathways,” said Michele Beck, director at the Utah Office of Consumer Services and a member of the launch committee.

Individual consumer advocate offices aren’t resourced enough to participate in these processes, Beck said, creating the need for a central consumer advocate organization that could maintain interaction with RO processes. Launch committee members suggested the creation of a 501(c)(3) organization that could facilitate consumer advocate participation. Beck highlighted the Consumer Advocates of the PJM States (CAPS) program as an example worth replicating.

Launch committee members also highlighted other existing structures within the CAISO model that could be carried forth in the new RO, including the ISO’s Department of Market Monitoring and Market Surveillance Committee.

Additional ‘Tools in the Toolbox’

Stakeholders provided additional ideas for protecting the public interest.

“One other tool that we should have in the toolbox for protecting the public interest is really allowing and enabling the public to participate in our decision making to the extent that it’s appropriate,” said Mark Specht, Western states energy manager at the Union of Concerned Scientists and a member of the launch committee. “Things we might consider would be creating some sort of office of public engagement that would really serve as a resource for folks who are interested in participating and having their voices heard in our decision making.”

Preserving state and local autonomy within regions also was a primary point of conversation given the different laws, policies and preferences within each state.

“We’ve really been thinking about, how do we create a system that explicitly acknowledges and protects the ability for states to keep that authority in place and enables states to really develop their own vision of what the public interest is?” said Kathleen Staks, executive director of Western Freedom and co-chair of the Pathways Initiative. “What tools holistically across the entire regional organization ensure that the regional organization protects the public interest in lieu of a single state statutory requirement like we have with the CAISO today?”

Commissioner John Hammond of the Idaho Public Utilities Commission echoed concern over the challenge of defining the public interest given the array of different players.

“There are obviously common interests in keeping costs low and in reliability, but I worry about when we start getting into policy areas and what impacts that might have on the individual states that have different policies,” Hammond said. “My fear is you start incorporating too many things in the toolbox, you might get a reaction legislatively from particular states … so I think it’s very important that we define exactly what public interest we are trying to protect.”

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Corrected: NYISO Operating Committee Briefs: Aug. 15, 2024

The NYISO Operating Committee has approved two study reports and one study scope, all of which involve load projects in northern New York.  

The SDC St. Lawrence interconnection study modeled the impact of the 120-MW load project on the local system. NYISO staff found that the project would cause thermal overload that could not be mitigated with adjustment. In sensitivity scenarios, the project caused voltage violations and voltage transfer degradation.  

NYISO estimated the cost to build the attachment facility for the interconnection is $55 million, plus or minus 50%, and it would take about 54 months to complete. The cost to mitigate the thermal overload issues and the voltage transfer degradation issues were $33.6 million and $37.5 million. Voltage violations would cost an estimated $2.5 million to mitigate. An additional estimated $39 million would be needed to mitigate thermal issues at the transformer. 

The customer asked if there was a different software package that could be used to help reassess costs. 

“We can take it back and consider it, but I don’t believe the additional capability of the distributed model at St. Lawrence would resolve these overloads” or alleviate upgrade costs, said Aaron Markham, vice president of operations for NYISO.

In the study report for the Massena Green Hydrogen project, a 110-MW hydrogen electrolysis plant, no adverse impacts to the grid were found. NYISO found that interconnection would be feasible with the construction of a new three-breaker and bus substation. The estimated cost for the interconnection would be about $27.7 million, and the project would take two to three years to complete. 

The Cayuga Compute 150-MW data center scoping study was discussed and approved. The study will perform reliability and cost-estimation analysis similar to the reports listed above. 

Other Business

The Operating Committee also heard the July 2024 Operations Performance Report. Peak load was 28,990 MW, which set the new summer 2024 peak. Markham said this was because of higher-than-average temperatures.  

He noted that NYISO also had to call on the Emergency Response Demand Program and Special Case Resources during the evenings of July 15-16. Markham said they hit scarcity pricing on both days. 

“On the 16th of July, a number of severe thunderstorms, including 10 confirmed tornadoes, occurred in the state as the remnants of Beryl passed through,” Markham said. He said that caused simultaneous outages for about 275,000 customers.

“There was a tornado in Buffalo early last week, and from what I saw, that broke the [record for the] number of tornadoes that occurred in the state,” Markham said. “That was 25 back in 1992; we are up to 26 this year.”  

The committee also reviewed and approved supplemental manual updates for constraint-specific transmission shortage pricing. These updates to the day-ahead scheduling manual and transmission dispatch operations manual are described here. Drafts may be seen here and here. 

Eds: A previous version of this article incorrectly referred to the SDC St. Lawrence as the North Country Data Center.

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NYISO Tariff Revisions Include Uncertainty Reserve

NYISO staff have presented tariff revisions that may be deployed as early as the first quarter of 2026 to account for the uncertainty of wind and solar energy forecasts. The filing date with FERC has yet to be determined.

If accepted by FERC, the revisions would add two new items to the tariff, uncertainty reserve requirements and scarcity pricing in 30-minute reserves for the New York Control Area and several downstate zones. These requirements would add a stepwise demand curve to the market.

“Uncertainty reserve requirements for operating reserves are here to account for the forecast uncertainty of node wind and solar energy forecasts,” Vijay Kaki, market design specialist for NYISO, said at the Installed Capacity Working Group meeting Aug. 13.

Kaki explained the uncertainty reserve requirements would be calculated for, and apply to, the day-ahead and real-time markets. For the day-ahead market, the uncertainty reserve would apply only to the 30-minute reserve product. In the real-time market, these new reserves would be calculated for both 10- and 30-minute reserve products.

For the day-ahead market, the reserves would be calculated for each hour of the day, before the day-ahead market run.

“It’s a daily change,” said Kaki, explaining this was based on annual forecast data. “The annual metrics are calculated once a year, and those metrics will be applied to the day and market forecast data on a daily basis.”

The NYISO price scheme is intended to encourage generators to respond quickly to requests for energy to meet reliability requirements. The market would pay more for generators who activate when operating reserves and uncertainty reserves are low.

Revisions to the tariff, along with a consumer impact analysis, are expected to be done by the end of the third quarter.

Winter Reliability Enhancements

After discussing the tariff revisions, NYISO presented the winter reliability capacity enhancement project that tentatively is scheduled for 2025. The idea is to ensure the capacity market provides the correct price signals all year to ensure reliability as New York transitions to a winter-peaking system.

“We’re looking at this project to consider what would be the process for setting winter CAFs [capacity accreditation factors] and would they be any different,” said Michael Swider, senior market design specialist for NYISO.

Swider said the market needed to be evaluated to look for elements that are more affected by a more seasonally differentiated capacity market. Currently there is one installed capacity requirement that is applied to an entire year that is forecast based on annual peak load, which occurs in summer.

NYISO projects the system will transition to a winter peak in the 2030s. The RTO has stated its concerns about fuel constraints occurring in winter, particularly if the system is winter peaking. (See NYISO Braces for the Coming Winter.) Because the current ICAP is calculated based on summer load, NYISO staff worry the current system may cause reliability and market issues.

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PJM MRC/MC Preview: Aug. 21, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Aug. 21. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will cover the discussions and votes. See the website and next week’s newsletter for a full report. 

Markets and Reliability Committee

Endorsements (9:10-11:30)

  1. Enhanced Know Your Customer (9:10-9:30)

PJM’s Anita Patel and Eric Scherling will present a proposal to tighten PJM’s know your customer (KYC) rules, which require members to provide information to facilitate the due diligence PJM conducts on key decision-making leadership. The tariff changes would require nonpublicly traded members to provide the names of beneficial owners, board of director members and principals. PJM then would conduct background checks on them. The committee deferred voting on the language during the July MRC meeting to review changes to the definitions of principal and beneficial owners added to the language after its first read. (See “Vote on Enhanced Know Your Customer Deferred,” PJM MRC Briefs: July 24, 2024.) 

The committee will be asked to endorse the proposed solution and tariff revisions. 

Issue Tracking: Enhanced Know Your Customer 

  1. Re-evaluation of Financial Parameters Used in CONE for 2027/28 BRA (9:30-9:50)

PJM’s Skyler Marzewski will present a proposal to recalculate the after-tax weighted average cost of capital (ATWACC) and bonus depreciation values for the 2027/28 Base Residual Auction (BRA). Both of the values are used in the calculation of the cost of new entry (CONE) and have been the topic of discussion as some stakeholders argue that changing market conditions, interest rates in particular, have substantially changed the financing of new generation. (See “PJM Proposes Increased CONE Parameters,” PJM MRC Briefs: July 24, 2024.) 

The committee will be asked to endorse the proposed solution and corresponding revisions to the tariff and Manual 18. Same-day endorsement may be sought at the MC. 

Issue Tracking: Financial Assumptions Used to Calculate Gross CONE 

  1. Automating Bid Duration for Economic DR Participating in Energy Markets (9:50-10:10)

PJM’s Pete Langbein is set to present a proposal to create two new energy market parameters for demand response (DR) resources: a minimum down time and minimum release time.  

The committee will be asked to endorse the proposed solution and corresponding Manual 11 revisions. 

Issue Tracking: Automating Bid Duration for Economic Demand Response Participating in Energy Markets 

  1. Evaluation of Energy Efficiency Resources (10:10-11:30)

Langbein will present a proposal to revise how PJM measures and verifies the capacity offered by energy efficiency (EE) resources. The changes would require EE providers to demonstrate a causal link between capacity market revenues and the viability of their projects, obtain exclusive rights to offer energy savings associated with a project as capacity and reduce the period for which installations can be offered as capacity from four years to one. (See Stakeholders Endorse PJM EE Measurement and Verification Proposal.) 

The committee will be asked to endorse the proposed solution. Same-day endorsement may be sought at the Members Committee. 

Issue Tracking: Evaluation of Energy Efficiency Resources 

Members Committee

Consent Agenda (4:05-4:10)

B. Endorse proposed tariff and Operating Agreement (OA) revisions addressing the performance impact of the multi-schedule model on the Market Clearing Engine. The proposal would use a formula to select one schedule for each generator to be modeled in the real-time market in an effort to prevent multi-schedule modeling from leading to an untenable increase in MCE computation times. (See “Schedule Selection Formula Endorsed,” PJM MRC Briefs: July 24, 2024.)

Issue Tracking: Performance Impact of multi-schedule model in Market Clearing Engine (MCE) in nGEM Enhanced Combined Cycle (ECC) and Energy Storage Resource (ESR) models

C. Endorse proposed tariff and OA revisions intended to resolve delays in how reserve resources are deployed. The changes would transmit deployment instructions through resources’ basepoints, in addition to the existing automatic spin event and all-call notifications, as well as empowering operators to dispatch reserves at a percentage of their maximum commitment. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.)

Endorsements (4:10-4:40)

  1. Enhanced Know Your Customer (KYC) (4:10-4:20)

Patel and Scherling will review the proposed KYC tariff revisions. 

The committee will be asked to endorse the proposed solution and corresponding tariff revisions. 

  1. Re-evaluation of Financial Parameters Used in CONE for 2027/28 BRA (4:20-4:30)

Marzewski will review the proposed changes to the financial parameters underlying the gross CONE value in the most recent quadrennial review. 

The committee will be asked to endorse the proposed solution and corresponding tariff revisions. 

  1. Evaluation of Energy Efficiency Resources (4:30-4:40)

Langbein will review the proposed changes to energy efficiency measurement and verification. 

The committee will be asked to endorse the proposed solution and corresponding governing document revisions. 

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FERC OKs $116M Settlement for New Orleans over Grand Gulf Nuclear Mismanagement

FERC sanctioned a partial settlement to resolve many of the New Orleans City Council’s longstanding complaints over management of the Grand Gulf Nuclear Station.

The commission in an Aug. 14 order said Grand Gulf operator and Entergy subsidiary System Energy Resources, Inc.’s (SERI) $116 million partial offer seemed fair and in the public interest (ER18-1182-008).

The settlement resolves numerous grievances New Orleans officials made in 20 FERC dockets related to subpar Grand Gulf operations, ratemaking and tax violations that shifted costs to customers, an unreasonable capital structure and return on equity and excessive costs of the Grand Gulf sale-leaseback renewal. The earliest docket involved in the settlement stretches back to 2017.

The New Orleans City Council settled with Entergy unofficially last spring in a three-part agreement: $116 million to settle allegations around misconduct within SERI; $138 million more to resolve allegations of dubious tax accounting; and lastly, $500,000 to put concerns over reliability to bed. (See Entergy Earnings Call Focuses on La. Resilience Plan, Nuclear Outage and Settlements.)

The partial settlement provides a return on equity moratorium: SERI will use a fixed, 9.65% ROE in monthly sales to Entergy New Orleans that began in June and will continue through June 30, 2026. The agreement also stipulates SERI’s equity ratio in its capital structure won’t exceed 52% in bills to Entergy New Orleans.

Entergy’s operating companies in Arkansas, Mississippi, Louisiana and New Orleans purchase Grand Gulf’s power through SERI. The state public service commissions from the trio of states all have or are on the verge of agreeing to their own settlements with SERI over mismanagement of the southwest Mississippi nuclear plant, with Louisiana the latest to agree to an offer. (See Entergy Touts Louisiana Settlements, Beryl Response in Q2 Earnings.)

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New York Orders Utilities to Join in Proactive Grid Planning

New York is ordering electric utilities to plan for expected future demand from the clean energy transition and identify urgent infrastructure needs that already exist. 

The Public Service Commission on Aug. 15 ordered “proactive planning for upgraded electric grid infrastructure” (Case 24-E-0364) with hopes of meeting the increasing loads created by electrified buildings and battery-powered transportation. 

New York and its electric utilities have anticipated and planned for much higher electric use for most of a decade. But it often has been a top-down process that can move much more slowly than load grows. So, a bottom-up approach that is more granular — and hopefully much faster — is being added. 

The state’s six major investor-owned electric utilities are directed to collaborate to develop two filings: a proposal for proactively planning to meet the future needs of transportation and building electrification and a proposal identifying urgent needs that may need to be met before the process detailed in the first proposal can be put into motion. 

Heat pumps and electric vehicle chargers can be ordered and installed in a matter of weeks or months, but an upgrade to the utility infrastructure supporting them can take more than seven years to move from concept to completion. 

The order seeks to narrow this gap, and also to create a unified planning process across the utilities to reduce the chance of infrastructure upgrades being redundant, insufficient or misaligned across utility territories. 

This new bottom-up process is intended to complement the Coordinated Grid Planning Process (CGPP) created in August 2023 (Case 20-E-0197), which involves the same utilities but is more suited to a top-down focus on high-voltage transmission, the order explains. 

The utilities are directed to recommend whether this new proactive process can formally integrate with the CGPP and, if so, how. 

When Schuyler Matteson, clean energy planning lead at the Department of Public Service, completed his presentation on the proposed order, PSC Chairperson Rory Christian said, “I want to clarify something in case some are left with the impression we just figured this out. We did not. In fact, this particular proceeding has been quite some time in development.” 

Some of the PSC cases on which this new process is built date back almost a decade, Christian added. “We’ve known this problem was coming.” 

Commissioner John Maggiore asked, “Why haven’t we done this already?” 

Matteson explained how it took so long, rather than why: Some groundwork already was in place, but the PSC’s July 2020 electric vehicle make-ready order really began the process by which staff “identified some significant differences between planning for transportation loads versus traditional electric system planning and how there was some conflicts there in the ways the loads show up and how to plan for those loads.” 

Commissioner Uchenna Bright asked if the rate of electrification of buildings and vehicles had accelerated and if the state is trying to be more strategic about infrastructure investments in response. 

“I think that’s exactly right,” Matteson said. “We had fairly stable both peak and average load growth over the last five or 10 years. But as we see fleets responding to both our policies and national policies, we see large, very chunky popcorn-type loads popping up around the state that might be 5, 10, 20 megawatts at a time, which is a very significantly sized load.” Sales of individual electric vehicles and heat pumps add to the load, he said. 

Commissioner Denise Sheehan said she thought coordinating the new proactive process with the existing CGPP would be essential. She asked about the economic development potential. 

“I would say there’s a couple of ways it’s implicated,” Matteson replied, noting the number and variety of new load requests coming in and the different approaches to meeting them. 

“So, a lot of the largest types of loads, the 50-, 100-MW-plus loads that might be coming into the system, they’re likely to be captured under the Coordinated Grid Planning Process, because they often have transmission-level interconnections,” he said. 

“But to the extent that we do see significant adoption of new loads coming on of the system on the distribution network, those will have to be incorporated into the distribution scale load forecast that the utilities will use to identify these infrastructure planning upgrades.” 

Commissioner Radina Valova said her main concern in considering the draft order had been whether the loads utilities projected actually would materialize. 

“Will the commission have the opportunity to review the utilities’ proposed forecasting methodologies,” she asked, “including their underlying inputs and assumptions, the methodologies that they will use specific to the proactive planning process?” 

Matteson replied that it’s important to fill the gap “that we think exists right now in terms of really granular, longer-term forecasting for EVs and building electrification.” 

As part of the filing that’s requested, 120 days from now, utilities will propose “those different load forecasts, those planning methodologies.” That allows time to evaluate utility proposals, and in “the actual development process of the planning framework, we expect to have some more back-and-forth with the utilities on specifically what data sets are most relevant here.” 

Commissioner David Valesky also asked about the commission’s role going forward. 

The PSC will be involved repeatedly and soon, Matteson said. 

“We heard about a couple of [urgent projects] through our stakeholder process and through the technical conferences where National Grid and Con Edison have already identified projects that may need to enter construction within the next year or so, so those urgently needed projects would come within about 90 days, and then we’d be able to evaluate the need to fund those projects,” he said. 

The commission approved the order with a 6-0 vote.