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December 26, 2024

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ISO-NE Outlines ‘Straw Scope’ of Capacity Market Reforms

ISO-NE responded to stakeholder feedback on its capacity auction reform (CAR) project at the NEPOOL Markets Committee meeting Aug. 6, providing clarity on the scope of its capacity market overhaul.

Chris Geissler, ISO-NE’s director of economic analysis, outlined the “straw scope” of the reforms, including which topics likely will be included in the project, and those remaining under consideration.

The CAR project is intended to coordinate resource accreditation reforms with changes to the time frame of capacity auctions. ISO-NE plans to move from the current forward annual auction format to a prompt seasonal auction for the 2028/29 capacity commitment period (CCP).

This change would reduce the time between the auction and the CCP and would split the yearlong CCP into seasons. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.)

Geissler presented ISO-NE’s initial thoughts on the scope to the MC in July, and stakeholders submitted written comments prior to the August meeting. (See NEPOOL Markets Committee Restarts Work on Capacity Market Changes.)

The core aspects of the project include defining the timing and schedule of the prompt reforms, the treatment of new and retiring resources, and the delineation of seasons in the CCP, along with finalizing the accreditation reforms, Geissler said. The project also will include a focus on offer price formation, accounting for gas constraints and updating the current data systems, he added.

ISO-NE also plans to move from a descending clock to a sealed bid, which was recommended by the External Market Monitor. He said sealed bids would help enable simultaneous (instead of sequential) seasonal auctions, which ISO-NE is considering to allow bidders “to submit offers that separately reflect seasonal and annual costs.”

Geissler said the RTO still is considering whether to include an evaluation of how it will model resources that are retained via out-of-market mechanisms, tie benefits and correlated temperature-related outages.

He added ISO-NE will consider whether it can improve the existing load model used for accreditation, along with the modeling frameworks used for different resource types. Storage developers argue the RTO’s load modeling has produced unrealistic capacity shortfall events. (See ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.)

The RTO is unlikely to include in the scope a reconsideration of the underlying software program used for the accreditation modeling, or an evaluation of modeling of resource start time. Some stakeholders argue in favor of modeling resource start time, and the External Market Monitor (EMM) has highlighted the issue.

“Resources with long startup times that do not operate frequently provide less reliability value than more flexible units,” the EMM noted in 2021.

Scope Feedback

Prior to the meeting, a wide range of stakeholders submitted written comments on ISO-NE’s scope proposal.

A coalition of clean energy companies and environmental advocacy groups called on ISO-NE to “facilitate more discussion on how the modeled risk relates to observed real-world risk.”

Storage developers expressed concern that the new accreditation framework will lead to a significant reduction in capacity market revenue for storage resources. The impact analysis results presented in the previous stage of the accreditation project indicated storage would see the most significant revenue reduction of all resource types. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.)

Several solar companies also submitted comments urging the RTO to consider “enhancements to the modeling framework” for co-located solar and storage resources.

LS Power made the case that accreditation should account for unit-by-unit differences in natural gas availability for gas generation. The company has stressed that gas availability when temperatures decline varies significantly by state and by unit, and ISO-NE’s current accreditation proposal would not account for these differences.

“Just as the current Forward Capacity Auction methodology recognizes locational variations and unit-specific characteristics for accreditation, ISO’s CAR accreditation approach to natural gas accessibility must do the same,” LS wrote.

Meanwhile, RENEW Northeast expressed support for ISO-NE’s proposal for accrediting gas resources, writing that “the proposed market constraint for gas, as part of the seasonal market, appears to be a significant improvement and we appreciate that ISO continues to plan for this as part of the initial market reform effort.”

Calpine advocated for a simultaneous clearing design for seasonal auctions, writing that it has “grave concerns with a seasonal construct that does not allow or permit resources the opportunity to recover full (annual) costs.”

The company also stressed the scope should include an evaluation of tie benefits, and that tie benefits should be treated similarly to other capacity resources.

In contrast, Synapse Energy Economics wrote that re-evaluating the treatment of tie benefits is “not a critical priority at this stage,” adding that it likely would have a small impact on overall capacity requirements.

Several stakeholders, including the New England Power Generators Association (NEPGA), said ISO-NE should discuss with stakeholders what costs can be included in a capacity market offer price.

The Massachusetts Attorney General’s Office recommended ISO-NE “develop a longer-term strategic plan and roadmap for consideration and implementation of needed capacity market reforms that are outside the scope of CAR for CCP 19.”

Financial Assurance

A proposal by NEPGA to amend ISO-NE’s proposed updates to the financial assurance policy failed to gain the support of the MC, with 50% of votes in favor.

NEPGA’s proposal would direct ISO-NE to allow bilateral trading of capacity supply obligations (CSOs) until five business days before each obligation month and would require ISO-NE to review trades within five business days of their submission. (See NE Generators Propose Financial Assurance Changes.)

“The current rules create incremental risk and increase the cost of assuming a CSO,” said Bruce Anderson of NEPGA. “The ability to trade closer in time to the obligation month improves reliability, in that it allows for timely substitution of anticipated Capacity Scarcity Condition performance.”

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NERC Report Identifies Persistent CIP Violation Themes

In a report released Aug. 6, NERC said registered entities’ cyber and physical security postures have room for improvement in four key areas and called on stakeholders to “continue the conversations within their organizations and with their peers” to build a safer electric grid. 

The 2024 Critical Infrastructure Protection Themes and Lessons Learned report is the third in a series, with previous installments published in 2015 and 2018.  

Its goal is to identify “risk themes that have made it difficult for some entities to mitigate risks associated with the NERC Critical Infrastructure Protection (CIP) reliability standards [and] to communicate these themes” to stakeholders, along with possible resolutions. NERC said the recommendations are “merely approaches that have been successful for certain entities,” rather than mandatory directives.  

“While industry excels at many aspects of cyber security, the intention of this report is to outline areas for improvement with the goal of driving continued progress toward our shared mission of ensuring a reliable power system,” NERC said, adding that the document includes “high-level fact patterns from open and closed cases” while withholding information that could expose security holes in the grid. 

The risks discussed fall into four main themes: 

    • latent vulnerabilities; 
    • insufficient commitment to low-impact programs;
    • shortages of labor and skillsets;
    • performance drift. 

Latent vulnerabilities refer to “long-standing, higher-risk issues that evade detection and persist within entities’ environments,” which arise even at entities with robust and effective CIP compliance programs that have seen overall failures decline. The ERO noted that such violations tend to be “more isolated in nature” without significant trends but warned that entities still must address these risks to “drive continuous improvement” in grid security. 

Examples of latent vulnerabilities highlighted in the report include an entity’s discovery that an outdated system configuration had granted improper access for grid cyber systems to thousands of unauthorized users for more than five years. The entity discovered the issue only when a transferred employee realized she still had access to files outside her new department. 

Another case involved physical security: An entity had no monitoring system in place for physical access points to substations, despite having alarms and alerts that “created a false sense … that monitoring was occurring.” In reality, the report said, the alarms and alerts had been effectively neutralized by configuration changes during construction of the substations.  

To address these issues, NERC suggested that entities try to determine whether they have dedicated enough resources to the development and execution of detective controls, test their controls regularly and scrutinize their design while “contemplating scenarios that those controls may not address.” The ERO advised that entities conduct periodic searches for latent vulnerabilities in addition to formal internal audits. 

Another theme involves insufficient commitment to low-impact programs, which cover systems considered not to pose a significant risk to grid security. NERC noted that since 2017, there has been a steady rise in the number of noncompliances regarding the CIP-003 (Cybersecurity — security management controls) family of standards, which contain “the majority of low-impact cybersecurity requirements” — from two violations in 2017 to 53 last year. 

The ERO said the majority of these infringements involve misunderstandings of CIP obligations and security objectives, insufficient understandings of the cyber environment, struggles “to effectively manage electronic access,” or inability to implement effective controls on removable media. 

NERC called for entities to improve their attention to detail, planning and execution of low-impact security programs. It also recommended utilities evaluate whether security personnel understand their expectations and cyber environment and that entities taking over the management of existing low-impact sites undergo the same evaluation. 

Labor Issues

Shortages of skilled labor also contribute to security risks, NERC said. The ERO observed that 70% of organizations in the energy, power and utilities industry report a shortage of cybersecurity staff, even as nearly 80% of the industry considers the current threat landscape as the most challenging in the past five years.  

Tying this into the security risk discussion, NERC said many CIP violations it has seen resulted from “entities losing skilled labor … and failing to successfully transition the underlying job responsibilities to new or existing staff.” These transition failures can result from inadequate knowledge transfer or from difficulties finding replacement staff with the necessary skills to adapt to the cybersecurity needs of the electric industry. 

NERC said tackling this issue will require “creativity and attention.” Possible solutions include proactively hiring new staff while experienced employees still are available to educate and train them, along with evaluating their approaches to hiring and compensation to ensure they can attract workers with the skills they need. In addition, the ERO recommended implementing succession plans for employees in critical positions whose departure could “lead to process or internal control failures.” 

The final trend identified in the report is performance drift, relating specifically to physical security and meaning “apathy, circumvention, complacency, inattentiveness” and other human performance issues that creep into security programs “at entities of every size and type.” NERC noted that physical security often requires repetitive behavior that may last long periods of time, and workers may lose focus on or forget the importance of individual acts. 

The ERO said it has “seen increased failure with these repetitive behaviors when disciplined execution becomes inconvenient or uncomfortable.” For example, multiple cases involve staff allowing individuals into secure areas who forgot their credentials or never had them at all. This can arise from a feeling of favors being owed, or employees assuming the people in question “were supposed to be there” — such as a truck assumed to be an authorized delivery vehicle or an unknown individual allowed into a secure area because he claimed to be with a vendor. 

Among NERC’s suggestions to address this issue are regular testing for potential performance drift, such as physical penetration tests. Security programs must exhibit “continuous internal skepticism,” especially because remote work and high turnover have caused staff to become “increasingly unfamiliar with colleagues and other departments.” Additional improvements include implementing incentive programs to “promote process adherence and whistleblowing when processes are ignored.” 

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CAISO Proposal Seeks to Refine Storage Bid Cost Recovery

A new CAISO proposal seeks to address unwarranted bid cost recovery (BCR) payments to storage resources, an issue that has stirred controversy over the past month.

The proposal, which CAISO presented at an Aug. 5 workshop, is part of Track 1 of CAISO’s new Storage Bid Cost Recovery and Default Energy Bids Enhancements, which began July 8 and has been criticized by stakeholders for its “aggressive timeline.” (See CAISO Kicks Off Storage Bid Cost Recovery Stakeholder Initiative.) A final proposal is scheduled for a board vote Sept. 26.

“This is a very complicated issue with a lot of moving parts, and I do appreciate that there could be a significant amount of economic burden that’s being introduced into the market because of this, but I really do agree that we should slow down,” Josh Arnold, senior market and operations analyst at Customized Energy Solutions, said during the Aug. 5 meeting. “It’s an incredibly complicated system and I think in some cases it has been oversimplified.”

The initiative aims to address what the ISO identified as unusually high BCR payments to storage resources, despite the payments not being aligned with the intent of BCR.

As noted in the ISO’s July 26 straw proposal, BCR was created with conventional assets in mind, meaning it doesn’t consider storage resources’ opportunity costs or state-of-charge (SOC) constraints. The differentiated treatment of unavailable energy, the proposal says, has led to two primary concerns: that storage assets aren’t exposed to real-time prices for deviating from day-ahead schedules due to SOC constraints, and that it creates incentives for resources to bid inefficiently to maximize a combined BCR and market payment.

CAISO’s proposal seeks to address the problem of a storage resource being unable to meet a day-ahead schedule due to an SOC constraint. In that case, the market instructs the storage asset to a 0-MW dispatch because of the SOC being binding, categorizing the energy as “optimal” and making it eligible for BCR.

“Our proposal is really to define that dispatch that is unavailable due to state-of-charge constraints in the binding interval as non-optimal energy, meaning that it would not be eligible for BCR,” Sergio Dueñas Melendez, storage sector manager at CAISO, said in the meeting. “We believe that this will materially limit the chances of unwarranted BCR derived from buy- or sell-backs of the day-ahead schedule.”

Because the proposal applies only to the real-time binding interval, it wouldn’t fully eliminate BCR, Dueñas Melendez noted.

‘Knee-jerk Reaction Initiative’

Track 2 of the initiative addresses how the BCR construct treats energy storage in co-located configurations, as well as dealing with storage and hybrid resource default energy bids (DEBs).

Some stakeholders expressed concern that the proposal didn’t consider the complexities of BCR and that Tracks 1 and 2 should be separated into different initiatives.

“There’s instances where, yes, the scheduling coordinator of the storage resources is causing the SOC [constraint] [and] that you don’t want to get bid cost recovery. But we know that there are market design issues that can result in the SOC being mismanaged,” said Don Tretheway, director, Markets & Regulatory Policy at GDS Associates.

Tretheway also noted that separating Tracks 1 and 2 could solve the problem more efficiently.

“CAISO is basically saying that you’re going to try and solve now the two instances that you’re concerned of. The first is the ability to inflate your BCR payments so that you can get additional revenues, versus storage resources not being exposed to the real-time bid price when they can’t meet their SOC,” Tretheway said. “I think you can separate those two issues, and you can address those bidding concerns you have in a very simple BCR settlement versus trying to do all this other complex stuff, which would then give us the time to think about what the appropriate approach would be.”

He argued that by solving Track 2 issues related to the DEB first, scheduling coordinators wouldn’t need to ensure that real-time energy bids reflect real-time conditions for storage resources.

Several stakeholders agreed with Tretheway’s concerns, underscoring the complexity of the topic and the need for more time to resolve issues.

Kallie Wells, senior consultant at Gridwell Consulting representing the Western Power Trading Forum, highlighted the need for a more “robust discussion.”

“I think we owe it to ourselves to talk through different ways to address this issue,” Wells said. “One of the drawbacks I see of this proposal is it does create an incentive that we haven’t really discussed. And I do wonder to what extent this proposal is going to incent resources to now bid in a way to ensure that they meet their day-ahead schedules, which we all know real-time conditions change from day-ahead. So, if they’re bidding in a way that basically self-schedules them at their day-ahead schedule, we’ve now lost all that flexibility that these resources are bringing to the market, and that can cause reliability issues.”

Stakeholders continued to ask for more time to address the issue.

“This feels to be a bit of a knee-jerk reaction initiative overall,” said Chris Devon, director of energy market policy at Terra-Gen. “It doesn’t seem like CAISO is willing or able to talk about storage in a manner that looks at everything that needs to be discussed holistically.”

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Exelon Prepping for Major Load Growth in Utility Service Territories

Exelon is focused on meeting rising demand from data centers and manufacturing while also working with regulators to ensure that Commonwealth Edison’s integrated grid plan meets the requirements of the Illinois Climate and Equitable Jobs Act, company officials said during its second-quarter earnings call Aug. 1.

CEO Calvin Butler said a revised grid plan, filed in May, is on track for approval after the Illinois Commerce Commission rejected the original in December. The company has reached agreements with the city of Chicago, the Building Owners and Management Association, and environmental organizations, he said.

“These affirmations are good examples of what differentiates the process this year. Approval of the plan will ensure that Northern Illinois will receive the investment needed to maintain an affordable, resilient, reliable and clean grid for its customers and will support the state’s success in attracting new business,” Butler said.

CFO Jeanne Jones said data centers, energy-intensive manufacturing, economic development and electrification are leading to increased transmission spending over the next four years.

She said the growth is exemplified by a partnership between Exelon and Compass Datacenters to build one of the largest data centers in Illinois. She also noted the 235-acre Baltimore Peninsula mixed-use development, which includes 100 MW of load and is supported by rebuilding or constructing several new substations.

“This growth in high-density load, not just in data centers, but also in solar panel production, [electric vehicle] battery manufacturing, hydrogen production, quantum computing and other industries is one of several drivers for why our transmission spend increased by 45% in our four-year plan,” Jones said.

ComEd CEO Gil Quiniones said data center growth is likely to continue in the utility’s region.

“It’s been a robust market for data centers here in Illinois. We have over 5 GW in what we call engineering phase where data centers have paid us to start engineering their projects,” he said. “Some of them actually have made deposits so that we can order large equipment like transformers and breakers. And then behind that, we have another 13 GW in what we call prospects. So they’re not yet in engineering, but they are knocking on our doors, making inquiries very interested in coming to our jurisdiction.”

Exelon reported net income of $448 million ($0.45/share) in the second quarter, a 30.6% increase over that of the same period last year.

PJM Capacity Auction

A substantial increase in PJM capacity prices likely will push consumer rates up, Jones said, potentially leading to double-digit increases in the Baltimore Gas and Electric region, which reached its $466.35/MW-day price cap in the latest Base Residual Auction because of limited local capacity and constrained transmission. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.)

Butler said Exelon and PJM have signaled concerns about future resource adequacy as baseload generation is replaced by renewable resources and load growth fueled by data centers.

“The price signals that we saw clearly indicate a need for infrastructure investments in our footprint, particularly in BGE, both generation and transmission,” he said.

Jones said utilities are working to keep costs down, such as with energy efficiency programs that have led to $9 billion in ComEd consumer savings since their inception in 2008. A ComEd rebate program also has facilitated the development of 1 GW of distributed energy resources.

Co-located Load

Butler discussed the utility’s protest of PJM’s request for FERC to amend the Susquehanna nuclear generator’s interconnection service agreement (ISA) to reduce the facility’s capacity interconnection rights (CIRs) and shift 480 MW of its output to a co-located data center (ER24-2172).

The ISA already contains language allowing 300 MW of the facility’s output to be dedicated to co-located load. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

Exelon urged the commission to set the matter for hearing and argued that the proposed amendments do not address how the configuration would prevent the load from receiving energy from the PJM grid. It also said the configuration would create a new category of PJM load that does not yet exist in the governing documents and that it should be required to pay for ancillary grid benefits.

Butler said Exelon supports co-located load and data centers, but it should be recognized they benefit from being a part of the PJM grid and should pay for those services.

“Users of the grid should pay their fair share. And while there may be unique opportunities to leverage land and equipment at generation plants to get data centers online quickly, they are still connected to the grid and are benefiting from a host of services that the grid provides to serve all of the load connected to it,” he said.

Colette Honorable, Exelon’s executive vice president of public policy, said the company’s priority is making sure the rules for co-located load are equitable.

“Look, this demand is coming either way, whether it’s co-located or not,” said Honorable, a former FERC commissioner. “And our focus is making sure the investment gets done for the needs of our customers and that everyone has a fair and equitable allocation of the cost of using the grid. And I think that’s the bottom line.”

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Duke Energy Executives Discuss Demand Growth on Q2 Earnings Call

Duke Energy executives highlighted how the return to load growth is impacting its utilities during its second-quarter earnings call with analysts Aug. 6. 

The trend started to impact the utility at the start of the year, when it had to file an update to a still-pending integrated resource plan at the North Carolina Utilities Commission after load forecasts increased. 

“We operate in some of the most attractive jurisdictions for both economic development and customer migration, which provide conviction in our 2% load growth forecast in 2024, and 1.5 to 2% load growth CAGR (compound annual growth rate) over the five-year planning horizon,” CFO Brian Savoy said. 

Residential customers are moving at high rates to Duke’s territories in the Carolinas and Florida, where demand was up 2.4% in the first half of the year. Commercial demand growth exceeded Duke’s expectations, while industrial demand saw somewhat slower growth in its territory. Some large customers in Duke’s territory were impacted by interest rates and worries of a possible economic downturn, but the company expects growth in advanced manufacturing and data centers to rise significantly in the long term. 

“It’s primarily what I would call our legacy industries of textile and paper that are feeling the pressure,” CEO Lynn Good said. “And we continue to track with all of that industrial volume we’re expecting from economic development; that is exactly on track. So, it’s a little bit of an old-industry/new-industry story that we’re seeing in the Carolinas in particular, and a little bit in Indiana.” 

Duke recently entered into memoranda of understanding with large customers in the Carolinas, including Amazon, Google, Microsoft and Nucor, to explore tailored solutions to meet large-scale energy needs and lower the long-term cost of investing in clean energy, Savoy said. 

“These voluntary programs, which are subject to commission approval, would be open to any large customer and would include protections for nonparticipating customers,” Savoy said. “We look forward to continued collaboration with all stakeholders as we work to meet the accelerating demand in our service territories.” 

Of the forecasted “economic development” demand growth through 2028, just 25% comes from data centers, though Good said that in the longer term, that is forecasted to be a bigger chunk of new demand. The MOUs are meant to not only help the firmer load growth in its pipeline, but also encourage continued expansion in Duke’s territories, Good said. 

“The discussions are early,” she added. “I think there’s a clear understanding that we are trying to do a couple of things here. We’re trying to meet the load. We’re trying to meet their sustainability goals. We’re trying to do so in a way that protects retail customers. We’re trying to meet their timelines. And I would say the discussion is very constructive, and the notion of risk sharing is something that we’re very clear on and have lots of experience in talking with customers about.” 

Nucor has signaled interest in using nuclear power to fuel its steel-manufacturing operations, even investing $35 million in a potential fusion plant. Good was asked whether the MOUs with it and the others included work on nuclear. 

“They have an interest, obviously, in carbon-free generation, and nuclear represents an around-the-clock option,” Good said. “But we all recognize we’re [in] the early stages of development. So, is there a structure? Is there premium pricing? Is there some method of equity investment? Is there some structure that would encourage the development at a perhaps a more rapid pace, or sooner, because of the partnership? So, all of that is being explored as we talk with them.” 

Duke reported $886 million ($1.13/share) in net income for the second quarter, a big improvement over its loss of $234 million in the same quarter last year. 

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No Clear Blueprint for Western ‘RO’ Stakeholder Process

One thing has become abundantly clear after three intensive workshops this summer: There’s no blueprint for developing the stakeholder process for the “regional organization” (RO) envisioned by the West-Wide Governance Pathways Initiative. 

“Stakeholder engagement process” is one of six “work streams” the Pathways Initiative launched this summer to lay the foundation for the RO, which would assume the governance of CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). (See Busy Summer Ahead for Pathways Initiative.) In some ways, its outcome could be the most vital for the RO’s long-term viability.   

That’s because supporters of SPP’s Markets+ day-ahead offering have touted the market’s stakeholder-led approach to governance nearly as much as the independence of that governance from state (that is, California) influence, challenging acceptance of CAISO’s more staff-driven model. 

Scott Miller, executive director of the Western Power Trading Forum, recognized the change in expectations last July, telling RTO Insider that Markets+ had been “charmed” by SPP’s approach to stakeholder engagement. (See In Contest for the West, Markets+ Gathers Momentum — and Skeptics.) 

“Now they’ve been exposed to a stakeholder process that the stakeholders run, and there still hasn’t been a stakeholder process [in CAISO] that is developed much differently, even in the context of the EIM,” Miller said at the time. 

‘Little Bit Outside the Mainstream’

A year later, Pathways backers seek to address those changed expectations, beginning with a series of four workshops to determine how stakeholders want to interact with the future RO. The group’s Launch Committee considered the subject weighty enough to engage an independent facilitator, Gridworks, to manage the workshop discussions. 

Workshop participants are grappling with a broad question of how to create a “hybrid” stakeholder process model that combines the best parts of CAISO’s staff-driven process with the stakeholder-driven — and committee-based — processes of the RTOs in the Eastern Interconnection, which themselves vary in their approaches. 

Several participants have pointed to benefits of CAISO’s approach: its inclusiveness, accessibility and relative informality, despite its top-down nature. They’ve noted that while CAISO’s process does not rely on stakeholder committees, the ISO recently rolled out use of stakeholder “working groups” to hash out market initiatives.  

“The CAISO process is able to organically capture large ideas [and groups of] stakeholders,” Alan Meck, principal market design analyst at Pacific Gas and Electric, said during the Pathways Initiative’s July 24 workshop.  

Meck said he sees benefit in the ISO’s less structured — that is, non-committee — approach to addressing issues because it doesn’t entail a process in which “x percent” of votes from certain stakeholder groups is needed to advance markets changes. 

Oregon Public Utility Commissioner Letha Tawney said that “as a stakeholder who is not resourced to engage in these processes very deeply,” she appreciated the open nature of the CAISO process. 

“I like how it doesn’t ask, ‘What’s your standing? Why do you have a voice here? Do you get to have a say in this? It’s an all-comers [process], and as a decision-maker myself, who tries to run procedurally equitable processes, I really like that,” said Tawney, one of the signatories of the July 2023 letter launching the Pathways Initiative. 

Tony Braun, an attorney who represents publicly owned utilities in California, offered an example of how that openness can benefit stakeholders who sit “a little bit outside the mainstream” on a market issue. 

“When the flexible capacity product was first introduced, the proposal, which was very mature, was to just peanut butter the costs of it on a load-ratio share basis,” Braun said. “We had to fight tooth-and-nail to show … CAISO that our loads and resources did not look like everybody else’s, or at least certain loads and resources.” 

Braun said the public utilities ultimately convinced the ISO to adopt a more cost-causation approach. 

“And I can’t help but think that would have not happened in a voting structure — that we would have just been an extraordinarily small minority and we would just get rolled over,” he said. 

Ryan Millard, West region senior director of regulatory and political affairs at NextEra Energy Resources, said CAISO included elements of “the good, the bad and the ugly.” Among the bad, Millard noted, is that CAISO’s lack of stakeholder process formality can translate into unclear timelines. 

Citing the example of the ISO’s interconnection process enhancements initiative, he said, “I don’t think there were enough attempts in the beginning to kind of structure how the stakeholder process was going to move forward, and there [weren’t] timelines built into the front. In fact, that was my commentary through that process multiple times: ‘Pick a date, you have a lot of conflicting or complicated compliance filings at FERC that are going to make this more complicated.’ And sure enough, it did.” 

Other workshop participants pointed to what they see as advantages in SPP’s more structured stakeholder process, which they experienced in developing the Markets+ tariff. 

Doug Marker, an intergovernmental affairs specialist at the Bonneville Power Administration, said BPA recognizes and supports the fact that Pathways is seeking “to do something different than the older CAISO staff model.”  

“We would like to see a more stakeholder-led issue development process,” he said during the July 24 workshop. In April, BPA staff issued a recommendation that the agency choose Markets+ over EDAM, citing governance and stakeholder processes as two key reasons for its leaning. (See BPA Staff Recommends Markets+ over EDAM.)  

For BPA, it’s important the stakeholder process “get issues defined and developed so that there’s a clear majority and minority perspective, if necessary,” Marker said. 

“The Markets+ process has helped to facilitate developing consensus on some difficult issues. We were really skeptical going into the process about the voting aspect of it, but it served in some instances to really facilitate consensus,” he said. 

Lauren Tenney Denison, director of market policy and grid strategy at the Portland-based Public Power Council, spoke approvingly of the Markets+ system of standing work groups and ad hoc task forces, both of which include representatives from various stakeholder sectors and rely on forms of voting to advance issues through the stakeholder process. 

“While all decisions go to an independent board eventually, they build up through that working group level,” Tenney Denison said. “Then there’s the Markets+ Executive Committee that has representatives from all the participants and stakeholders. That group is also able to direct work back to those workgroups and task forces. So there’s just more structure involved that has stakeholders having an active voice through this voting mechanism on what to prioritize and what needs to be looked at.” 

‘Pleasantly Surprised’

An Aug. 2 Pathways workshop delved into the question of what a “sector-based committee and voting structure” could add to the RO.  

Braun said he thinks sector-based representation is essential and provides an “indicia of inclusiveness” to the stakeholder process, helping to “get the right people at the table” and build consensus. 

“I think I probably get less worked up about the definitions of the sectors than many do,” he said. “I get nervous when sectors get too granular. I think one of the lessons that we’ve learned is that making the sectors broad forces people to work together to come up with plans for populating the sectors and the relative positions in the stakeholder processes,” such as in the WEIM’s stakeholder-led Regional Issues Forum (RIF).  

“I think one of the benefits of having some similarly situated folks within the same group is that it’s helpful to sort of zoom in on areas where there is consensus out of the gate and areas where maybe we’re using different terminology to describe the same thing — or with areas also where there isn’t consensus,” said Ian White, director of regulatory affairs at Shell Trading. 

White said the RIF group representing independent power producers, marketers and independent load-serving entities sector — one in which Shell participates — has become “quite an unruly” sector with its 70 members, many of which operate under different business models and therefore don’t always share the same interests.  

“Regardless of sector size, I think you’re always going to have splinter factions form over issues that are of unique concern to an organization’s individual goals,” NextEra’s Millard said. “And that’s particularly true in diverse sectors, of which NextEra is one. The less formal structure of CAISO’s stakeholder framework sort of allows for that, and you have the ability to collaborate and/or advocate as a subgroup of your sector or even cross-collaborate with other sectors.” 

Allie Mace, manager of market policy and analysis at BPA, said sector-based representation encourages collaboration among stakeholders. 

“In the Markets+ experience, we were pretty pleasantly surprised by the enthusiasm and engagement to dig in on issues and shape compromises and consensus approaches across the sectors,” Mace said. “The sector definitions didn’t seem like they were a barrier to that collaboration. I think defined sectors can help to provide some good helpful parameters for organizing issues and input.” 

Voting with Purpose

On the topic of whether the RO’s stakeholder process should include participant voting, both Braun and Scott Ranzal, director of portfolio management at Pacific Gas and Electric, expressed support for some kind of voting, but raised the question of the purpose of votes.  

As noted throughout the workshop, voting can be characterized as “indicative” (showing a preference during the process), “advisory” (expressing an opinion to a board or other body) or “binding” (advancing a proposal).   

“I think voting is a reflection of desire that actually already happens inside the CAISO,” Ranzal said. “It’s not labeled as a vote, but it is very clear in the CAISO processes where people want to be. So I think if voting is a reflection of desire, and that can help with accountability and visualizing what is happening, adding that to the CAISO process seems like it would have a positive bent to it.” 

“I think voting has the potential to complicate engagement and sometimes discourage engagement altogether, if you’re a minority voice on a specific issue,” Millard said, advocating for “narrowing the application of when and how voting” is used in the stakeholder process. 

Mace said BPA found voting in Markets+ to be a “positive experience” after the agency overcame a “learning curve.” 

“We were pretty impressed with how voting helped to move things along,” Mace said. “Calling for that advisory vote could be a very powerful tool at times in meetings for getting out of a spinning topic and identifying where people stood, so then you can move forward on the compromise and collaboration.” 

Natalie McIntire, a senior advocate at the Natural Resources Defense Council, said she wouldn’t take a position on whether the RO should include voting and whether such voting should be advisory or binding. 

“But if there is voting, I think it’s really important that you spend a fair amount of time thinking about the balance of those votes,” McIntire said. “I think different regions across the country have different ways that they weight voting based on sectors, and you want to really make sure that that voting is reasonably balanced so that no one sector has control over the outcome of those votes.” 

Kerinia Cusick, president of the Center for Renewables Integration, said any “effective” stakeholder process she’s been involved with has included some form of voting. 

“I’m trying to sort of think of examples where there has been no voting, and those have been somewhat frustrating processes,” Cusick said. “They’ve been sort of long, very engaged, and then nothing comes out of it. So there’s a ton of value of voting to drive accountability.” 

Michele Beck, director of Utah Office of Consumer Services, said she agreed with workshop participants who want to find a “middle ground” between the more “prescriptive” voting structure of the Eastern RTOs and the CAISO process, “something that might be more limited, more indicative.” 

Ranzal said Pathways likely will draw on parts of multiple RTOs to serve the RO’s stakeholder process.   

“We’re going to create our own thing, as we often do in the West, and I think that suits and fits the needs of the West and that’s a good thing. That’s part of the reason why we’re all out here,” he said. 

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4th Circuit Remands Duke Energy Market Power Lawsuit Filed by NTE

The 4th U.S. Circuit Court of Appeals on Aug. 5 sent back to lower courts a lawsuit alleging Duke Energy abused its market power to prevent a power plant developer from serving a municipal utility in North Carolina.

NTE Energy had pursued a deal where it would build a natural gas plant in part to serve Fayetteville, N.C., as the municipality’s contract with Duke was about to expire. But the utility came back with a cheaper contract and kept the business. A lower court found Duke was just competing for its business, but the appeals panel of three judges has open questions on whether market power was abused.

“While we recognize that much of Duke’s conduct can be understood to be legitimate competitive conduct, as well explained by very able counsel, we also have found much from which a jury could conclude that Duke’s actions were illegitimate anticompetitive conduct that violated Section 2 of the Sherman Act, also as well explained by very able counsel,” the 4th Circuit said. “Because genuine disputes of material fact exist, we vacate the district court’s summary judgment and remand for further proceedings.”

On remand, a different district judge will have to be assigned to the case because in the first round U.S. District Judge Kenneth Bell had recused himself due to a former law partner working for the utility. He was reassigned the case years later and denied a motion from NTE to recuse himself again.

“We conclude, as most courts have, that once a judge recuses himself from a case, he should remain recused from that case, even though his recusal may not have originally been required,” the order said.

As an independent power producer, NTE builds power plants and has to rely on utility-owned transmission to transport its power to customers that typically are municipalities. It started construction in 2016 on a new combined cycle natural gas plant in Kings Mountain, N.C., which required access to Duke’s system because it controlled more than 90% of the wholesale market in the region.

Duke and NTE signed a standard interconnection agreement for the Kings Mountain plant and at first were not worried about the constitution. But the IPP started attracting customers as its new combined cycle plant provided power at cheaper rates than Duke could offer, and nine customers signed deals for power from the plant.

NTE had cheaper power, but Duke had 20-year contracts with many customers that required several years of advance notice before they could be terminated, which limited the opportunities for customers. Fayetteville and its 500 MW of load had an expiring contract after being served by Duke for a century.

“NTE did indeed then have plans to build additional power plants in the Carolinas,” the court said. “But key to its plans for expansion was the rare opportunity — because of the terms of Fayetteville’s agreement with Duke — to compete for Fayetteville’s business.”

The Reidsville Energy Center was planned to be a 475-MW combined cycle plant, but it needed a large anchor customer to get built, and Fayetteville was the most attractive one available. Duke entered into an interconnection agreement with the plant that FERC approved, which had NTE pay it $58.9 million for the interconnection lines plus ongoing charges to use them.

After that deal, NTE poached an additional three Duke wholesale customers, and as of 2017, its costs to supply them still were 30% above the IPP’s. Duke identified holding onto Fayetteville as its “biggest upcoming battle” with an opt-out for its contract opening up in 2024, the court said.

Duke reworked its contract with Fayetteville, and executives exchanged emails saying they hoped to get a deal worked out and “ruin NTE’s plans” for the Reidsville plant, as any other remaining opportunities to get a municipal customer were more than a decade away, the court said.

“Despite its relative inefficiency, Duke made a highly attractive, multi-faceted offer to Fayetteville, which amounted in the aggregate to a discount of $325 million for Fayetteville and which was unprecedented,” the court said.

The discount came on the deal the city already had with Duke, but the terms moved those rates higher starting this year to a price more than NTE would have charged. Duke also agreed to quadruple the price it paid for excess power from a fossil plant Fayetteville owned.

Duke expected to lose $100 million on the reworked deal, but in a white paper, company officials argued they could offset the loss through higher charges to other customers.

NTE tried to exercise a suspension of its interconnection agreement, which it thought would have kept its place in Duke’s queue, but the utility said it had breached the deal and tried to terminate it outright.

On Sept. 6, 2019, Duke unilaterally terminated the deal with NTE without notifying FERC as the interconnection agreement required. Days later it approved the reworked deal with Fayetteville and signed it while the plant’s interconnection was listed as canceled.

FERC approved the reworked Fayetteville deal in early 2020, and NTE’s efforts on the Reidsville plant lost momentum. The commission also found a few months later that Duke had improperly terminated the NTE interconnection deal.

NTE argued that Duke’s actions destroyed the value of the new plant and left its customers with no choice but to pay the utility higher rates, which led to the lawsuit.

The district court entered a summary judgment dismissing NTE’s lawsuit, which NTE appealed to the 4th Circuit.

“NTE alleges that Duke engaged in several, simultaneous courses of conduct that combined to thwart NTE from bringing a more efficient power plant online and ultimately from competing with Duke in the Carolinas wholesale power market,” the court said. “It argues that the district court erroneously ‘compartmentalized’ the various aspects of Duke’s anticompetitive conduct and asked whether each one, independently, was unlawful.”

Duke argued the appeals court should reject the holistic approach NTE favors, saying the Supreme Court has set up tests to determine whether conduct abuses market power and the IPP flunked them all. All the activities Duke undertook were legal under those tests.

“In the context of the allegations in this case, we agree with NTE,” the court said. “It is foundational that alleged anticompetitive conduct must be considered as a whole.”

Anticompetitive conduct comes in different forms and can’t always be categorized easily as in the Supreme Court’s tests, which can be too rigid for a “complex or atypical exclusionary campaign.” Such cases are more challenging than when individual practices are each independently unlawful, but they are not categorical impossibilities under the law, the court said.

While the court agreed with NTE that the lower court should look at Duke’s activity (canceling the interconnection deal and offering a discount to Fayetteville) altogether, material disputed facts in the case prevented summary judgment.

“Upon resolution of those disputed facts, a jury might well conclude that Duke’s conduct was simply good, old-fashioned competition, which, in the end, favors the consumers of electric power in the relevant market,” the court said. “On the other hand, the factfinder might just as well conclude that Duke saw a more efficient competitor in NTE and acted, through a broad range of anticompetitive conduct in various contexts, to eliminate that competition, to the detriment of consumers.”

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New England States Delay OSW Solicitation to Account for DOE Funding

Connecticut, Massachusetts and Rhode Island have delayed their much-anticipated coordinated offshore wind solicitation by 30 days to account for the effects of the U.S. Department of Energy’s recent award of Grid Resilience and Innovation Partnerships funding to help interconnect offshore wind projects. 

The states were set to announce the results of the procurement Aug. 7. The day before, DOE announced its award of $389.3 million for substations in Southern New England to help interconnect up to 4,800 MW of offshore wind, as well as to spur the development of multiday energy storage in Maine. (See DOE Announces $2.2B in Grid Resilience, Innovation Awards.) 

The coordinated solicitation is intended to lower overall costs by using regional supply chains and the three states’ collective buying power. It drew 5,454 MW of bids from four developers, staying within the solicitation’s 6,000-MW cap. (See New England States’ OSW Procurement Receives 5,454 MW in Bids.) 

This marks the second time the solicitation has been delayed; the states previously pushed the project selection date from June to August to buy time for clarity on federal tax credits from the Inflation Reduction Act. (See New England States Delay Offshore Wind Solicitations.) 

Under the new schedule, project selection is scheduled for Sept. 6, while the long-term contracts are set to be executed in November and submitted for approval in December. 

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Constellation Raises Earnings Guidance amid Rising Demand

Constellation Energy turned in another solid quarterly report Aug. 6, boosting its earnings guidance for the year and offering a rosy picture for the future of its nuclear power fleet. 

During a conference call with financial analysts, much of the conversation surrounded data centers and the prospect of Constellation helping to meet their immense load demand with long-term behind-the-meter supply agreements.  

CEO Joe Dominguez said the company is moving ahead with negotiations for co-located data centers even as the regulatory structure for such agreements is examined. 

He presented this as a win-win-win — helping to place the nation at the forefront of the artificial intelligence revolution, reducing the amount of new infrastructure utility ratepayers must fund and locking in a market for Constellation’s zero-emissions generation for decades to come. 

“We’re confident that any thorough examination of co-location with nuclear plants will show that it is both the fastest and most cost-effective way to develop critical digital infrastructure without burdening other customers with expensive upgrades,” he said. 

Long-term behind-the-meter agreements also give Constellation the economic certainty it needs to seek relicensing of its plants, Dominguez said. 

The issue has gained prominence as Talen Energy has proposed a deal to power a growing data center on the site of its nuclear plant in Pennsylvania, drawing protests from Exelon and American Electric Power, which drew rebuttals from Talen and others, including Constellation. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.) 

On Aug. 2, FERC said it would hold a commissioner-led technical conference this year on co-location of large loads at generating facilities (AD24-11). 

Dominguez said the Aug. 2 actions at FERC “may have slowed things but ultimately will be constructive, in our view. Notably, FERC did not grant requests by a small number of utilities to set the Talen Energy ISA for hearing or in the alternative to reject it outright.” 

Co-location is not always the right solution, but neither is it a new or unfamiliar concept, he added. 

“As we see it, utility connection will continue to make sense for some applications and in some parts of the grid. But when it’s an option, we will continue to see customer interest in co-location, strong interest, because there are just too many advantages of connecting large load directly to large forms of generation, especially clean generation.” 

The protest to FERC about the Talen deal may slow the finalizing of facility co-location agreements or change their details, but it will not block co-location, Dominguez said.  

“We really don’t see an outcome here where the FERC is going to say, ‘You can’t do this.’” 

An analyst asked if the recent PJM auction increased a sense of urgency among potential customers to lock down these co-location agreements. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

Dominguez said it did, just as it has increased the urgency for front-of-meter deals, because the marketplace is tightening. 

Another analyst asked whether Constellation expected to get regulatory clarity on the prospect of co-location this year or next. 

Dominguez did not offer a prediction but said Constellation is not waiting for absolute clarity in the FERC process. 

“I do think the Talen ISA is going to be instructive, and folks are watching that, to make sure it goes through, what conditions might get attached to that, but we independently are working on contractual provisions that allow us to manage whatever outcome comes out of those proceedings.” 

He added: “So, at least for the moment, we’re working with our customers [toward] finalizing deals.” 

Customers and policymakers have an interest in resolution of the dispute, Dominguez said. 

“Talen’s not our deal, but I’ll use it as an illustration: That arrangement is bringing $10-plus billion, maybe more than $20 billion, of economic development to a region that if we’re going to be honest, hasn’t seen a lot of sunshine from an economic development standpoint of this dimension in a long, long time. 

“I think it’s fair to say that policymakers around Pennsylvania like to see that for communities like this that need jobs and economic opportunities. And I think it’s fair to extrapolate from that, that they won’t like it very much if people interfere with those things and cause it to come off the rails.” 

Constellation reported second-quarter GAAP net income of $814 million ($2.58/share), compared with $833 million ($2.56/share) in the same quarter of 2023. 

The company raised its full-year 2024 net earnings guidance from $7.23 to $8.03/share to $7.60 to $8.40/share and maintained its earlier forecast of annual earnings growth greater than 10% on average through 2028. 

Constellation’s stock price closed 6.5% higher in heavier-than-average trading Aug. 6. 

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SPP Considering 765-kV Solution for Permian Basin

TULSA, Okla. — SPP is considering a 765-kV solution and several 500-kV proposals in its Permian Basin footprint in Texas and New Mexico, its first dabble with extra high voltage (EHV) transmission lines.

Staff have proposed a 300-mile, 765-kV transmission line in New Mexico that will address “extreme” forecast load growth beyond its next two Integrated Transmission Planning (ITP) portfolios. They say it’s part of a proactive approach to get ahead of the region’s growth.

“It’s kind of the big one we’re going to look at,” SPP planning engineer Nick Parker told stakeholders during the Markets and Operations Policy Committee’s July meeting.

Growing electrification of oil and gas activity fuels much of the region’s load growth, although large industrial and data facilities also are contributors. SPP forecasts the Permian’s drilling load in New Mexico to increase by 5.3 GW in 2032. Southwestern Public Service (SPS), the incumbent utility for the region, says its load projects have grown by more than 2,750 MW since the 2023 ITP.

SPP staff said load growth will continue to aggravate issues in an already stressed area of the system and that solutions must address conditions beyond the 2024 ITP due to expected rate of growth.

The 765-kV solution offers other technological and operational advantages. The line’s capacity is nearly three times that of a double-circuit 345-kV line and its cost per MW-mile is less than one-third the cost per MW-mile of 345 facilities, SPP says. Because 765-kV lines use the highest voltage available in the nation, their load is less than lower-voltage lines and they can carry power over longer distances.

“We expect these loads to continue to grow. They’re still coming, and we know that electrification is still coming,” Parker said. “We think it’s just the more proactive approach to go ahead and move forward with the beginning of a 765-transmission system to ensure we can deliver to this area.”

Staff also are considering about 525 miles of 500-kV projects in the same area. They said with anticipated load growth beyond the 2024 and 2025 ITP studies, “a more robust solution” is required to address voltage and power delivery issues in southern New Mexico.

The growing load in SPP’s Permian Basin footprint | SPP

ERCOT staff has projected the SPS projects will cost about $750 million, or almost as much as the 2022 and 2023 ITP portfolios. The entire portfolio could end up costing between $2 billion and $3.5 billion. The costs are conceptual in that they are more “rough estimates” until SPP receives study-level estimates.

“This portfolio is the largest that we’ve ever had in an annual cycle. It is reflective of load changes,” engineering vice president Casey Cathey said, noting the last ITP cycle’s load forecast exceeding two-year-out models in just one year.

“We recognize that there are a number of projects in our queue that probably don’t really need to be in our queue,” he added. “We also recognize there are a number of projects that need to stay, and they need to interconnect.”

ERCOT faces similar challenges addressing the Permian’s explosive growth. In a report filed with Texas regulators, the grid operator said transmission operators expect oil and gas load to peak at 11.96 GW in 2030 and 14.71 GW in 2038. It expects an additional 12 GW of data center and other non-petroleum load by 2030, with the combined total amounting to about a third of the system’s current summer peak (55718).

Based on those forecasts, ERCOT projects a total cost of between $12.95 billion and $15.32 billion for the transmission facilities to meet the coming load. The ISO sees EHV lines as part of the solution, pointing to their “generally known” benefits over 345-kV counterparts: reducing losses for long-distance transportation, increasing short circuit strength and improving voltage stability.

“ERCOT recommends the [Public Utility Commission] give serious consideration to an EHV solution — particularly a 765-kV solution — to meet the forecasted transmission needs,” staff told the PUC.

The commission also is gathering stakeholder input on EHV transmission lines in ERCOT. ERCOT has said in response that incorporating 500-kV and 765-kV lines could reduce or eliminate the need for large underbuilds on the 138-, 115- and 69-kV systems (55249).

“An EHV system would likely remain the backbone of the bulk power system for decades without an increase in voltage,” the grid operator said. It said 500- and 765-kV systems are expected to provide “ample capacity to meet substantial long-term load growth and accommodate large power transfers” and they offer greater flexibility in siting generation resources.