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November 19, 2024

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SPP’s Sugg Announces Retirement from RTO

SPP CEO Barbara Sugg announced Aug. 8 that she will retire from the RTO on April 1, 2025, after 35 years of service.

Sugg was appointed to the RTO’s top position in 2020, replacing longtime CEO Nick Brown. Under her guidance, SPP has earned designations as one of the best places to work in Arkansas the past three years; expanded its service offerings and territory into the Western Interconnection with RTO West, Markets+ and other services; and garnered consistently high stakeholder satisfaction ratings.

During her tenure, the RTO has navigated historic challenges that included the COVID-19 pandemic and resulting changes to workplace norms; increasing extreme weather that has affected regional electric reliability; and the ongoing growth in demand for electricity and challenges to resource adequacy.

Sugg said in an email to RTO Insider that she has “bittersweet, mixed emotions” about her planned retirement during an “exciting and rewarding time to be part of the electric utility industry.”

“I have no doubt that SPP’s future is as bright as ever,” she said.

Golden Spread Electric Cooperative’s Mike Wise, one of SPP’s more senior and involved members, noted Sugg’s career has virtually matched his. He commended her for bringing out the best in people and encouraging them to grow.

“Barbara’s leadership and vision guided the SPP through some very difficult times,” Wise told RTO Insider, alluding to the COVID-19 pandemic that hit just after she was named CEO. “She had to create a new corporate culture around remote work and still maintain effective RTO operations. Then she was forced to navigate the highly destructive Winter Storm Uri as an RTO which faced circumstances never seen before in the region.

“She exhibited amazing strength of character and never wavered from her strong belief in the exceptionalism of her employees and the committed stakeholders in the SPP. A big three cheers for a good friend and great leader.”

Joe Lang, Omaha Public Power District’s director of generation strategy and origination and vice chair of the stakeholder-led Markets and Operations Policy Committee, wished the best for Sugg and congratulated her on a “fulfilling” career.

“Barbara has been a strong leader as SPP’s CEO through significant challenges in the electric power industry,” he said. “Barbara will be remembered for her leadership that guided SPP through the pandemic, generation interconnection backlog efforts, navigating resource adequacy constraints during extreme weather events, as well as successes expanding into the West.”

“Barbara’s dedication, passion and support of SPP’s mission and people have been evident throughout her tenure,” John Cupparo, chair of the Board of Directors, said in a news release. “Her impact as a CEO will be felt for years to come, and the board joins SPP’s stakeholders in thanking her for the high standard of leadership she’s set.”

The board plans to name a new CEO before Sugg’s departure, and it has engaged search firm Heidrick & Struggles to assess internal and external candidates as her potential replacement.

“I’m not done until I’m done. I still have much work to do,” she said, crediting SPP’s “dedicated” staff and “diverse” stakeholders. “For now, I remain energized, committed and focused on ensuring SPP’s success and partnering closely with my replacement to ensure she or he is prepared to take the reins.”

Sugg joined SPP in 1997 after eight years with Louisiana Energy and Power Authority. Because LEPA, which comprises 20 municipal power systems, was an SPP member at the time and new hires from members were able to bridge their service years, Sugg is credited with 35 years with the grid operator.

Her career has spanned every level of the RTO’s leadership, including roles as senior vice president of information technology and chief security officer.

Michael Deselle, SPP’s chief compliance and administrative officer, also has announced his retirement, effective at year-end. He joined the RTO in 2006 after 14 years at Central and South West and American Electric Power.

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Maryland Energy Administration, PSC Staff Clash on Future of Gas

Instead of continuing to build pipeline systems and replace aging pipes with expensive new ones that raise rates for customers, Maryland’s gas utilities should first look at non-pipes alternatives (NPAs) such as identifying and sealing leaky pipe joints, said Joyce Lombardi, energy policy manager at the Maryland Energy Administration.

“There’s a robot that can do this,” Lombardi told the Maryland Public Service Commission on July 31, during the continuation of its July 25 public hearing on the future of natural gas in the state. “It just zips underground. It goes into a working pipe, seals the joints; no one up top knows about it. [It] lasts for 50 years. It is one-third of the cost of traditional pipe replacement [and is] being used in New York and Rhode Island.”

The PSC heard two presentations with strongly opposing views at the July 31 hearing: one from the MEA and one from the commission’s own staff attorneys.

Lombardi focused on practical actions, which she said the PSC has the legal authority to take in the short term, such as requiring gas utilities to consider NPAs, while staff laid out complex and at times seemingly contradictory arguments on the fine points of existing legislation and whether any action on the future of gas is currently needed.

“The General Assembly should be given the opportunity to ratify or modify the commission’s decisions after the commission has had the opportunity to create a thorough review of the factual record,” said Staff Counsel Lloyd Spivak.

The hearings were triggered by a petition from the Office of People’s Counsel, filed in February 2023, asking the PSC to open a docket on the future of natural gas, and natural gas infrastructure and utilities, in the state. At the July 25 hearing, People’s Counsel David Lapp argued that Maryland’s ambitious climate targets and push for electrification of heating and cooling would decrease gas demand and the need for ongoing pipeline buildout and replacements. (See Maryland PSC Opens Debate on Future of Gas.)

Under the Climate Solutions Now Act (CSNA) of 2022, Maryland is committed to cutting its greenhouse gas emissions 60% by 2031, and Gov. Wes Moore (D) has pledged the state will have a 100% clean electric system by 2035.

The result, Lapp said on July 25, is that “there’s a massive disconnect between the technology, climate policy and what’s actually going on with the state’s gas utilities,” which have been spending hundreds of millions of dollars per year on pipeline replacement projects while increasing customer bills — in some cases, threefold.

Lapp stressed at the earlier hearing that OPC’s goal was not shutting down the state’s natural gas utilities, but rather to have the commission consider a “wide spectrum” of pathways for these companies to plan for substantially downsized demand and capital spending.

A panel of four PSC staff attorneys initially seemed to support the OPC petition, saying that a proceeding on the future of natural gas would be “necessary in order to achieve the goals laid out in the CSNA,” according to Harrison Scherr, who led off the presentation.

But Scherr and the other attorneys then qualified that support with a series of legal and technical considerations, finally recommending the commission take no immediate action beyond possibly launching a work group or several feasibility studies.

The PSC has “broad authority to regulate the gas utilities … [but] changes in commission policy should proceed with a rule making,” Scherr said. “It should be a very thorough path that we move forward. [Any] actions and policy decisions regarding the transition away from gas should be consistent with guidance from the General Assembly.”

Similarly, Scherr first said that the CSNA tasks the commission with determining how the law’s GHG reduction goals should be achieved, but then backtracked, saying, “It is the responsibility of the General Assembly to set the course by choosing a GHG reduction pathway and enacting enabling legislation.”

Spivak noted that natural gas — used as fuel, for electricity and from its own production facilities — accounts for about 19.5% of Maryland’s greenhouse gas emissions and contested the OPC’s figures on the increasing adoption of heat pumps across the state.

He discounted a 3.8% increase in electric heating customers from 2013 to 2022 — versus a .3% increase in natural gas customers — by speculating that “customers are switching from propane or oil to electric and are not necessarily switching from gas to electric.”

He argued for a balance of climate and public safety considerations in any review of Maryland’s natural gas policies, calling for feasibility studies to look at options like renewable natural gas or geothermal energy or whether the state has the workforce or enough heat pumps to support widespread electrification. A “human feasibility study” may also be needed to look at “the willingness of citizens to switch,” he said.

National Trends

The primary impetus for the OPC’s petition was a 2013 law called the Strategic Infrastructure Development and Enhancement (STRIDE) Act (S.B. 8/H.B. 89), which has allowed the gas utilities to recover the costs of certain pipeline replacements before they are completed, resulting in significant increases in gas utility bills.

But the OPC petition is also part of a larger national trend as other states look to curb emissions from natural gas and face pushback from the industry. As detailed in the petition’s appendices, the California Public Utilities Commission in 2022 passed a first-in-the-nation rule eliminating subsidies for natural gas hookups — still allowed in Maryland. It also passed a general order requiring gas utilities to get PUC approval for any projects costing more than $75 million and potentially causing significant environmental impacts.

Colorado, Massachusetts, Minnesota, New Jersey, New York, Rhode Island and the District of Columbia also have proceedings underway looking at how to balance their emission reduction goals with the public safety imperatives of existing natural gas systems. In 2021, for example, Minnesota passed the Natural Gas Innovation Act (NGIA), requiring the state’s natural gas utilities to develop plans for how they will use “innovative resources” to decarbonize their operations.

In 2022, the Minnesota Public Utilities Commission issued an order setting standards for energy efficiency and electrification investments that will comply with the NGIA.

While the PSC has yet to rule on the OPC’s petition, Chair Frederick H. Hoover did acknowledge the July public hearings as de facto proceedings on the future of natural gas. Other drivers for the PSC could be the executive order Gov. Moore signed in June, calling for the state to establish a zero-emission heating equipment standard and a new clean heat standard to be added to the state’s renewable portfolio standard.

Moore also signed a new law (H.B. 397) in May, requiring gas utilities to develop geothermal pilot projects to provide power to specific neighborhoods, also aimed at cutting back the need for natural gas pipelines. The utilities’ plans will go to the PSC for approval.

As these policies and programs come into effect, Lombardi stressed that requiring gas utilities to demonstrate that they are giving serious consideration to non-pipes alternatives should be a first step for the commission.

“This would be for all capital infrastructure spending, including capacity and line extensions to the extent possible,” she said. “Again, this is a floor, not a ceiling.”

In addition to pipe repairs, like joint resealing, Lombardi said definitions of NPAs should include both demand response and targeted electrification, a strategy for selectively swapping out natural gas for electric heating, or other electric appliances in locations that could most benefit from electrification.

“You can electrify just a few houses or an apartment building or an entire neighborhood maybe that has a high energy burden, or maybe a neighborhood that already has a lot of leaks,” she said.

That idea won support from Commissioner Bonnie Suchman, who said targeted electrification could be an effective, incremental approach to reducing both emissions and gas networks.

“The idea of targeted electrification is a much easier pill to swallow than sort of all-or-nothing,” she said. “And it gets us focused on what makes the most sense for an individual as opposed to just full-on electrification.”

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California Labor Groups Affirm Support for Pathways Proposal

Labor groups that blocked past California legislative efforts to “regionalize” CAISO told state lawmakers Aug. 6 they “look forward” to working with the legislature next year to pass a bill to implement the governance changes to the ISO being developed by the West-Wide Governance Pathways Initiative. 

The statement by the California Coalition of Utility Employees and the California State Association of Electrical Workers to a key State Senate committee might mark the unofficial start of the legislative campaign to allow CAISO to hand off oversight of its Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) to the Pathways Initiative’s proposed “regional organization” (RO). 

It also confirms that Pathways has the support of a key constituency needed to advance that change. 

“As you all know, we’ve been the proverbial fly in the ointment and opposed all three of the prior legislative attempts at regionalization,” Scott Wetch, a lobbyist representing the labor groups, told the Senate’s Energy, Utilities and Communications Committee during an oversight hearing on state agency efforts to maintain electric reliability in the face of extreme weather and the transition to emissions-free resources. 

“Those proposals would have transformed … CAISO itself into an RTO. In contrast, the Pathways Initiative would preserve … CAISO and its balancing authority and other functions, except for control over the energy markets,” Wetch said during a public comment period at the end of the hearing. 

Bills to convert CAISO into an RTO failed three years in a row over the 2016-2018 sessions, largely because of opposition from the International Brotherhood of Electrical Workers (IBEW), as well as resistance from publicly owned utilities in California and some environmental groups worried about the impact on the state’s renewable energy goals. 

Those bills would have extended the boundaries of the ISO’s balancing authority area to include states with utilities opting to join the expanded market. Under California law, that could have meant that the portion of projects that California’s renewable portfolio standard requires to be interconnected directly to the ISO’s BAA would be built outside the state, reducing job opportunities for IBEW members — a nonstarter for the union. 

“I also just want to emphasize that the Pathways proposal being developed would preserve California jobs, unlike previous regionalization proposals,” Wetch told senators. He also noted the plan “will enable many more utilities around the West to join” EDAM. 

“I want to emphasize that we foresee that the proposal would not affect California’s or any other state’s ability to protect its policies such as renewable portfolio standards, transmission planning, cost allocation or GHG reduction,” Wetch said. “It could even enhance our ability to decarbonize at lower cost by allowing us to use solar, wind and hydro resources more efficiently.” 

The change of heart among California labor groups became evident last year when Marc Joseph, an attorney for the IBEW, joined the Pathways Launch Committee. 

“Frankly, I wouldn’t be spending this much time [on Pathways] if I thought this was going to crash and burn,” Joseph said during an April meeting of that committee. (See Past Opponents Now See Legislative Pathway to CAISO Regionalization.) 

No Clear Road Map

During a Pathways workshop Aug. 5 to examine issues related to altering the CAISO tariff and migrating ISO functions to the RO, Launch Committee member Evie Kahl, general counsel for the California Community Choice Association, provided clarification on what a proposed bill would seek to achieve. 

“When we talk about the legislative change for any of this, what we’re looking at is not a legislative change to enable the CAISO to become a different entity than it is today, but to provide these [market] services and to allow California’s BA to participate in the RO market,” Kahl said, adding that the legislation will not determine what services the RO can offer. “That’s all independent.” 

Launch Committee members have made clear that the committee itself is prohibited from attempting to influence legislation because Pathways is a nonprofit 501(c)(3) organization, although some of its members could act in that capacity as representatives of their employers. 

Asked how specific the legislation would need to be to allow a scenario in which the RO takes on a larger portion of the ISO’s market functions and legal responsibilities (what Pathways is calling Option 2.5), compared with a more limited assumption of functions (Option 2.0), committee member Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said he hesitated to “get too far into the weeds” about legislation the group is not directly shaping. 

“I do think there is a pretty plausible legislative route that is permissive and does not get into the specifics of prescribing changes specific to 2.0 or 2.5. In other words, the legislation could look exactly the same,” Gray said. 

“What would be different, potentially in the legislative process, is more clarity from the Launch Committee and stakeholders in support of a particular outcome — 2.0 or 2.5 — that would inform the deliberations,” he said. “But the actual changes to California law don’t necessarily need to be different, and a more prescriptive approach may raise some issues on its own, as opposed to a more permissive approach.” 

The Aug. 5 workshop offered insight into the broad spectrum of issues and level of complexity that participants in the Pathways CAISO Issues and Tariff Analysis Work Group confront as they sort out the future relationship between the RO and ISO, including relative levels of independence, responsibility and liability for market issues, as well as what services each might provide over time. 

“We are really creating something new here,” Kahl said. “Everything that’s being outlined — there have been pieces of this developed across the country with different RTOs, but we’re putting the pieces together differently. In other words, there really hasn’t been a clear road map for us to do what we’ve been doing.” 

In his comments to the senators, Wetch expressed confidence in the outcome. 

“We are pleased with the progress that the [Pathways] Launch Committee has made in the past year. We remain optimistic that the Launch Committee will be able to make a recommendation to create a new regional organization and transfer oversight of the energy markets from the CAISO to the new regional organization,” he said. 

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CISA Launches Cybersecurity Software Buying Guide

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released a guide to help organizations determine their software suppliers’ approach to cybersecurity in order to prevent nonsecure code from getting into their systems. 

CISA’s Secure by Demand Guide, published Aug. 6, provides “questions and resources” that software buyers can use to double-check their suppliers. The agency said that while staff in charge of software acquisition at an organization usually understand the core cybersecurity requirements for a desired technology, they often do not check whether suppliers have “practices and policies in place to ensure that security is a core consideration” at all stages of development. 

The document is intended as a complement to the agency’s Secure by Design Guide, released a week earlier. That guide aims to help instill in software developers the philosophy of building cybersecurity into their products from the ground up and taking proactive steps to ensure their software is free of vulnerabilities. A secure-by-design approach follows three principles: 

    • Take ownership of customer security outcomes. 
    • Embrace radical transparency and accountability. 
    • Build organizational structure and leadership to achieve these goals. 

With the new guide, CISA said, businesses can make sure suppliers are following these principles. 

“We are glad to see leading technology vendors recognize that their products need to be more secure. … Businesses can also help move the needle by making better risk-informed decisions when purchasing software,” CISA Director Jen Easterly said in a statement. “This new guide will help software customers understand how they can use their purchasing power to procure secure products and turn secure by design into secure by demand.” 

In the guide, CISA said businesses’ due diligence of software manufacturers “often [focuses] on [the manufacturers’] enterprise security measures,” which they examine through the lens of compliance standards. However, this focus on enterprise security — which relates to how the company protects its own infrastructure — can come at the expense of neglecting the vendor’s product security, by which the company ensures its products are safe from attacks. 

The guide urged organizations to look for ways to make product security a focus at each stage of procurement. Before procurement, an organization can use probing questions to evaluate a manufacturer’s understanding of product security; during procurement, the organization can write product security requirements into its contract language; and afterward, it can continue to assess the product security and security outcomes. 

Suggested general questions for software manufacturers include whether the manufacturer has taken CISA’s Secure by Design Pledge, how it measures its adherence to the pledge, and to what extent it supports security patches. Additional questions cover a number of specific topics: 

    • authentication — whether the product supports secure authentication measures such as single sign-on and multifactor authentication and has eliminated default passwords in its products. 
    • eliminating classes of vulnerability — what vulnerability classes the manufacturer has addressed systematically in its products, and whether it has a road map for eliminating those classes. 
    • evidence of intrusions — whether manufacturers make security logs available to customers in the baseline version of their products. 
    • software supply chain security — whether the manufacturer generates a software bill of materials in a standardized format that is available to customers, and how it vets the security of open source software components. 
    • vulnerability disclosure and reporting — whether the manufacturer demonstrates transparency and timeliness in vulnerability reporting for its products. 

Describing the guide as “a starting point for software customers to generate the demand for more secure technology products,” CISA advised businesses to use additional resources, such as its Software Acquisition Guide for Government Enterprise Consumers and the National Institute of Standards and Technology’s Secure Software Development Framework. 

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NYISO Presents Draft Recommendations for Demand Curve Reset

NYISO presented its draft recommendations for the demand curve reset Aug. 1, including the choice of a two-hour battery electric storage system resource as the proxy unit in calculations.

The ISO said it agreed with the findings of Analysis Group, even after some stakeholders — mostly generators — opposed the choice. (See NYISO Stakeholders Continue Debate over Battery as Proxy Unit.)

The presentation to the Installed Capacity Working Group was proceeded by a long discussion of various financial parameters employed by NYISO’s consultants.

“Hopefully I don’t need to cover this,” said Zach Smith, senior manager of capacity and new resource integration market solutions for NYISO, referencing a background slide. “We just spent the past two hours talking about” it.

Smith said that NYISO staff concurred with the recommendations of Analysis Group. Based on the data analyzed so far, a 200-MW, two-hour lithium battery storage system is the technology that represents the highest variable and lowest fixed cost for all zones in New York.

“There are a couple of areas we are continuing to investigate, to sharpen our pencils on,” Smith said. “The first is an assessment of the capital parameters for the battery storage option. … We are also looking at the appropriate derating factor for battery energy storage.”

Smith added that NYISO was looking at the appropriate indices and weightings used for updating the cost of new entry.

Doreen Saia, a lawyer with Greenberg Traurig, said she was unsure how well Analysis Group captured the risk portfolio of the two-hour battery as compared to other storage options. Earlier she said she believed the analysis was “too aggressive” on an eight-hour battery but not aggressive on the two-hour.

“While I’m not conflating capacity accreditation factors with this, from a risk perspective, I think you have to project or assume or presume that investors are going to see that distinction and manage it with a risk assessment,” Saia said. “I think that’s where the train fell off the tracks a little.”

Other stakeholders seemed concerned about the derating factor for energy storage. Derating factors measure the availability or performance of specific resources. They are combined with duration adjustment factors to account for a resource’s capacity accreditation.

Smith outlined a problem with the derating factor for the two-hour battery. Analysis Group and its consulting partners, 1898 and Co., recommended a 2% derating factor. However, NYISO’s ICAP Manual establishes that the initial derating factor for new classes of energy storage entering the capacity market is set to the NERC class average of pumped hydro storage, 9%.

“There is a potential misalignment between the assumed proxy EFORd [equivalent forced outage rate – demand] value for energy storage directed by the ICAP Manual versus the potential operating performance anticipated for such resources,” said Smith. “We are continuing to evaluate what the appropriate derating factor should be for battery energy storage systems in the demand curve reset.”

“You’re acknowledging that there’s a problem,” said Mark Younger, president of Hudson Energy Economics. “But you have not committed yet to fixing the problem.”

“We are committed to investigating the problem,” Smith answered. “I don’t know what the solution to the problem is, but we will have a resolution to it.”

Smith went on to say that NYISO would work with Analysis Group to investigate the appropriateness of the composite escalation factor methodology in the indices used for determining the gross CONE. Composite escalation factors combine inflation and potential market shifts to try to estimate the future cost of longer-term projects.

“Despite our best efforts, which everyone seems to be having including the state in their contracting efforts, the issue of how to manage escalation has taken on a life on its own. … It’s cumbersome and unmanageable,” said Saia.

Smith said that NYISO was still soliciting feedback and it would post the comments received. It will post the final staff recommendations Sept. 5. The final reports from NYISO and the consultants will then be posted on Sept. 19 and referred to the Board of Directors for approval. Final stakeholder comments for the board should be filed by Oct. 9.

The ISO is required to file a proposal with FERC by Nov. 30.

“Then I’m going to take a vacation,” Smith said.

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DC Circuit Vacates FERC Approval of Two LNG Facilities in Texas

The D.C. Circuit Court of Appeals issued an order Aug. 6 vacating FERC’s approval of two LNG export facilities in Texas and remanding the cases back to the commission. 

The two facilities are in Cameron County, Texas, which borders Mexico. The facilities’ approval already had been in front of the court in appeals filed by Vecinos para el Bienestar de la Comunidad Costera (Neighbors for the Well-being of the Coastal Community). The vacated orders were on remand from those earlier cases. 

“The commission erroneously declined to issue supplemental environmental impact statements addressing its updated environmental justice analysis for each project and its consideration of a carbon capture and sequestration system for one of the terminals,” said the decision, authored by a three-judge panel. “It also failed to explain why it declined to consider air quality data from a nearby air monitor.” 

Texas LNG Brownsville filed an application in 2016 to build an LNG export terminal on the Brownsville Shipping Channel. Within six weeks, Rio Grande LNG filed to build a second terminal nearby, while Rio Bravo Pipeline Co. filed to build an interstate pipeline to bring fuel to the second facility. The latter two firms are subsidiaries of NextDecade LNG and the joint pipeline/LNG development is called the Rio Grande project. 

Rio Grande filed to add a carbon capture and sequestration system to its facility after losing the first round of litigation. It would seek to capture 90% of the CO2 produced by natural gas liquefaction and ship it via pipeline to an underground injection site in Texas. 

On remand, the commission did an environmental justice analysis that included gathering new, relevant information. But it declined to order a more formal supplemental Environmental Impact Statement (EIS) under the National Environmental Policy Act (NEPA), which would have required giving parties a chance to comment on its analysis. 

Petitioners argued FERC should have done an EIS on the projects on remand. The court agreed. NEPA requires a supplemental EIS when significant new circumstances or information related to environmental concerns of the action are available.  

“Here, the pertinent ‘new information’ includes the updated demographic and environmental data submitted by the developers, as well as the commission’s entirely new analysis and interpretation of that data, which are substantially different from the previously conducted environmental justice analysis in the final EIS,” the court said. 

The original EIS covered the impact on just a two-mile radius around the projects, which FERC extended to 50 kilometers (31 miles) in the less formal review on remand. The new analysis was significantly longer and, unlike the initial EIS, found “disproportionately high and adverse” impacts on environmental justice communities. FERC also ordered additional mitigation measures. 

FERC argued it did not have to do a formal EIS because it reached the same conclusion that the projects would not have major impacts on air quality. 

“That explanation is inadequate for two related reasons,” the court said. “First, neither the regulations nor case law condition the requirement to issue a supplemental EIS on a new determination that a particular environmental impact is significant.” 

The second reason in FERC’s argument is that environmental justice analyses, even new and expanded ones, are not important enough to require a supplemental EIS unless they also disclose significant impacts on the physical environment.  

Effects on environmental justice communities are impacts that are relevant to environmental concerns, which would require a supplemental EIS, the court said. 

FERC took comments on how the developers responded to its new analysis, but it did not let other parties comment directly on its conclusions. 

“But NEPA’s purpose is to allow the public to see and comment on the agency’s interpretation of data, not just the underlying data itself,” the court said. FERC therefore deprived petitioners and the broader public of an adequate springboard for public comments, which it would have been legally required to consider in its decision. 

Rio Grande’s addition of CCS to its project also drew arguments that FERC should have conducted a new EIS based on that change. 

“Rio Grande submitted its CCS proposal specifically in response to our 2021 remand — which required the commission to revisit aspects of its environmental analysis and its ultimate approval of the project — such that both approval requests were pending before the commission at the same time,” the court said. “Indeed, Rio Grande implored the commission to consider the CCS proposal as part of the reauthorization process precisely because it viewed the two actions as related and thought that the CCS proposal’s ability to capture most of the terminal’s GHG emissions would make reauthorization more likely.” 

On remand, FERC must consider the actions together in its environmental analysis before deciding whether to reauthorize the terminal. Even if Rio Grande decided against moving ahead with the CCS, FERC must study it as an alternative in a new EIS on remand. 

The court also criticized FERC for failing to properly consider data from a nearby air monitor, and on remand, it must use the data or supply a reasoned argument for not doing so. 

The court noted its decision to vacate the orders could have a significant impact on the two projects, but it was warranted due to FERC’s serious “procedural defects.” 

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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.”