NERC has selected Michael Ball, senior vice president and chief security officer at Berkshire Hathaway Energy, to replace Manny Cancel as CEO of the Electricity Information Sharing and Analysis Center (E-ISAC) and senior vice president at NERC, the ERO said March 24.
Ball will take over effective April 14, with Cancel planning to remain with the E-ISAC as an adviser until May 30, according to NERC’s press release.
The ERO began the search for a new E-ISAC head in April 2024, after Cancel announced he would retire in early 2025. (See NERC’s Cancel, Hoptroff to Retire in 2025.) NERC CEO Jim Robb said Ball’s “experience working with the E-ISAC over the years coupled with his relationships and reputation with industry leaders and key government agencies will provide us with the skills needed to continue maturing and elevating our E-ISAC capabilities.”
Ball has been with Berkshire Hathaway for 27 years, most recently leading a security team focused on strategic global cyber and physical security policies and practices. Previous roles at the utility include leading its company-wide risk management program and the quality assurance and business continuity teams at PacifiCorp.
“I’ve had the privilege of protecting critical infrastructure throughout my 27 years at Berkshire Hathaway Energy,” Ball said. “I’m honored to carry that mission forward on a broader scale, supporting industry as a whole and the key services that our members and stakeholders provide to their communities.”
Ball will take over the E-ISAC at a time of ongoing online pressure against North American utilities. In a recent filing, NERC told FERC that North American utilities reported three cyber intrusion attempts in 2024 that showed “an increased level of sophistication” on the part of the perpetrators. (See related story, ERO Says 2024 Cyber Incidents Showed “Sophistication”.)
In recent months, the E-ISAC and its counterparts for other industries have had to work without a leader at the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), which is charged with identifying and managing risks to U.S. cyber and physical infrastructure. The agency’s previous director, Jen Easterly, resigned prior to President Trump’s inauguration.
Trump recently nominated Sean Plankey, former Coast Guard officer and head of cyber policy at the National Security Council, to head CISA. The Senate has not yet acted on Plankey’s nomination.
Cancel joined the E-ISAC in 2020, taking over from Bill Lawrence. Before joining the ERO, he was chief information officer at Con Edison. Cancel has represented the industry before Congress and in other forums, such as the ERO’s annual GridSecCon security conference, and has overseen the past two iterations of the biennial GridEx security exercise.
During Cancel’s term at the E-ISAC, North American utilities have seen a marked increase in physical threats to grid reliability, as well as danger to electric equipment. Some of the threat actors have political motivations, such as the neo-Nazi leader who allegedly plotted to damage substations in Baltimore to start a race war. Other attackers have smaller-scale goals, like the men accused of damaging electric facilities in Washington state to cover up a burglary.
VALLEY FORGE, Pa. — PJM on March 19 presented the Markets and Reliability Committee with a proposed settlement with several clean energy associations and developers on its site control requirements for new generation projects (ER25-1544, EL25-22).
Filed with the commission March 10, the proposed tariff revisions would codify a set of rules on when developers may add or remove parcels from a project that is less restrictive than the reading PJM has advanced in its Order 2023 compliance filing (ER24-2045). The settlement would resolve a complaint from American Clean Power Association, Solar Energy Industries Association and Advanced Energy United. It also was signed by EDF Renewables, which had raised issues with the compliance filing.
The language in the settlement would replace a PJM proposal to revise Manual 14H to codify its interpretation, which several developers throughout the stakeholder process have argued is overly onerous. The MRC voted by acclamation to defer action on the manual revisions until FERC action on the settlement or 60 days from its meeting, whichever is sooner. (See “Voting on Site Control Requirement Manual Revisions Deferred Pending Settlement,” PJM MRC/MC Briefs: Feb. 20, 2025.)
PJM Director of Interconnection Planning Donnie Bielak said if the settlement is approved, conforming revisions to the manual would be required. If it is rejected, he said the RTO’s preference would be to pursue its originally proposed manual revisions.
Senior Engineer AJ Lambert said the key difference between the manual revisions and the settlement language is that in the latter, PJM would not require site control for parcels no longer needed for a project to be completed. It also would modify the decision point requirements and add clarification where there have been interpretation issues.
Changes to site plans would be permitted under the settlement so long as the developer can demonstrate there would be no impact to the “timing of milestones or transmission owner construction schedule.” By making such a change, the developer would waive the ability to request milestone extensions “related to permits or other land issues.”
Demonstration of site control over parcels no longer used on the site would not be required under the settlement. Any changes to interconnection facilities or switchyards would not be permitted if they would affect system impact or facilities studies.
The tariff currently requires that any changes to a project footprint be adjacent to the parcels included in the original project application, which would be expanded under the settlement to allow easements connecting parcels.
PJM’s proposed manual revisions have been deferred several times since being endorsed by the Planning Committee in December 2024, owing to the settlement negotiations. Discontent over the lack of insight into what was holding up consideration of the language led the MRC initially to vote against another deferral in February, but it reconsidered after PJM and EDF said they were confident an agreement was imminent. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.)
The revisions would allow parcels to be added to a project at Decision Point 1 (DP1), so long as the land is adjacent to the site or evidence of connecting easements is provided. Parcels also could be removed at this point if the project continues to meet the minimum acreage and energy output defined in the project application.
While there would be no specific requirement to demonstrate site control at DP2, the proposed language would state, “Site control must be maintained throughout the cycle process.” Adding parcels also would be permitted at DP2, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle.
No additions would be permitted at the final DP3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement to determine permissibility.
BOSTON — State energy officials emphasized the need for increased oversight of transmission investments at Raab Associates’ New England Electricity Restructuring Roundtable.
In recent years, costs associated with asset condition projects (ACPs), a class of transmission investments aimed at upgrading or replacing aging and degrading infrastructure, have grown significantly. State officials and consumer advocates call for changes to the process of reviewing these projects.
“We think it’s critical to get a handle on this sooner rather than later,” Phil Bartlett, chair of the Maine Public Utilities Commission, said at the March 21 roundtable.
Transmission owners already have made some changes to increase the transparency into ACP projects in response to requests from the states, including periodically releasing public data on under-development and in-service projects. ACPs classified as proposed, planned or under construction total nearly $6 billion, with major additional projects set to be introduced in the coming months. (See ISO-NE Planning Advisory Committee Briefs: March 19, 2025.)
The states continue to raise the lack of oversight for ACP spending and have called for the creation of an independent transmission monitor (ITM) “as a means of ensuring transmission costs are transparent and closely scrutinized.”
“The transmission owners are the sole determiners of what is an asset condition project,” Bartlett said. “These projects flow through FERC formula rates, so FERC isn’t taking a close look at them, there’s no process for ISO-NE to take a close look at them, and most of the states don’t have the authority to dig in and look too closely at them, so we think there needs to be some regional mechanism to make sure that there is reasonable accountability.”
In a filing to FERC on March 20 (EL25-44), the New England States Committee on Electricity (NESCOE) asked the commission to require that all “transmission investments recovered through the Regional Network Service rate be planned through an ISO-NE-administered regional transmission planning process.”
NESCOE also asked FERC to “adopt, in the nearest term, NESCOE’s longstanding request to implement an Independent Transmission Monitor,” adding that the specific responsibilities of the ITM “should be developed by the region to meet New England’s current region-specific needs.”
The states expressed concern the planning process for asset condition projects does not adequately consider “whether the transmission facilities from the grid of yesterday are actually needed for the grid of today or are the right projects to account for new resources creating new demands on the transmission system.”
“We want to make sure that [ACPs] are part of, or consistent with, a regional plan,” Bartlett said at the roundtable. “Instead of having every transmission owner simply operating in a silo, let’s make sure that those investments fit within a cohesive and sensible regional strategy.”
Commissioner Katie Dykes of the Connecticut Department of Energy and Environmental Protection echoed Bartlett’s concerns about asset condition oversight and said New England has seen a 72% increase in transmission costs since 2015, which now make up about 10-11% of electricity bills for residential consumers in Connecticut.
She highlighted a white paper published by the state in February that emphasizes potential cost savings associated with correctly sizing asset condition projects and incorporating advanced transmission technologies into transmission solutions.
Dykes stressed the importance of “ensuring that ratepayers can continue to trust that the increased amount of their dollars that is going to these projects is being reasonably spent.”
Without effective oversight, “we can’t really give that assurance,” Dykes said.
In an interview following the roundtable, Dave Burnham, director of transmission policy at Eversource, said the company is committed to working with the states and other stakeholders to improve ACP procedures and is open to discussions about creating an independent entity to review ACPs.
“I think it’s been a natural evolution from adding more transparency to now asking: ‘what should we do with this information?’” Burnham said. “We completely understand the desire from the states to have somebody looking at these projects with an independent view.”
He agreed that the region should establish a process to evaluate the proper sizing of ACPs when the projects overlap with obvious needs for increased transmission capacity. While asset condition projects often incidentally increase capacity, ACP projects typically do not aim to add capacity beyond these incidental gains, Burnham said.
He expressed his hope stakeholders can reach an agreement on an acceptable set of oversight and planning changes and said, “we don’t believe that FERC coming in and imposing a one-size-fits-all solution is the right thing to do.”
Incorporating Retail Demand Response
Speakers also highlighted the potential of demand response to help limit supply costs and reduce the need for additional grid infrastructure.
“There are all these retail programs that, for a variety of reasons, aren’t participating in the wholesale market,” said Bartlett, who leads a working group on retail demand response and load flexibility for the New England Conference of Public Utility Commissioners.
He expressed his hope the region can establish a simple, standardized mechanism to submit retail DR program information to ISO-NE “so they can see what’s coming … and therefore build it into operational planning, and down the road have conversations about how to ensure we are compensating these resources.”
Erika Diamond of EnergyHub stressed the need to make it easy for customers to understand and engage with demand response incentives.
“Our whole thing is trying to figure out how to make it as simple as humanly possible,” Diamond said.
She said the ConnectedSolutions program, which extends across multiple states and utility service territories in the Northeast, is a good model for reaching customers and vendors.
Marketing across “a vast territory with the same message is far easier than going utility by utility,” Diamond said, adding that “having a really simple program design has also really helped … along with making sure the compensation is the best fit for the technology.”
Fossil Infrastructure Updates
State officials at the roundtable also answered questions about the role of fossil fuel infrastructure as the region decarbonizes. The Trump administration has pushed to expand natural gas pipeline capacity, and Connecticut Gov. Ned Lamont (D) recently expressed an interest in additional gas capacity.
“If there are ways to make investments to help … address reliability challenges in the early 2030s that don’t result in stranded costs and do help shave overall costs on the electric bill,” Dykes said, “that may be a path to ensure that more people aren’t scared away from switching over to heat pumps and electric vehicles because of the sticker shock on their electric bill.”
Meanwhile, Melissa Lavinson, director of the Massachusetts Office of Energy Transformation, discussed the state’s ongoing work to reduce its reliance on the Everett LNG import terminal. The facility is under contract with the state’s gas utilities until May 2030, but the Massachusetts Department of Public Utilities has directed the utilities to work with the state to “reduce or eliminate their reliance” on the import terminal. (See Massachusetts DPU Approves Everett LNG Contracts.)
Lavinson said Everett is “an important asset for the state and the region,” but also is an expensive asset with volatile fuel costs and ultimately is incompatible with long-term state climate laws. She added that the state’s “focus is on the ratepayer” as it charts a future beyond the facility.
Massachusetts has been explicit in its goal to reduce its reliance on natural gas to meet its climate targets, and any efforts to expand pipeline capacity there likely would face strong political opposition. (See Massachusetts Moves to Limit New Gas Infrastructure.)
“Here in Massachusetts, we have very strong climate and clean energy laws — and I want to be really clear: laws,” Lavinson said. “And we are working very hard to comply with those and do it in a way that increases our energy independence, creates jobs and reduces our reliance on volatile, expensive fuels.”
Data centers may be driving electricity demand growth in the U.S., but air conditioning helped drive a 4.3% increase in worldwide demand in 2024, “bolstered by severe heat waves in countries such as China and India,” along with data centers, according to the International Energy Agency’s 2025 Global Energy Review.
In fact, the report says, 2024’s record-high temperatures drove a 6% increase in “cooling degree days,” a measure of cooling needs.
Released March 24, the report estimates that “weather effects contributed about 15% of the overall increase in global energy demand,” while also adding “around 20% to the increase in electricity and natural gas demand and … the entire increase in coal demand.”
Weather also was responsible for about half of the 0.8% increase in the world’s carbon dioxide emissions, which hit record highs of 37.8 gigatons and 422.5 parts per million of CO2, which is a 50% increase over preindustrial times.
IEA heralded the report as “the first global assessment of 2024 trends across the energy sector,” based on the latest data. The report differentiates between overall energy demand and the electricity demand that “is growing rapidly, pulling overall energy demand along with it to such an extent that it is enough to reverse years of declining energy consumption in advanced economies,” IEA Executive Director Fatih Birol said in the press release announcing the report.
Temperature effects contributed about 20% to the increase in electricity and natural gas demand and drove the entire increase in coal demand. | IEA
“The result is that demand for all major fuels and energy technologies increased in 2024, with renewables covering the largest share of the growth, followed by natural gas,” Birol said. “And the strong expansion of solar, wind, nuclear power and EVs is increasingly loosening the links between economic growth and emissions.”
“CO2emissions in advanced economies fell by 1.1% to 10.9 billion [metric tons] in 2024 — a level last seen 50 years ago — even though the cumulative GDP of these countries is now three times as large,” according to IEA.
Global GDP grew 3.2%, while overall global energy demand grew 2.2%.
What all these numbers show is that demand growth in the U.S. — and the potential solutions for meeting it — are part of larger global patterns and trends. The report also tracks sectors, like transportation electrification, where the U.S. is lagging behind China for global leadership.
AC and Data Centers
As in the U.S., renewable energy and nuclear resources are coming online fast in response to immediate increases in demand growth, providing more than 80% of new generation worldwide in 2024 — “a step up from 2023, when they accounted for two-thirds of total growth,” the report says.
“Solar PV led the way, increasing by about 480 TWh — the most of any source and far exceeding the previous year. Global generation from solar PV has been doubling approximately every three years since 2016, and it did so again between 2021 and 2024.”
Coal and natural gas still provide 60% of the world’s electricity — and grew 1% and 2.7%, respectively, in 2024 — the report says. Again, extreme weather events — particularly heat waves — accounted for about one-fifth of demand growth for natural gas.
Still, natural gas demand in the residential and building sectors grew only 1%, the report says.
The continuing dominance of fossil fuels notwithstanding, the IEA says renewables and nuclear are changing the world’s electricity mix. In 2024, for the first time, they generated two-fifths, or 40%, of all electricity.
Nuclear generation rose by more than 7 GW in 2024, up 33% over the previous year. New nuclear plants under construction grew by 50%. But these new plants were being built exclusively with Chinese and Russian designs, the report says, setting a challenge for U.S. companies seeking to break into global markets.
The U.S. definitely is behind growth curves in transportation electrification, according to the IEA. Kelley Blue Book pegged EV sales at 8.1% of total sales in 2024, versus 20% worldwide. China leads in this sector, with EV sales growing 40% year over year in 2024, although 80% of that growth was from plug-in hybrids.
China also is providing consumer subsidies of up to $3,000 “to encourage consumers to replace older, less efficient cars with new energy vehicles,” the report says.
Noting that buildings accounted for nearly 60% of total growth in electricity use worldwide — due to air conditioning and data centers — the report also tracks heat pump market growth, where China again is the global leader.
But the U.S. is the second-largest heat pump market, and sales are growing. While heat pump sales globally edged down 1% in 2024, they were up 15% in the U.S., where heat pumps outsold natural gas furnaces by 30%, the largest increase recorded to date.
The Bonneville Power Administration’s first day-ahead markets workshop since issuing the draft policy stating its intention to join SPP’s Markets+ left little opportunity for critics to probe agency officials about the decision.
That’s because the meeting featured a ground rule that largely checked inquiries from skeptics of the agency’s choice: Discussion had to be limited to “clarifying questions” about only what’s spelled out in the policy document.
“I want to be as clear as I can that these questions are really about the content that is in the draft policy, and it’s about clarifying that content,” Ashley Donahoo, BPA day-ahead markets lead, said at the start of the March 19 workshop, likely the last such meeting before the agency issues its final “record of decision” (ROD) in May. (See BPA Selects SPP Markets+ in Draft Policy.)
That instruction deviated from previous day-ahead workshops, where staff fielded a range of questions and took oral comments from participants on the fly. Instead, participants were instructed to reserve most questions for “formal” comments to be submitted to BPA through April 7.
“If I do say, ‘We can’t answer that question, you need to submit a formal comment,’ I’m not trying to be rude. This just is not the forum for that,” Donahoo said.
BPA offered its own clarification about the purpose of the meeting: “The workshop was intended to be an opportunity for stakeholders to ask clarifying questions on BPA’s day-ahead market draft policy as they prepare to meet our April 7 comment deadline.”
“This is a little bit challenging, this framework for the conversation,” said Stefanie Johnson, a strategic adviser with Seattle City Light, a BPA “preference” customer that has criticized the agency’s preference for Markets+. (See Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.)
Fred Heutte, senior policy associate at the Northwest Energy Coalition (NWEC), said the restriction meant a meeting scheduled for six hours lasted little more than two hours.
“Because it was limited only to ‘questions of clarification,’ the BPA day-ahead markets workshop was a missed opportunity for discussion of the broader themes of BPA’s draft market policy,” Heutte told RTO Insider.
Heutte’s frustration should come as little surprise to anyone familiar with the position of his organization, which has long advocated for the creation of a single Western electricity market that pointedly includes CAISO and California. NWEC has strongly and repeatedly urged BPA to join CAISO’s Extended Day-Ahead Market (EDAM) or at least postpone a decision until developments play out around the West-Wide Governance Pathways Initiative’s efforts to bring more independent governance to EDAM and the Western Energy Imbalance Market (WEIM). (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.)
“BPA’s own study shows it would risk a net loss of $100 million a year or more by joining the smaller of the two market areas instead of staying in the WEIM, which has proven its value to all participating areas,” he said, referring to the market benefits study consulting firm Energy and Environmental Economics conducted last year on behalf of the agency. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)
Heutte was the most persistent questioner during the workshop. His first question dealt with a statement in the draft policy that acknowledged BPA still lacks enough information to assess what impact joining Markets+ will have on emissions attributed to federal power purchases from the agency.
“When will that information be available and incorporated into your analysis?” he asked.
BPA climate change specialist Alisa Kasewater said the agency would be unable to provide a “quantifiable number” on emissions impact until it gets closer to operating in the market because of continued uncertainties. Questions remain around the interaction of state-specific greenhouse gas (GHG) rules with the market’s system for tracking and attribution of emissions, BPA’s own asset-controlling supplier emissions factor and the makeup of resources participating in the new market.
Kasewater addressed Heutte’s next question about what elements BPA prefers about the Markets+ GHG design. But Donahoo headed off his follow-up asking if BPA identified any preferable elements in EDAM’s handling of GHGs.
“I just want to be careful, because we are asking for clarifying questions. In the draft policy, was there something that you wanted clarified that you saw in there about what we said specifically?” Donahoo asked.
‘Fullness of Our Response’
Heutte elicited similar responses when he pressed BPA staff on other issues, including:
How BPA is differentiating between the vendor relationship Markets+ will have with SPP and that between EDAM and the Pathways Initiative’s proposed “regional organization.”
Given that SPP’s Board of Directors will retain “ultimate authority” over the RTO’s markets, “how much relative weight” in SPP management decisions will “Western interests” have compared with the broader SPP membership.
Why BPA isn’t waiting to see how this session of the California Legislature progresses on implementing the Pathways Initiative’s governance bill for CAISO.
“I understand your comments, and I do think you need to submit them formally,” Donahoo said. “I’m not hearing a clarification. I’m hearing more of a questioning of why we went our way.”
“I’m not trying to be argumentative; I’m trying to raise issues that we would like to clarify,” Heutte responded.
Speaking on behalf of the Northwest & Intermountain Power Producers Coalition (NIPPC), Henry Tilghman posed a question that referenced recent job cuts and resignations at BPA stemming from actions by the Trump administration. (See BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms.)
“I follow the news. I’ve talked to people at Bonneville. It sounds like you’re resource constrained. Can Bonneville deliver on the timeline to implement a day-ahead market in 2028?” Tilghman asked.
“I don’t believe we’ve mentioned 2028 in the draft policy, so I don’t see that as a clarifying question, but I recommend that you submit your comment,” Donahoo said. “And correct me if I’m wrong: DOE has restricted us from talking about staffing, so we can’t add anything to that.”
“I’m hearing a lot of mentions of, ‘Submit comments. We’ll address them,’” said Kalia Savage, principal transmission and markets policy analyst at Portland General Electric (PGE), which last year committed to joining EDAM.
“Since PGE has submitted comments throughout the process, we haven’t had all of our comments addressed. And then with the policy decision going towards Markets+, I would love to hear how comments are actually going to be addressed and considered given the policy decision direction,” she said.
Donahoo said BPA has posted on its website answers to any questions asked throughout the day-ahead market workshops, while comments on the draft policy will be addressed in the ROD.
“I’m quite sure in the fullness of our response, we will make a complete presentation of our views,” Heutte said.
‘Really Meaningful’
Still, BPA officials did address several stakeholder questions during the workshop, including some dealing with matters not explicitly spelled out in the draft policy.
In response to Tilghman’s question about whether BPA’s market analysis would be affected by delays in implementing the first binding season of the Western Resource Adequacy Program (WRAP), which Markets+ members are obligated to join, BPA’s Matt Hayes said the agency thinks WRAP participants, the Western Power Pool and SPP are committed to making the program work.
Besides, Hayes noted, beginning the WRAP’s binding period in winter 2027/28 technically doesn’t constitute a “delay” because the timeline still falls within the requirements of the program’s FERC-approved tariff.
Savage asked whether BPA would update its ROD after its May release based on developments coming out of the California legislature and CAISO’s GHG Working Group and upcoming EDAM congestion revenue rights allocation initiative.
“At this time, the final policy would be based on the facts that exist at the time of publication,” BPA attorney Erika Doot said. “If there were significant changes, we would consider whether we need to issue a subsequent document.”
As the meeting wound down, Chris Roden, director of energy services at Clatskanie (Ore.) People’s Utility District, sounded a supportive note for BPA.
“Reserving my opinion on where Bonneville is landing, I feel heard representing load — and also some independent generation — in the region,” Roden said. “I appreciate the process — the diligence — Bonneville has gone through, both from a legal perspective and a technical perspective. And this final ability to comment is really meaningful.”
“I recommend that you submit that formally. Thank you,” Donahoo joked.
A study of SPP’s future energy and resource needs has found the grid operator will have to rely on thermal generation to maintain grid reliability into midcentury. It will come at a cost.
The Brattle Group’s analysis says the RTO will require at least $88 billion and up to $263 billion of generation investment to support its load growth through 2050.
Much of that will be renewable energy. According to the study’s five scenarios, SPP could add at least 62 GW of renewable capacity and as much as 180 GW by 2050. SPP’s all-time demand peak is 53.2 GW, set in 2022.
“We can maintain the resource adequacy in a cost-effective and affordable way with all these new carbon-free resources in the system,” said SPP’s Afshin Salehian, who presented the study’s results to a March 19 joint meeting of several stakeholder groups. “There is still a value for fossil fuel generation capacity. [It is] needed to maintain the resource adequacy requirements in the most challenging hours of the system, and there are definitely needs for [that] fossil fuel generation in the system.”
In the study’s scenarios with high load growth and high shares of renewable generation, SPP is projected to affordably maintain resource adequacy if fossil fuel generation capacity is retained or replaced and sufficient new resources, including storage, are added to the system.
The Future Energy and Resource Needs (FERNS) study found that conventional generation will continue to serve about 40 to 60% of the region’s accredited capacity by 2050. However, renewable resources — aided by technology costs, natural gas prices and the availability of tax credits — will provide between 70 and 90% of the RTO’s annual energy, according to the study.
Brattle said SPP generated 47% of its energy from carbon-free resources in 2024.
“There [are] still fossil fuel generations in the system. They are generating some amount of energy,” Salehian said.
Simon Mahan, executive director of the Southern Renewable Energy Association, said the study highlights the importance of expanding transmission today and in the future.
“Just last week, wind energy resources were providing about 60% of SPP’s electricity demand,” he said, noting wind energy’s 58.2% share of the fuel mix at 11 a.m. CT March 19.
“SPP’s study demonstrates the need for additional transmission to help retain costs, maintain reliability and expand clean energy resources,” Mahan added.
Indeed, the FERNS study found SPP will need between 4 and 21 GW of new transmission capacity in its pricing zones.
“This study was not a transmission planning study but as we were trying to meet the demand in different scenarios, we realized that it is cheaper to build transmission rather than meet the demand locally with local generation,” Salehian said. “We had to build large-scale, long distance transmission lines to access higher-quality generation resources in other zones or in renewable-rich zones.”
The FERNS study was designed to find the most cost-effective future resource mix to meet system needs through 2050 and determine how the operational and investment costs vary across the five scenarios. It also identified the current resource adequacy framework’s shortcomings in a highly electrified and decarbonized future.
Brattle analyzed the change in SPP’s generation mix from 2030 through 2050, its resource adequacy risks, and the transformation’s cost, given the changes in supply and demand. It used a zonal capacity expansion model for each of the five FERNS scenarios and for recognizing interconnection with the RTO’s neighbors.
The study also found that by 2050:
Solar generation (between 42 and 130 GW) will outpace wind generation (between 20 and 48 GW). That also will require between 22 and 59 GW of battery storage, often co-located, to maintain resource adequacy.
Winter planning reserve margins will need to be “significantly higher” than summer reserve margins because of low solar capacity values and high temperature-correlated fossil outages in the winter.
There’s enough available land in SPP’s footprint to accommodate the additional projected wind and solar capacity in all scenarios evaluated.
Effective load-carrying capability (ELCC) values for solar and short-duration storage resources are projected to decline over time, but wind resources’ ELCC will increase slightly. That indicates a need for long-duration storage and interties with neighboring regions that offer resource adequacy and extreme-weather resilience benefits.
The grid operator is expected to take advantage of its ample renewable generation and become a more significant net exporter to other regions.
The study began in 2024 and was coordinated with SPP staff and stakeholders. It was sponsored by the Future Grid Strategy Advisory Group (FGSAG) and endorsed by the Resource and Energy Adequacy Leadership Team.
The study itself is not yet available. Salehian will present the study’s findings to the FGSAG on March 31 and again during the April 16-17 Strategic Planning Committee meeting. An SPP spokesperson said the final report will be published with the SPC meeting materials the week before.
U.S. utilities reported three cybersecurity incidents to the Electricity Information Sharing and Analysis Center (E-ISAC) in 2024, highlighting “the continued need for vigilance” even though none of the events affected grid reliability, NERC said in a filing to FERC on March 21 (RM18-2).
Electric utilities are required by reliability standard CIP-008-6 (Cybersecurity — incident reporting and response planning), which took effect in January 2021, to report qualifying cybersecurity incidents to the E-ISAC. (See FERC OKs Cyber Reporting Rule.) According to NERC’s technical rationale for the standard, reportable incidents are those that compromise or disrupt:
a cyber system that performs one or more reliability tasks of a functional entity;
an electronic security perimeter of a high- or medium-impact grid cyber system; or
an electronic access control or monitoring system of a high-impact grid cyber system.
FERC Order 848 directs NERC to submit an “annual anonymized, public summary of the reports” to the commission. Reports must include the intended effect of the cyber incident, the attack vector of the incident and the level of intrusion the attacker achieved or attempted.
NERC’s cyber incident report for 2024 did not identify the reporting entities, but it did note that one report was in the territory of the Northeast Power Coordinating Council, one in ReliabilityFirst and one in WECC. The ERO did not specify which reports (identified as A, B, and C) originated in which territory.
Report A detailed an incident in which the responsible entity received 20 alerts from its security information and event monitoring system that someone had tried to log in to a medium-impact grid cyber system. The login attempts used an intermediate system and appeared to originate from IP addresses in Wyoming and Florida. The entity believed both addresses were from the same attacker because they used the same username for the login attempts.
In report B, the entity indicated it had received multiple failed virtual private network authentication attempts across two apparent attempts to compromise. The first attempt involved multiple IP addresses from a foreign country, resulting in users being locked out. The next try occurred about a month later, with a “large volume of failed authentication attempts” targeting the same VPN interface. All attempts were “linked by the same internet service provider,” NERC said.
The final report covered an attempted scan of an entity’s Supervisory Control and Data Acquisition (SCADA) network by a foreign IP address. NERC said company logs showed the “attacker only made initial connections to the network and then was blocked by the entity’s firewall.”
According to NERC’s report, the biggest effect to utility operations from any of the incidents was the loss of access by an unspecified number of users during the first intrusion attempt identified in report B, and about 20 user accounts in the second attempt. The incident “strained operational efficiency and the IT service desk handling the … lockouts,” NERC said, but the attackers failed to gain access to any grid cyber systems.
Reports A and C did not identify any disruption to operations. NERC said the controls of both entities “were effective in identifying and mitigating the [attempts] to compromise.”
The ERO noted that none of the three incidents rises to the level of a reportable cyber incident because the attackers did not compromise or disrupt any grid cyber systems. However, two of the attacks showed “an increased level of sophistication” compared to attempted intrusions in previous years through the use of multiple IP addresses.
The E-ISAC has received 16 reports on cybersecurity incidents since CIP-008-6 went into effect, none of which qualified as reportable. Half of these were received in 2022; three each arrived in 2023 and 2024, and two came in 2021. Malware such as Trojan horses and ransomware was the most common attack vector over the past four years, accounting for 38% of the reported incidents. The next most common was attacks on third parties that support grid operations.
While NYISO operated reliably last winter, the season provided “continued examples of limited flexibility on the gas system,” ISO staff told the Operating Committee on March 20.
Temperatures were below average last winter, but there was no need for emergency operations, Aaron Markham, NYISO vice president of operations, said in presenting the cold weather operations report.
There were 16 daily peak loads in excess of 22,000 MW, the most since the 2017/18 winter, with the peak load of the season occurring on Jan. 22 at 23,521 MW. NYISO’s record is 25,738 MW, set Jan. 7, 2014.
The peak occurred during a cold snap that began over the Martin Luther King Jr. Day weekend. When the peak load occurred during the 6 p.m. hour Jan. 22, about 18% of the fuel mix was natural gas and 27% was oil. Markham indicated that this, and the high rate of oil consumption over the coldest days, showed that there were problems with gas procurement, leading to stored oil use.
“We did see some larger non-firm gas units actually put in derates during the Martin Luther King weekend as a result of a forecasted inability to get gas in response to the day-ahead schedule,” said Markham. “I don’t think we’ve actually seen that before, so that was kind of noteworthy.”
Markham said that the average forced outage rate was higher than average during the winter. It was a challenge to manage unavailable capacity in gas units between the day-ahead and real-time because gas generators did not have their normal operational flexibility. Many dual-fuel units resorted to oil, leading to depleted oil reserves statewide.
February Operations Report
Markham also presented the operations report for February.
While the month was milder than January, cold weather produced a peak load of 22,651 MW on Feb. 18. Toward the end of the month, Markam said there was a forced outage in the Greenwood/Staten Island load pocket in New York City caused by a transformer coming out of service while another parallel circuit was also out. NYISO implemented a targeted demand response program in the area.
Markham also mentioned that NYISO had found the source of curtailments of wind and solar resources in New York’s southern tier. A circuit breaker at a substation in Union was “stuck,” affecting several other lines nearby.
“We were able to work with the transmission owner to implement a strategy to avoid the stuck breaker contingency,” said Markham, who went on to say that the ISO was evaluating whether their solution met the criteria for a facility to be secured in its market models.
FERC once again decided that neither MISO nor Montana-Dakota Utilities are entitled to recourse over a MISO-SPP flowgate in North Dakota strained by a cryptocurrency mining facility.
The commission denied both MISO and Montana-Dakota Utilities’ requests for rehearing in a March 20 order (EL24-61 et al.). It said it found nothing amiss with the 230-kV Charlie Creek flowgate’s continued eligibility for market-to-market (M2M) coordination despite high congestion costs.
FERC first denied MISO and member Montana-Dakota Utilities Co.’s separate complaints over the Charlie Creek flowgate in September 2024. The two had argued that the congestion caused by the new cryptomining operation should fall to SPP alone because it’s a local issue brought on by data center load growth. But FERC said neither MISO nor Montana-Dakota Utilities proved that Charlie Creek failed to meet the criteria for M2M coordination, nor was SPP in the wrong for continuing to insist on M2M coordination. (See FERC Refuses MISO, MDU Complaints Regarding Crypto-strained MISO-SPP Flowgate.)
FERC kept that stance in its latest order. The commission pointed out that the Charlie Creek flowgate passed some of the studies required under MISO and SPP’s congestion management process to be eligible for M2M coordination. It also said it was unconvinced that MISO and SPP’s interregional coordination process laid out in their joint operating agreement is unreasonable.
MISO had said the flowgate, which serves the 200-MW Atlas Power Data Center, cost its members more than $40 million in unjustified M2M payments. The RTO argued it could provide little congestion relief for SPP’s transmission-constrained northwestern North Dakota load pocket. MISO also accused SPP of defying the two’s M2M coordination protocol by refusing to revoke the line’s M2M designation and insisting on interregional help for a provincial issue that MISO was powerless to resolve. Finally, MISO complained it couldn’t veto the M2M status of the line without SPP’s consent. (See MISO Argues to FERC for 2nd Look at Crypto-stressed Flowgate Management and SPP, MISO Clash over Crypto-strained M2M Flowgate.)
But FERC disagreed with MISO that the M2M process is unfair because it doesn’t account for cost causation. The commission said MISO and SPP’s coordination process is established on forecasted allocations with no requirement that the hundreds of M2M flowgates it serves be reviewed individually. The commission said such a style of cost allocation isn’t meant to be roughly commensurate with estimated benefits.
FERC noted SPP’s argument that about 20 other M2M flowgates at the seams “possess arguably ‘local’ attributes and impose ‘higher than expected’ congestion costs on SPP that require [M2M] payments to flow from SPP to MISO.” The commission said a single flowgate in particular cost SPP $12.5 million in M2M payments to MISO in fall 2023.
FERC also disagreed with MISO that it and SPP’s interregional coordination process is one-sided because it doesn’t allow one RTO the ability to revoke an M2M designation.
The commission also said it didn’t buy MISO’s argument that it doesn’t have enough generation nearby to help alleviate congestion on Charlie Creek. On the contrary, FERC said MISO operations contribute to congestion on the flowgate, where it serves load in the Williston, N.D., area. Flowgate studies from MISO and SPP’s coordination process show the line is “significantly impacted” by MISO flows from generators that exceed 5% in real-time, FERC said. It added that SPP confirmed that if the flowgate was withdrawn, it might have to resort to transmission loading relief.
FERC decided against ordering SPP and MISO to make any specific adjustments to their M2M coordination process, as MISO requested. It ended by asking them to work together.
“We encourage the parties to continue negotiating prospective revisions to their agreements, especially in light of SPP’s and MISO’s positions that similar issues are either currently occurring on other [M2M] flowgates or are likely to recur on other [M2M] flowgates in the future,” FERC wrote.
Additionally, FERC disagreed with Montana-Dakota Utilities’ complaint that a combination of congestion charges and M2M payments stemming from Charlie Creek caused it to be double-charged.
The utility claimed it was billed for the same congestion once under the SPP tariff and again to reimburse MISO for M2M coordination. But FERC said the two are “distinct charges provided for under different frameworks that serve separate purposes.” It explained one is incurred as a customer of SPP while the other is meant to cover interregional coordination charges.
In a separate but related docket on FERC’s March 20 agenda, the commission also turned down MISO’s request to waive SPP’s yearlong statute of limitations on resettlements (ER24-1586-001). MISO was counting on FERC to allow a prolonged resettlement period to refund affected members some of the M2M payments, had FERC directed refunds. SPP said that allowing settlement adjustments outside of the window would amount to retroactive ratemaking.
FERC on March 20 accepted SPP’s proposed tariff revisions incorporating a mark-to-auction (MTA) collateral requirement for its transmission congestion rights (TCR) market while stopping short of terminating a show-cause proceeding dating back to 2022 (ER24-2906).
SPP had requested that the commission terminate the ongoing show-cause proceeding (EL22-65) as part of its proposal, but FERC declined. It said that while the RTO’s proposal included just and reasonable reforms to allow for the re-marking of monthly TCRs acquired in the annual auction, “it does not fully address the commission’s concern that SPP’s TCR collateral requirements may not adequately address the increased risk of default that results from a TCR portfolio that declines in value.”
It further explained that seasonal TCRs — emphasizing the difference with monthly TCRs — would not be re-marked based on clearing prices in subsequent TCR auctions.
“Thus, the associated collateral requirements do not reflect a possible decline in value of those seasonal TCR products. Accordingly, SPP must still respond to the directives in the 2023 show-cause order,” the commission said, referring to an earlier ruling that the RTO’s tariff didn’t include an MTA requirement or comparable alternative. (See FERC Rebuffs PJM, SPP on FTR Credit Rules.)
SPP said it re-evaluated whether an MTA could be developed in its TCR market to address FERC’s concerns over the use of historical price data to calculate collateral requirements. It said the proposed revisions would mitigate a TCR portfolio’s risk of declining in value over time by implementing more frequent updating of collateral requirements based on valuations from more recent TCR auctions.
The RTO said the changes proposed in protests by DC Energy and the Energy Trading Institute would require “nothing short of a complete TCR market redesign.” SPP’s Market Monitoring Unit originally intervened in support of the grid operator but later said the proposal did not appear to be consistent with the commission’s show-cause order.
FERC granted SPP’s request for waiver of the commission’s 120-day notice requirement for good cause shown and accepted the proposed tariff revisions effective May 1.
MMU Doesn’t Get Rehearing
In a separate order, FERC rejected the MMU’s rehearing request of its acceptance of SPP’s proposal to establish a winter season resource adequacy requirement (RAR) by modifying its order and sustaining the result (ER24-2397).
The MMU said the commission erred in its November 2024 order approving the RAR. It contended that FERC erred in finding that SPP does not study forced outages and violated the rule of reason by failing to require the inclusion of outage scheduling procedures in the RTO’s tariff. The Monitor requested that FERC direct SPP to define “forced outage” in a compliance filing and to include its outage study procedures in the tariff at issue.
The commission said it was unpersuaded by the MMU’s arguments. It said SPP’s proposed language included the definition of an “authorized outage” that differentiated which resources can be counted toward a load-responsible entity’s RAR from those that cannot. It said the RTO’s outage coordination methodology makes clear that forced outages are those “forced” upon the SPP system, as opposed to other outages that are studied and approved.
FERC also disagreed with the MMU that SPP provided insufficient detail related to the tariff’s outage scheduling procedures to satisfy the rule of reason. It found that the RTO’s proposed language does not need to include the outage study procedures and said the MMU’s specific arguments pertaining to how SPP will study outages and whether the tariff contains sufficient detail on the procedures were beyond the scope of the proceeding.
The commission said it did not find that SPP’s forced-outage definition “‘significantly impacts rates’ in such a manner that the rule of reason” would be included in the tariff. FERC noted that while it found the definition of “seasonal net peak load” in a separate SPP proceeding “significantly affects rates” because it had a direct impact on effective load-carrying capability values, “the relationship between how SPP will study outages and the final resulting rate is only relevant as to the” performance-based accreditation methodology.
