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March 30, 2025

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Company Briefs

DOE Approves Venture Global to Export LNG to More Countries

The U.S. Department of Energy has approved Venture Global to export LNG from its Cameron Parish facility to more countries. 

The approval means Venture Global can export LNG from its Calcasieu Pass 2 project to any country, including Europe. Previously, the plant was limited to exporting to the 20 countries the U.S. has free trade agreements with, which includes nations such as Australia, Canada, Israel, Korea, Mexico and Singapore. 

CP2 is expected to pump out about 20 million tons of LNG annually, which would make it the third-largest exporter in the nation. 

More: Nola.com 

OCI Holdings to Build 2-GW Solar Cell Plant in Texas

Korean chemical industries company OCI Holdings says it will build a 2-GW solar cell production facility in Texas. The company will invest $265 million in the plant that will initially produce 1 GW of cells annually before increasing to 2 GW in 2026. 

More: PV Tech 

RWE, Meta Sign PPA with Texas Solar Project

RWE and Meta has announced a new power purchase agreement with a 200-MW solar project in Texas. Under the agreement, Meta will purchase 100% of the output from RWE’s Waterloo Solar project, which is set to begin construction in late 2025. 

More: RWE 

T1 Energy Reveals Site of New Solar Factory

T1 Energy, formerly FREYR Battery, has revealed that the location of its new U.S. solar cell factory will be in Milam County, Texas. The $850 million facility will be a part of the Advanced Manufacturing and Logistix Campus at Sandow Lakes and will produce up to 5 GW of solar cells. Construction of the factory, which is expected to be one of the largest solar manufacturing facilities in the U.S., is scheduled for mid-2025. 

More: Electrek; Houston Chronicle 

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Utilities Ask FERC to Toss Local Tx Planning Complaint; Others Support It

FERC was flooded with comments on a wide-ranging complaint consumers filed seeking increased oversight of local transmission planning, with utilities arguing the complaint should be tossed, while others contend it has merit and raises issues that need to be addressed.

The complaint alleges that transmission owners around the U.S. have been moving more projects into local transmission siting processes because they fall into a regulatory gap with minimal oversight (EL25-44). To remedy that, the complainants contend, all lines rated at 100 kV and above should be regionally planned, and FERC should set up “independent transmission monitors” to oversee the planning process. (See Consumer Groups Seek Independent Oversight of Local Tx Planning.)

The complaint was lodged against every RTO and ISO and all other transmission planners under FERC jurisdiction.

In comments filed March 20, the Edison Electric Institute said the complaint “is anti-infrastructure, suggesting unworkable requirements that would stymie the development of necessary transmission projects at a time when substantial investment in transmission is needed to serve growing load, support generation expansion, and maintain reliability, as well as to support national security and ensure the United States is positioned to be economically competitive in the global market.”

EEI echoed an argument common among opponents of the complaint: that in highlighting broad general issues with local transmission, the complaint failed to meet the burden of proof FERC requires to grant filings under Section 206 of the Federal Power Act.

“Complainants take pages to recount history, identify a host of transmission projects rated at 100 kV, cite to various studies in support changes that would apply nationally, apparently in service of ensuring that consumers are afforded ‘economically efficient energy services at a reasonable cost,’” EEI said. “Yet, they draw no clear linkage between the recitation of history, listing of projects, and the requested relief.”

Like many other opponents, EEI also said the complaint amounts to a collateral attack on previous FERC orders on transmission, including Order 1920. FERC considered requiring more oversight of local transmission and independent transmission monitors in the rulemaking process that led to Order 1920, but did not include those changes in the final rule.

“Local transmission investments are vital to enabling the interconnection of distribution resources, as even concentrated pockets of distributed resources can require localized transmission system reinforcements such as the reconductoring of lower-voltage lines or the construction of new substations,” EEI said. “Local projects also enable transmission owners to nimbly develop infrastructure needed to effectuate state goals. In addition, upgrades to local, lower-voltage facilities are often needed to quickly meet changing system conditions and improve operational flexibility.”

WIRES Group also urged FERC to reject the complaint, saying now is not the time to inject uncertainty into the transmission planning process given the challenges facing the grid.

“Utilities are facing potentially overwhelming demand driven by data centers, and artificial intelligence,” WIRES said. “Investment in transmission infrastructure will enable the interconnection of new generation, the service of new load demands and efficient operation of the grid.”

Centralizing all local planning at 100 kV and above would prove unworkable, WIRES said. Regional planners would have to replicate a public utility’s in-house staff, including transmission and substation engineering experts, real estate specialists, field crews, environmental staff and operational personnel.

“It is difficult to conceive how a regional planner could fill those needs in a timely fashion, even if such experts were available for hire,” WIRES said. “Complainants fail to explain how this transfer or duplication of staff, knowledge or expertise is even reasonable, efficient, or cost effective for customers.”

On top of staffing, there are issues with handling data from local utilities that often is confidential, WIRES said.

NARUC did not weigh in on the specifics of the complaint, but it intervened to note it had passed a resolution at the recent winter meetings that is related to local transmission planning oversight.

“NARUC urges the commission to act swiftly to put in place effective and robust transmission cost management and oversight processes for ‘end of life’ or ‘asset condition’ transmission projects in RTO regions, when requested by states within the region, with recovery of associated costs borne by those regions,” it said in brief comments.

Regional Views

Some comments from individual states highlighted how inconsistent oversight for local transmission is at the state level.

The California Public Utilities Commission said any “repair and replace” projects that do not expand grid capacity are not included in CAISO’s planning process. From 2019 to 2021, 63% of capital additions in the ISO’s territory were “self-approved” by utilities.

“The proportion of spending on utility self-approved projects continues to be the overwhelming majority of transmission spending by California’s three large IOUs and has actually increased over past years,” the CPUC said. “In the most recent data from the CPUC’s Transmission Project Review (TPR) Process, nearly 75% of the capital expenditures on the IOUs’ transmission projects over $1 million for years 2020 through 2024, were on self-approved projects.”

Cost estimates for new CAISO transmission required over the next 20 years range from $45.8 billion to $63.2 billion.

“Taken in its entirety, transmission investment in the CAISO in the next 20 years could be staggering, and measures are needed in the CAISO and elsewhere to enhance transparency and oversight of more transmission projects to promote affordability and to achieve the most cost-effective transmission grid possible,” the CPUC said.

The New York Public Service Commission told FERC that local transmission projects in its territory are covered either through utility rate cases or state-run planning processes designed to meet the state’s climate and renewable energy goals.

“While the complaint is directed at the NYISO, it implicates the traditional regulatory authority exercised by the NYSPSC,” it told FERC. “The NYSPSC strongly opposes the complaint, which seeks a remedy that would preempt the NYSPSC’s existing planning authority and rate oversight covering local transmission upgrades and replacements under state law.”

New York’s transmission owners agreed, saying FERC should deny the complaint for being legally and factually deficient.

“The ink is barely dry on Order No. 1920-A, rehearing requests are still pending commission consideration, and transmission providers across the United States — including the NYISO — are hard at work developing their compliance proposals,” they said. “The commission, for its part, is actively overseeing compliance — a process that is both deliberate and essential to ensuring a smooth transition to a long-term orientation in regional transmission planning.”

New England states generally supported the complaint, but the Maine Public Utilities Commission intervened to say that its review of local transmission projects offered enough oversight, though it couldn’t extend that claim to the entire region.

“While the complainants correctly identified a regulatory gap present in New England, the MPUC submits that the one-size-fits-all remedy proposed by the complainants is inappropriate and should be rejected,” the regulator said. “Any remedy to the regulatory gap identified by complainants should consider regional differences and provide for regional flexibility, especially since, as described below, there are already regulatory and state statutory frameworks in place that address certain aspects of asset condition projects.”

The New England States Committee on Electricity agreed with complainants that the process in New England is not just and reasonable because asset condition projects are too lightly overseen.

“Unlike transmission projects in New England that ISO-NE selects to meet reliability needs through the regional planning process, the process to rebuild, refurbish or replace aged and damaged transmission facilities is conducted by individual and investor-owned transmission companies on an ad hoc basis,” NESCOE said. “The scale of these projects, to a substantial degree, go beyond mere ‘in kind replacements’ and instead are leading to the massive reconstruction of the regional electric power grid. Yet ISO-NE, the regional system planner, is largely shut out of this process.”

While the New England states complained about the process there, some of the biggest transmission owners in the region (Avangrid, Eversource, National Grid and others) argued the process already benefits from oversight.

“The NETOs’ [New England Transmission Owners] asset condition project planning process provides opportunities for state regulators, consumer advocates and other stakeholders to participate, ask questions and challenge projects before costs are allocated to customers across the region,” they told FERC. “Additionally, the NETOs, the New England states and regional stakeholders have been working to further improve the transparency of asset condition project planning and enhance opportunities for stakeholder participation in that process.”

The complaint also led to a split among PJM stakeholders, with the Organization of PJM States Inc. filing brief comments at least agreeing that FERC should deal with the issues highlighted in the complaint.

“Local planning of transmission in the PJM region has vastly outstripped regional planning in recent years, and thus retail consumers have not been able to reap the benefits of regional, more holistically planned projects,” OPSI said.

OPSI did not take a position on the complaint, but said it wants FERC to address the proliferation of locally planned transmission projects with finality.

PJM, on the other hand, urged FERC to reject the complaint.

“The complainants failed to bear the burden of demonstrating with substantial, specific evidence that PJM’s regional planning provisions are unjust and unreasonable because they do not also encompass local transmission planning,” the RTO said. “PJM’s regional transmission planning authority stems from that granted by the PJM Transmission Owners which have each turned over operational control of their interstate transmission systems to PJM, and reserved for themselves the continued right to local transmission planning.”

Some Ask ‘Why Us?’

With its broad allegations against the entire industry, some of the respondents questioned why they had been cited in the complaint in the first place.

SPP noted that its planning process largely already aligns with what the complaint wants, but it still was compelled to file a response. A group of its transmission owners, including American Electric Power, Evergy and Xcel, agreed with the RTO.

“As a threshold matter, the complaint should be dismissed outright with regard to the Southwest Power Pool and the SPP TO Group because the complaint concedes that ‘SPP’s regional approach is consistent with the relief requested nationally through this complaint,’” the TOs said.

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PJM MRC/MC Briefs: March 19, 2025

Markets and Reliability Committee

Stakeholders Endorse IRM and FPR for 2026/27 Capacity Auction

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed by acclamation PJM’s recommended installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2026/27 Base Residual Auction (BRA), with 40 load-serving entities and consumer advocates abstaining over what they called a lack of transparency into how the RTO arrived at the figures.

The IRM would increase to 19.1%, up from 17.8% in the 2025 Third Incremental Auction (IA), and the FPR would fall to 0.917 from 0.938. PJM’s Patricio Rocha Garrido said almost all of the change is being driven by increasing demand in the load forecast, particularly in the winter. The seasonal balance of risk tilts to 65% loss-of-load expectation in the winter, increasing from 54.5% in the third IA; for the expected unserved entry metric, 93.9% of the risk would be in the winter.

The effective load-carrying capability ratings for most classes would also shift in line with increased winter risk. The rating for offshore wind would increase by 7%, to 69%, followed by onshore wind at a 3% increase, to 41%. In addition to having strong winter performance, Rocha Garrido said resources in the wind categories received transitional capacity interconnection rights (CIRs), which boosted the class’s overall ratings.

Demand response resources would see their ratings fall by 8 points to 69%, while storage ratings would decline between 5 and 7% depending on the resource duration. Gas resources would see more modest drops, in part because of changes in class membership, while other thermals would be flat or fall by 1%.

Rocha Garrido said PJM ran a sensitivity using the 2025 resource portfolio and found there was minimal impact on ratings compared to 2026 expected resource mix, which he said supports the conclusion that most of the changing dynamics are being prompted by the load forecast. He explained the reason there is more winter risk is because of extreme peak loads increasing in the 2025 forecast relative to 2024, while the summer peak loads are not growing relative to the 2024 forecast.

Scope of Deactivation Task Force Widened to Include RMR Agreements

Stakeholders endorsed charging the Deactivation Enhancement Senior Task Force with exploring the creation of a pro forma reliability-must-run agreement.

The MRC endorsed the change with 85% support, followed by the Members Committee endorsing by acclamation the same day. (See “PJM Presents Changes to DESTF Issue Charge,” PJM PC/TEAC Briefs: March 4, 2025.)

The revisions to the task force’s issue charge add a new key work activity (KWA) to draft a pro forma arrangement that recognizes the possible resource adequacy that RMR units can contribute and be effective for the 2028/29 delivery year. That year is when a temporary tariff provision allowing PJM to model the output of some RMR resources as capacity is set to expire (ER25-682). (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

The new language also expands the scope of the issue charge to allow consideration of a pro forma RMR agreement and changes to the capacity market rules around generators that have requested deactivation but which PJM has determined are necessary to maintain reliability. The out-of-scope section also was revised to carve out the new KWA.

Several generation owners noted PJM’s target of submitting a proposal to FERC around the end of the year would prevent changes to how RMR resources interact with the capacity market from being considered in the Quadrennial Review, which is in its early stages at the Market Implementation Committee.

Vistra’s Erik Heinle said each RMR resource is unique and any pro forma agreement should retain the ability for a generation owner to pursue a cost-of-service rate at FERC. He suggested including language in the issue charge stating that owners of a deactivating unit can develop an agreement with PJM outside of the pro forma approach.

PJM Senior Counsel Chen Lu said he does not believe the proposed language would preclude that ability, adding it would be up to stakeholders to come up with rules that govern that.

Stakeholders Endorse Manual Language Expanding SIS

The committee endorsed revisions to Manual 14H implementing expanded eligibility for surplus interconnection service (SIS), reflecting tariff changes FERC approved in February. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)

SIS allows generation owners with resources that are not using their full injection rights to co-locate additional resources at the same point of interconnection, so long as the host resource’s CIRs are not exceeded and no network upgrades are triggered.

The new language eliminates categorical restrictions on what resources — battery storage in particular — are eligible for SIS; changes how PJM models projects proceeding through SIS alongside those in the general interconnection queue; expands eligibility to applications where the host generator still is in development; and allows projects that consume transmission headroom but do not require network upgrades. It also would allow projects that require additional interconnection facilities for the service while still prohibiting new network upgrades.

Applications that could affect the network upgrades required for projects in the interconnection queue that have not had PJM determine if they will require upgrades also no longer would be prohibited from proceeding as SIS projects. The changes also eliminated language preventing SIS applications from proceeding if PJM has identified that the project would have a “material impact” on dynamic system stability response, steady-state thermal and voltage limits, or short-circuit capability limits.

The manual language was endorsed by the Planning Committee during its March 4 meeting. (See PJM Stakeholders Approve SIS Manual Language.)

PJM Presents 1st Read of Proposal to Rework Black Start Compensation

PJM’s Glen Boyle presented a first read of a proposal to rework the base formula rate (BFR) used to compensate black start resources not carrying investment costs for providing the service.

The proposed tariff revisions were endorsed by the MIC during its March 5 meeting. (See PJM Stakeholders Endorse Changes to Black Start Compensation.)

The BFR includes numerous variables, including fixed and variable costs, training, fuel storage, and an incentive factor. The proposal would revise the fixed cost element to replace the zonal net cost of new entry (CONE) with a fixed value derived from the five-year RTO-wide CONE, which thereafter would be adjusted using the Handy-Whitman Index. Boyle said PJM does not see a correlation between net CONE and the need for black start resources, nor should there be a locational element to the price.

Boyle said PJM is concerned that if compensation for existing black start units is not increased, more resources will cease participation and they will have to be replaced on the more costly capital recovery factor (CRF), which is used to determine compensation for resources that require upgrades to provide black start. PJM is not proposing any changes to the CRF.

Since 2019 there have been 29 resources that stopped providing black start service, 26 of which were replaced through requests for proposals. All but two of the new black start units began providing the service on the CRF. Boyle said about 85% of the black start fleet is compensated through the BFR.

Independent Market Monitor Joe Bowring said there should be a focus on finding a way to compensate resources that fully considers their costs and ensures they see an appropriate return. He argued that the proposal, which was sponsored by PJM at the MIC, does not have a definition of an appropriate payment.

The Monitor’s proposal, which did not win the MIC’s support, would have used the RTO-wide net CONE, rather than zonal values, and included a recommendation that a more holistic stakeholder discussion be initiated to reconsider compensation.

“This is simply refusing to address the underlying issue and making vague and unsupported allegations,” Bowring said.

In previous meetings, Bowring noted the process was instigated by the net CONE for future BRAs falling with the shift to a combined cycle turbine as the reference resource. FERC since has granted PJM’s request to keep the reference resource as a combustion turbine.

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates have been troubled by the lack of a metric to demonstrate the RTO’s concerns that generation owners may be considering pulling their resources out of black start service.

Stakeholders Discuss Uplift Costs Seen During January Storms

PJM presented the impact winter storms during January had on uplift payments, which amounted to nearly $332 million between Jan. 19 and 23.

Storms falling on long holiday weekends have proven to be a challenge for PJM, as gas resources typically must purchase a package with a steady rate of fuel when nominating for supply on weekends and holidays. (See PJM: ‘Conservative Operations’ Maintained Reliability During Jan. 2024 Storm.)

Senior Dispatch Manager Kevin Hatch said the Martin Luther King Jr. Day weekend saw highly variable load, which complicated efforts to block schedule gas. The start of the weekend was forecast to have fairly modest loads, but ramped up to some of the highest winter peaks PJM has seen. Gas pipelines already had restrictions in place going into the weekend, and there was uncertainty about whether resources connected to those pipelines would be able to get fuel on the spot market.

PJM also had some resources start ahead of time so that any equipment failures associated with start-ups could be resolved before the storms rolled in. Once those units were online, Hatch said operators sought to avoid cycling them on and off throughout the storm to ensure they could remain available.

The RTO employed a new conservative operations procedure established after December 2022’s Winter Storm Elliott, allowing operators to commit resources in advance when they believe those units could have difficulty procuring fuel or otherwise are at risk of not being able available. Several stakeholders have argued the practice violates market principles and significantly increased uplift costs.

The majority of the uplift was balancing operating reserve credits, amounting to $206 million, while day-ahead operating reserve credits accounted for an additional $126 million.

In addition to impacts on the energy market, the amount of uplift paid during the January storm had a notable effect on the net CONE aspect of the capacity market, said Adrien Ford, director of wholesale market development for Constellation Energy.

“This is not acceptable to continue on the path that we’re on,” she said. “I’d like to note that this tie in is not just energy and uplift … but also net CONE.”

Members Committee

Stakeholders Endorse Changes to MC Webinar Scope

The MC endorsed reducing the number of reports delivered to the committee via the webinars held between its face-to-face meetings.

The revisions to Manual 34 were advanced by Calpine and seconded by Vistra in an effort to move substantive discussions to venues that are attended by a wider spectrum of PJM’s membership. (See “Manual Revisions Seek to Reimagine Role of MC Webinar,” PJM MRC/MC Briefs: Feb. 20, 2025.)

Vistra’s Heinle said the March 17 webinar included a fervent discussion about how load bids in the day-ahead market. He argued it would have been beneficial for more participants to be involved.

The language also shifts PJM’s regulatory, system and market operations reports to the MC, along with reports delivered by the Monitor and the Organization of PJM States Inc. Interregional coordination reports would be moved to the MIC.

The changes also would move the timing of the webinars to be held on the week following MC meetings, with the possibility of it being canceled if there is little to discuss. Currently it is held on the Monday before the committee meets.

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NERC Selects Berkshire’s Michael Ball as E-ISAC CEO

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. 

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PJM Presents Settlement on Site Control Requirements

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. 

Donnie Bielak, PJM | © RTO Insider

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. 

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New England Officials Discuss Tx Oversight and Rising Energy Costs

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.”

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IEA: Extreme Weather Adds 20% to Increase in Electricity Demand in 2024

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.” 

“CO2 emissions 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.  

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BPA Workshop Leaves Little Room to Probe Markets+ Decision

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.

Ashley Donahoo, BPA | © RTO Insider

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.

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SPP Study: $88B to $263B in Generation Needed by 2050

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. 

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ERO Says 2024 Cyber Incidents Showed Increased ‘Sophistication’

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.