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April 25, 2025

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Texas PUC Approves 765-kV Transmission Option for Permian Basin

In what is being labeled a “landmark” and “historic” decision by the industry, the Texas Public Utility Commission approved a plan April 24 that allows ERCOT to authorize the region’s first extra-high-voltage transmission lines and meet the petroleum-rich Permian Basin’s rapidly growing power needs. 

The PUC unanimously endorsed staff’s recommendation to construct three 765-kV import paths into the Permian Basin, where oil and gas electrification and data center announcements have significantly increased load projections. The 765-kV option, while 22% more expensive than the 345-kV option, will carry more than twice the voltage of existing infrastructure. (See PUC Staff Urges Approval of 765-kV Lines to West Texas.) 

ERCOT and the transmission service providers (TSPs) have said the 765-kV lines can carry more power and meet higher demand levels as the state continues to grow. They can reduce congestion on existing transmission lines and could save money in the long term by eliminating the need to build additional lines. 

The TSPs have been preparing certificates of convenience and necessity applications for the projects approved in the plan. “Now that the voltage decision [has been] made, they can begin filing those applications to get the process started,” spokesperson Ellie Breed said in an email. 

“Our priority now is ensuring utilities execute these projects quickly and at the lowest possible cost to Texas consumers,” PUC Chair Thomas Gleeson said in a statement. 

Staff said the current options have increased to $10.11 billion for 765 kV and $8.28 billion for 345 kV. 

“This is really exciting for Texas, when you look back on monumental decisions that affect Texas,” Commissioner Kathleen Jackson said during the open meeting. “This will fit in those benchmarks, and we will look back and say this was one of those decisions.” 

The PUC’s decision came after a monthslong review process that included three public workshops and three rounds of stakeholder feedback. Commission staff conducted a full analysis of the costs, equipment supply chains and project-completion timelines for both voltage options, gathering input from the public, equipment manufacturers and the transmission companies that will build and operate the new lines. 

The commission’s order does not apply to ERCOT’s plans to add an EHV backbone to the rest of its system. The grid operator said it will work with the PUC and stakeholders to include the higher voltage in its study process. 

ERCOT included a 765-study as part of its annual Regional Transmission Plan (55718). (See 765-kV Lines in West Texas Inch Closer to Reality.) 

The Texas Advanced Energy Business Alliance (TAEBA) applauded the PUC’s decision, saying in an email the “historic vote” ushers in a “new era of grid modernization for the Lone Star State.” 

“This decision brings ERCOT into the 21st century,” TAEBA Executive Director Matthew Boms said. “As electricity demand surges, we need a grid that’s built for the future — reliable, efficient and cost-effective. Today’s vote is a strong step toward that goal.” 

American Electric Power trumpeted the fact that its Texas subsidiary will build one of the three import paths into the Permian Basin as part of a jointly assigned project. The 300-mile line will run from Fort Stockton to San Antonio. 

AEP energized its first 765-kV operational transmission line in 1969 between Kentucky and Ohio. It now owns 2,110 miles of 765-kV facilities, more than any other system in North America, it said. 

The commission also endorsed a petition approving assignments to the TSPs to own, construct and operate the Permian Basin projects (57441). 

“I want to further clarify the commission is not deciding in this proceeding any requirement for a TSP’s CCN,” Gleeson said. “Those will be decided in the future.” 

At the PUC’s direction, ERCOT filed its reliability plan for the Permian Basin in July 2024. The plan included the 345- and 765-kV import paths and a 2038 need date. The commission approved the plan in October 2024 but reserved a decision on the voltage level by May. (See Texas PUC Approves Permian Reliability Plan.) 

4 Projects Added to TEF

The PUC approved staff’s recommendation to advance four generation projects, totaling more than 1,900 MW of capacity, to the Texas Energy Fund’s due diligence review. 

The low-interest loan program, designed to add 10 GW in gas generation, has seen eight projects drop out or be removed in recent months (56896). (See 2 More Projects Fall out of TEF Loan Program.) 

The projects belong to independent power producers Invenergy and Nightpeak Energy. Invenergy proposed two projects totaling 1,369 MW of capacity, and Nightpeak has applied for loans to cover 565 MW. That raises the TEF In-ERCOT Program portfolio to 18 projects, promising 9,218 MW and requesting $5.04 billion in loans. Texas lawmakers have already set aside $5 billion for the program. 

“These are taxpayer dollars, and this is our program. We set the rules, and at the end of the day, you have to have the ability to repay, and you have to have the ability to execute,” Gleeson said. “Inherent in getting public funds is a trust from the public that they’ll be spent correctly, and I think our due diligence process is helping to ensure that.” 

The commission also approved the first recipient of the TEF’s Completion Bonus Grant Program, which awards grants to companies that add at least 100 MW to the ERCOT grid through new construction or by expanding dispatchable generators that meet the TEF’s requirements. 

The Lower Colorado River Authority is seeking $22.5 million in loans to help build the first of two 188-MW gas-fired units at its Timmerman Power Plant. The PUC can award LCRA a maximum of $120,000/MW (up to $22.5 million) if the unit connects to ERCOT before June 1, 2026. The facility will be tracked annually for 10 years and must meet specific performance and reliability measures and is available to ERCOT dispatch. 

The unit is scheduled to reach commercial operations in 2025. 

“It’s just good to see LCRA coming forward and taking advantage of this,” Jackson said. “It’s 10 years of oversight and performance, incentivizing them to be able to get the full grant.” 

Braunig RMR Work Delayed

ERCOT staff told the commission that a crack in Braunig Unit 3’s boiler superheater header will require that the header be replaced, “significantly extending” the unit’s potential return to service as late as spring 2026 (55999). 

CPS Energy found the crack during its maintenance outage, which began March 3 as part of the unit’s reliability must-run agreement with ERCOT. The San Antonio municipality announced in 2024 it would be retiring the 55-year-old gas unit along with Braunig’s other two units, but the Texas grid operator said it was still needed for reliability reasons. (See “RMR Contract for CPS Energy Unit Faces Increased Costs, Delays,” ERCOT Board of Directors Briefs: April 7-8, 2025.) 

David Kezell, ERCOT’s director of weatherization and inspection, said a new super heater will have to be built specifically for Braunig 3. Ideally, he said, the unit could be operational for the 2025/26 winter. The superheater is expected to cost about $3 million.  

“The budget is in reasonable shape,” Kezell said. ERCOT and the market already are on the hook for $45.85 million under the terms of Braunig 3’s RMR. 

Kristi Hobbs, vice president of system planning and weatherization, said ERCOT conducted another analysis to determine whether to proceed with the investment in Braunig. Staff updated their models with load growth and generation studies since their previous study and came to the same result. 

“We found that even with a delay, even if it’s delayed into February of next year, there is still more benefit than cost to moving forward with maintaining the Braunig unit,” Hobbs said. “We see the potential benefit really comes next summer in the July and August time frame … so we still see that benefit of moving forward with the work.” 

ERCOT counsel Nathan Bigbee told the PUC that ERCOT had reached an agreement with LifeCycle Power, which owns 15 mobile generators that it has leased to CenterPoint Energy, and is proceeding with plans to move the units to San Antonio over the summer. He said cooperation is still needed between CenterPoint and CPS to “make this all work.” 

“Having a fundamental structure in place for ERCOT and the LifeCycle arrangement will help facilitate those agreements as well,” Bigbee said. “This is not like anything else we’ve had before. We are leveraging the RMR framework for the dispatch, the settlement and the performance metrics for these generators.” 

The generators, which can produce nearly 40 MW apiece, will be moved to San Antonio in groups of three. They will then be connected in strategic sites to the CPS distribution network. 

In other actions that the PUC crammed into just over an hour before adjourning, the commissioners: 

    • sided with staff’s recommendation to delay the first procurement for the proposed firm fuel supply service (FFSS) until the 2026/27 winter season. The generation service is still going through ERCOT’s stakeholder process; staff were also leery of “competing interests” coming out of the Texas Legislature, which ends in early June (56000).
    • approved a joint application by CPS and South Texas Electric Cooperative for certificates of convenience and necessity for a proposed 345-kV project south of San Antonio. The PUC modified the proposed order by changing the project’s route, which is estimated to cost between $274 million and $390 million. The project is one of several that are part of the San Antonio South Reliability Project addressing a transmission constraint that led to the Braunig RMR. It will be built and owned 50/50 by CPS and STEC (57115).
    • accepted CenterPoint’s request to recover more than $400 million in restoration costs from a series of storms in May 2024. The PUC approved $28.9 million in restoration costs and an additional $396.3 million in expenses to be securitized (57271). (See Texas Public Utility Commission Briefs: May 23, 2024.)
    • agreed to AEP Texas’ $318 million, three-year system reliability plan that the company says will save about $71 million in projected restoration costs. About 80% of the plan involves replacing aging infrastructure with newer equipment designed to a higher standard that can better withstand extreme weather events, AEP said (57057).
    • welcomed the city of Caldwell, between Houston and Austin, into the ERCOT system by approving an order integrating its 14 MW of load from MISO. The city reached an unopposed agreement with PUC staff, LCRA Transmission Services, Entergy Texas and the Office of Public Utility Counsel. ERCOT did not oppose the settlement (56164).
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Stakeholders, NERC Respond to FERC Large Loads Investigation

NERC joined a wide range of industry stakeholders responding to FERC’s investigation of co-located large loads and their effect on grid reliability and costs for customers, while other stakeholders provided feedback on PJM’s suggested approaches to co-location (EL25-49, AD24-11).

FERC launched the inquiry in February after rejecting an agreement the previous November between Amazon Web Services and Talen Energy to expand a data center co-located with the Susquehanna nuclear plant in Pennsylvania by modifying the generator’s interconnection service agreement to reduce its output to PJM. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.)

Along with ordering PJM and its transmission owners to determine whether the RTO’s tariff needed updates to accommodate the arrangements, the commission also sought comments on the larger issues. FERC is concerned that the arrangements could be developed in a way that is not fair for other customers, and that co-location could cause issues for reliability and resource adequacy similar to an event in July 2024 in which a transmission line fault in Virginia led to 1,500 MW of load reduction, all from data centers. (See NERC Report Highlights Data Center Load Loss Issues.)

In its comments, NERC highlighted the ERO’s efforts to address the reliability challenges of co-located large loads. The organization cited its report on the 2024 event as well as its creation of the Large Loads Task Force (LLTF) in August 2024. Reporting to the Reliability and Security Technical Committee, the LLTF has a goal of creating two white papers and one reliability guideline before June 2026 on the identification and mitigation of risks, along with guidance for “improvements in modeling, analyses, coordination and data collection, real-time monitoring and event analysis.”

Discussing the recent testimony of NERC Chief Engineer Mark Lauby at FERC’s April open meeting, where topics included the 2024 incident as well as similar events in Virginia and Texas, NERC observed that co-located large loads may provide benefits to reliability as well as risks. The presentation was attached to NERC’s filing as an appendix.

“Proximity between large loads and power generation sources can reduce energy loss while improving transmission reliability [and fostering] improved coordination, leading to better load management and reduced strain on the” grid, NERC said. “Grid stability may also be enhanced if the proximity created flexibility to adjust demand during critical conditions.”

The ERO’s filing also mentioned the risks posed by co-location, such as the possibility that system operators may not have visibility into a co-located large load, leaving them unable to perform reliability analysis. This could lead to “risk of thermal overloads and voltage or stability issues.” Large loads can also experience fluctuations during faults or switching that operators may not be able to anticipate.

NERC noted that its Board of Trustees solicited input from the Member Representatives Committee and industry stakeholders ahead of a panel on large loads at its February meeting. In response to the panel discussion and input, the board directed NERC to develop an action plan to identify and address the risks of large loads. This action plan will be due at the board’s next meeting May 8.

Other respondents shared NERC’s reliability concerns. Consumers’ Research, a nonprofit consumer advocacy group, cited NERC’s 2025 Long-Term Reliability Assessment, which said many parts of North America could face resource adequacy challenges in the next 10 years, along with FERC Chair Mark Christie’s warnings that “America is facing a reliability crisis driven by the dangerous pace of retirements of dispatchable generation units.”

The group urged FERC to ensure that co-location is accomplished without exaggerating these reliability issues. Measures to achieve this goal could include requiring the parties involved to maintain a reserve capacity of dispatchable power for ratepayers, and that they “have no targets or commitments for net zero or any related low-carbon goals.” CR said such commitments “harm consumers by artificially weakening the market for dispatchable power.”

A joint comment by Suzanne Glatz of Glatz Energy Consulting and Abraham Silverman, a research scholar at Johns Hopkins University, referred to NERC’s 2023 Reliability Risk Priorities Report, which warned that “new loads,” including data centers, cryptocurrency mining and artificial intelligence, “can emerge and grow faster than generation and transmission can be built.” They suggested that FERC “strongly consider a co-location ‘safety valve’ that ensures that co-location does not drive PJM into shortage conditions.”

Modifications Suggested to PJM’s Approaches

PJM filed its initial response to FERC’s investigation in March, laying out three approaches to co-locating load already permissible under the RTO’s tariff and outlining five more that could be developed under more possible configurations or limitations imposed by state laws.

Multiple stakeholders responded to PJM’s comments with their own takes on the RTO’s plans, or on the theme of co-location in general. The Data Center Coalition commented that co-located load configurations can allow large consumers to avoid long interconnection delays by not relying on congested transmission infrastructure. It argued that many of the issues raised around co-location are more related to tightening capacity supply and demand.

“Co-location can reduce transmission congestion, avoid costly infrastructure buildouts and enable the more efficient interconnection of new resources. But amid tightening margins, it has become a stand-in for deeper anxiety about supply adequacy and planning accuracy,” the coalition wrote.

It requested that the commission initiate settlement judge proceedings to allow for more thorough discussions and stay the investigation for 90 days. It also recommended that PJM make several changes to its load forecasting, including verifying the commercial readiness of large load additions and increasing transparency to ensure that such additions do not create reliability issues.

Constellation Energy argued that requiring data centers to be classified as network load in front of generators’ meters has led to interconnections taking years to complete and has exposed data centers to moratoriums on new load interconnections, as seen in Ohio. While many consumers will prefer the reliability offered by PJM in exchange for being subject to transmission charges, the company said many are willing to forgo the reliability of full grid service in exchange for speedier interconnection.

In some cases, Constellation said, those customers might be willing to accept backup service from the grid once network upgrades have been completed.

Responding to several paradigms PJM laid out for the commission to explore in the RTO’s comments, Constellation said it is opposed to the “bring your own generation” route, which would prioritize generation interconnections part of a co-located load configuration. The company argued that would discriminate against existing generation and undermine capacity market incentives.

Under options in which the load is behind the generator’s meter, Constellation said it may be appropriate for it to pay some ancillary services, such as regulation and black start, but subjecting the load to network integration transmission service charges would require it to use services it would not otherwise. (See PJM Responds to FERC Co-located Load Investigation.)

The company asked the commission to either accept modified variants of the co-located options proposed by PJM or initiate a time-limited settlement judge proceeding to consider alternatives.

PJM stressed in its March filing that while the options it presented are routes the commission could explore, it does not view them all as equal or feasible. It was particularly skeptical of two configurations exempting co-located load from transmission charges when protective mechanisms have been installed to prevent the load from receiving energy from the grid. Such mechanisms could fail, the RTO wrote, and the load would nonetheless continue to consume ancillary services, such as regulation.

Echoing the Data Center Coalition, Constellation said co-located load is being blamed for broader issues with PJM’s capacity market and generation interconnection process. It said the RTO’s Reliability Resource Initiative bolsters resource adequacy by adding 50 projects to the next queue cycle that can quickly bring capacity to market, and further improvements can also be made to the interconnection study process.

“The commission should determine whether there are additional tools to address near-term capacity needs while reinforcing PJM’s capacity market, which is already sending strong signals for new entry (or for delaying retirement of existing resources),” it wrote.

Constellation encouraged the commission to establish a flexible set of rules for developers to follow when pursuing co-located configurations, saying there are many ways that load and generation can be combined.

“Allowing load to select a configuration that best serves its needs will enhance national security and national economic competitiveness by speeding connection for those new customers who need to connect quickly and will save existing customers money by minimizing system upgrades,” the company wrote.

Generation developer BrightNight said the commission should establish a pro forma agreement and process for co-located configurations that allows flexibility for the three configurations that may be pursued: fully islanded generation and load; flexible load or demand response; and load that may rely on the grid for backup service when on-site generation is unavailable.

“Data center developers, generation developers and system planners cannot make long-term decisions without understanding what co-location arrangements the commission will accept,” BrightNight wrote. “Standardizing procedures and agreements would give developers and planners certainty, reduce opportunities for undue discrimination or preference, reduce disputes and, hopefully, expedite the development of data centers and needed generation.”

Public Interest Organizations Warn of Consumer Costs

Several public interest organizations jointly argued that certain co-location configurations could push network upgrade costs to consumers and cause reliability issues if they fall through cracks in PJM’s load forecasting.

The comments were signed by Appalachian Voices, Clean Air Task Force, Earthjustice, the Environmental Defense Fund, PennFuture and the Sierra Club.

They wrote that the three processes PJM uses to identify transmission violations prompted by co-located configurations — necessary studies, TO load integration studies and the Regional Transmission Expansion Plan — fail to take a holistic look at projects’ impacts. The necessary studies exclusively look at changes to the generator’s interconnection service agreement, while the latter two assign any identified upgrades to network load.

They also highlighted that PJM has not allowed batteries to go through the necessary studies process because the charging cycle can act like load, but the RTO has proposed to apply it to co-located configurations.

The organizations wrote that accelerated data center load is expected to cause wholesale costs to rise significantly, and co-located load configurations sought by developers would further shift costs to consumers. They also argued it could create opportunities for generators to engage in market power manipulation by withholding capacity from PJM to supply co-located load.

“The commission cannot ignore the current realities in PJM: already sky-high capacity prices, as well as an extremely backlogged interconnection queue, supply chain issues for new resources (both generation and transmission) and limited available transmission capacity that further drives up the cost of interconnection,” they wrote.

“Each of these conditions makes new entry challenging, and if left unaddressed, very expensive. Allowing the key drivers of the tight supply margins — large load customers — to avoid and exacerbate these challenges and associated costs by sequestering access to existing generation would be a cost shift of extreme magnitude.”

TOs, cooperatives and municipal providers opposed changes to PJM’s tariff, jointly commenting that existing processes may not be preferable for co-located configurations, but they are not discriminatory or unjust and unreasonable and therefore changes cannot be compelled by FERC using a Federal Power Act Section 206 investigation. The comments were submitted by Exelon; American Electric Power; the city of Hamilton, Ohio; Southern Maryland Electric Cooperative; Duke Energy; and Dominion Energy, among others.

“Those end-use load connection processes, governed by the states and fully consistent with the PJM tariff, are available to all, and those processes work. Moreover, the transmission service provided to co-located load under the PJM tariff is available to all on a non-discriminatory basis,” they wrote. “Nowhere in the record is there an allegation —let alone evidence — that the current PJM tariff impedes the development of or service to any load, co-located or otherwise.”

They also argued that co-located configurations should be prohibited from being classified as behind-the-meter generation, citing PJM’s statements that the ruleset was designed for smaller configurations and the load would not be properly measured by the RTO, even though it uses the transmission system.

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Gas Soars, Wind Slumps for GE Vernova

GE Vernova’s gas turbine sales pipeline grew 39% and its onshore wind orders dropped 42% in the first quarter of 2025 amid sweeping changes in the U.S. energy landscape. 

The company reported solid financials April 23 and provided details on its business segments. 

Natural gas again was a focus as CEO Scott Strazik spoke to financial analysts on a conference call. 

In the first quarter, GE Vernova booked 7 GW of orders and 7 GW of slot reservations that are expected to convert to orders, bringing the total gas turbine pipeline to 50 GW. 

Strazik said GE Vernova expects to ship 10 GW worth of gas turbines and take orders for 20 GW through the remainder of 2025, ending the year with a 60-GW backlog that will book up production capacity through 2028. 

Already, the company is signing agreements for gas turbines to be delivered in 2029, setting the stage for infrastructure investments that will shape the power sector for decades. 

A day after the earnings report, GE Vernova and Duke Energy announced agreement on a purchase of up to 11 of GE Vernova’s 7HA gas turbines — in addition to the eight recently secured. 

Meanwhile, the company continues to wind down its exposure to offshore wind, fulfilling its two remaining commitments — turbines for the Dogger Bank and Vineyard Wind projects — and recording a $70 million loss on termination of the last of the supply agreements for the 18-GW offshore turbine it decided not to bring to market. 

The company’s wind sector reported a net loss. Individually, onshore wind delivered its fifth straight profitable quarter. New orders were 43% lower than in the first quarter of 2024, however. 

“We remain cautious on the timing of an onshore order inflection in North America as customers continue to navigate growing interconnection queues, policy uncertainty and higher interest rates,” CFO Ken Parks said. 

The numbers reported April 23 reflect the rapid and sizable shift in energy priorities that came with the transition from President Biden to President Trump. 

“I continue to see this market normalizing to a higher-for-longer gas market,” Strazik said. “The world needs more dispatchable power generation to support economic growth and national security. Gas power will provide a significant amount of the incremental dispatchable power while also being the force multiplier for more renewables where wind and solar resources make sense.” 

Strazik drilled down a bit on the 50 GW of turbine orders and slot reservations: About 60% of them are from the United States, but the more recent ones are more heavily in the United States and more heavily associated with data centers. 

He said the 29 GW backlog is firm but there was more chance of fluctuation within the 21 GW of slot reservations, despite the large deposits that accompany them. “I see very little quote, unquote, cancellation risk, but there will be some movement that our supply chain will have to be nimble with, as the slot reservation agreements turn to orders and final dates get finalized.” 

An analyst asked for further insight about onshore wind, historically a strong U.S. market for corporate predecessor General Electric. 

Strazik said GE Vernova is highly confident in securing market share when onshore wind begins to rebound, but does not know when that inflection point will come, and when the 200 GW-plus of U.S. onshore wind projects in early stage development start to move forward. 

“We continue to see there be an important role for wind to play, but we need to see progress on permitting,” he said. “I think there is a real question on the price embedded in those projects that are in the interconnect queue. Where are the tax incentives going? I think clarity on permitting process today and ultimately incentives [is] going to be important in … those projects getting to closure.” 

GE Vernova projected solid financial performance for 2025 but acknowledged the moving pieces that could impact its bottom line. 

“While our end markets remain strong, we are not immune to the complexity of play, given the current outline of tariffs and resulting inflation,” Strazik said. “We do expect our cost to go up $300 [million] to $400 million in 2025.” 

GE Vernova reported net income of $264 million, or $0.91 per share, on total revenue of $8.03 billion for the first quarter of 2025, compared with a net loss of $106 million or $0.47 per share, on revenue of $7.26 billion in the same quarter of 2024. 

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Firm Fuel Proposal Continues to Confuse NYISO Stakeholders

NYISO returned to the Installed Capacity Working Group with more modifications to the tariff language and general structure of its firm fuel capacity accreditation proposal, though based on the conversation at the meeting April 21, stakeholders are still skeptical of it.

The ISO made the changes in response to the criticism it received from stakeholders, including the Market Monitoring Unit. (See NYISO’s Firm Fuel Proposal Criticized.)

But stakeholders peppered staff with hypothetical questions about how penalties and FERC referrals would be triggered and when. There were several times throughout the meeting that attendees asked for others to slow down so that they could follow their line of questioning.

The firm fuel capacity accreditation project is an effort to incentivize generators to secure firm fuel contracts with their suppliers before winter, when the ISO and the New York State Reliability Council are worried about fuel shortages.

Generators wishing to elect as firm would commit to being able to run for 56 hours over any consecutive seven-day period in December through February. They would declare Aug. 1 of the prior capability year that they are opting to be firm. Failure to perform because of lack of fuel would result in a financial sanction. (See NYISO Business Issues Committee OKs Firm Fuel Accreditation Concept.)

Nikolai Tubbs, associate market design specialist for NYISO, explained the adjustments to the structure of the penalties, while Zachary Smith, senior manager of capacity and new resource integration market solutions, fielded questions from stakeholders.

For any given “winter performance month,” the financial sanction would be assessed at a 1.5 multiplier if the reason for failure was within the generator’s control. Generators would lose their firm fuel accreditation (i.e., adjusted down to non-firm) via the “settlement adjustment modifier” if failures occurred outside of the generator’s control, or if the generator failed to have an operating plan or fuel contract in place for the whole month.

Generators would be required to notify NYISO by Dec. 1 if they were unable to secure firm fuel contracts. If something goes wrong during the winter, such as a fuel contract getting canceled, the generator is also obligated to inform the ISO. This reverts their status to “non-firm” by applying the settlement adjustment modifier.

If NYISO learned that a generator failed to provide the required notice, the generator would be subject to the sanction with the 1.5 modifier and be referred to FERC. The ISO would also report to FERC if a generator supplied operating plans or fuel contracts that were “false or misleading.”

In response to a question about what would happen if a generator had no contracts by Dec. 1 but did for January and February, Smith said that it would get the settlement adjustment (be compensated as non-firm) for all three months.

“There’s no ability to cure,” Smith said. “You potentially have the worse multiplier if you also fail to perform. If you have the contracts in place for December and January, but they are not in place for February, only February gets the settlement adjustment absent any of the other failures to perform.”

Doreen Saia, a stakeholder representing generator interests, said that this implied that a failure in December would cause a settlement adjustment no matter what, but a generator might want to have contracts in place because if it didn’t, it would get hit with the worse financial sanction if it failed to perform.

“I think part of the problem is that this has been through so many iterations at this point that it would be a small miracle if the tariff said anything cogently or coherently,” Saia said.

The conversation turned toward hashing out when NYISO would refer a generator to FERC. Smith explained that after a failure to perform, the ISO had the ability to ask to review a generator’s contracts and plans, but that it might not always do so.

“If the entire gas system went out, I don’t think we’d need to get to reviewing your contracts,” Smith said as an example. “At that point it clearly didn’t matter what your contract said.”

But in other cases, Smith said NYISO would need to open an investigation into whether the failure to perform was in the generator’s control. Even in the case of an investigation, Smith would not state that the ISO would need to review contracts or plans in all cases. The ISO was reserving the right to look into plans and contracts in the event of a failure to perform.

“The NYISO is not making a judgment call on anyone’s plans, to whether or not they should have a penalty apply, absent a failure to perform,” Smith said. After some further discussion, Smith said NYISO did not want to be in the position of approving people’s operating plans; it just wanted to audit plans if there was a concern.

“There’s a lot of ‘ifs’ and ‘thens’ here,” one stakeholder said at one point during the meeting. “Might I suggest you put this into a flow chart?”

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SPP Stakeholders Open Discussion on Affordability

HOUSTON — SPP staff have opened a discussion into affordability and the grid operator’s proposed regionwide approach to improve decision-making and keep affordability as a key focus of the business strategy. 

To that end, CFO David Kelley shared with the Strategic Planning Committee a draft definition of affordability that defines it as the ongoing pursuit of “delivering regional solutions at a cost that balances near-term financial impacts with long-term economic sustainability” in SPP’s footprint. 

He said during the SPC’s April 16 meeting that the definition is supported by a model that incorporates transparency, proactive planning and stakeholder-driven decision-making to ensure costs and benefits are well understood and balanced over time. 

Kelley invited the SPC’s membership to meet with him and help refine the affordability model. Several were quick to respond during the meeting. They offered their initial thoughts on FERC’s efforts to place affordability on equal footing with reliability, clarifying the definition of affordability to ensure it’s easily understood, including regulators in the discussion, emphasizing the affordability of connecting in this region and defining where the committee will draw the line on affordability. 

“It’s very clear that FERC has put affordability on the same level as reliability. The previous FERC chairman made that very, very clear, and the current chair has not changed that view,” Golden Spread Electric Cooperative’s Mike Wise said. “So my encouragement is to keep affordability and reliability in the same sentence and the same focus, same level of concern.” 

“A lot of this looks through the lens of retail rates. That’s actually complicated, and like all of us in this room, we will use consumer costs to support a point,” said David Mindham, with EDP Renewables. “We’ve got to be careful that we’re not using this to support our business interests, as opposed to the customers’ interest.” 

Kelley said the genesis was the Finance Committee making it “abundantly clear” how important affordability was in presenting the budget, his first after being promoted to CFO. 

“This is intended to be something that is regional in nature. We as a regional organization, how would we view affordability, recognizing that every member in this room, and all 116 or 118 members that we have, would have their own unique view of affordability?” he asked rhetorically. “What is the lens that we will view the things that we’re bringing forward, whether it’s transmission, expansion plans or proposed changes to the [planning reserve margin] or changes to revolutionize our market? How are we viewing those things in terms of affordability?” 

The conversation continued into the next agenda item, a discussion of short-term reliability projects (STRP) that was facilitated by board member Irene Dimitry. She said the number, size and cost of the projects have grown tremendously, triggering a need to rethink the board’s treatment of these projects and how to make more informed STRP decisions. 

CEO Lanny Nickell clarified that a 30-day comment period was to gather SPC members’ feedback on proposed considerations and not whether STRPs should continue to be assigned to incumbent transmission owners or put out for competitive bids. 

“Personally, I believe this issue falls squarely in the reliability and affordability balance that we just talked about, and it sits squarely with the board,” board Chair and SPC Chair John Cupparo said after the discussion closed. “We didn’t ask for that responsibility, but we got it as part of [FERC’s] Order 1000 process. If the $3.2 billion [of STRPs] that we just approved in February was a one-time event, you might be able to justify leaving everything as is.  

“But it appears the 2025 ITP may be as big, if not bigger, and we don’t know what 2026 looks like. From my perspective, if this is a regular occurrence, we as a board have an obligation to define what safeguards mean and how we plan to execute that role.” 

SPP Waits on Executive Orders

Kelley told the committee members interested in the grid operator’s perspective on the Trump administration’s energy executive orders issued April 8 will have to wait until the SPC meets virtually in July or holds a special meeting. 

“[That] flurry of orders did just come out last week, and we are still looking into them and evaluating potential implications,” he said. “I can commit to you that once our team has gone through them and developed an approach for how we might want to engage with any elected officials or otherwise and we need to inform the SPC of what our plans and intentions are or get feedback from you, we will schedule some time. 

“We understand the SPC’s role in these types of activities.” 

He said members should direct any feedback or specific requests to Kevin Bryant, the RTO’s first executive vice president of stakeholder affairs and chief strategy officer, who goes by “KB.” Bryant’s team is coordinating the executive order review and will facilitate the committee’s future conversations on the EOs. 

SPC Scope Changes Add Members

The SPC endorsed revisions to its scope that include increasing its membership from 14 to as many as 29, matching the Members Committee’s sector representation. The MC participates in board meetings and provides advisory votes to the directors. 

The sectors will select their representatives to fill the 14 vacant seats, following SPP’s normal processes. The board also can add one of its members to the SPC. The Corporate Governance Committee and the board will review and approve the selections. Current members will not be affected. 

Kelly said the scope changes reflect SPC’s new focus on ensuring that “we’re staying on the forefront of the pace of change that is happening with our industry and certainly, the things that are affecting SPP,” as determined by members’ feedback. 

The CGC also will consider the changes and make a recommendation to the board. The directors will select the nominees in August. 

The nominations have been submitted, but two sectors (the Independent Power Producer/Marketer and the State Power Agency) have more candidates than open seats and will have to settle on their final slate. 

SPP Releases FERNS Report

A planned presentation and discussion of Brattle Group’s Future Energy Resource Needs Study (FERNS) was rescheduled for the July SPC meeting, but the report itself already has been published. 

Among its findings, the report predicts renewable generation will grow “significantly,” even without federal tax credits or other clean energy policies. Brattle said because of renewable energy’s abundant availability in the SPP footprint and declining technology costs, carbon-free generation’s share could reach about 90% by 2050. It predicts the RTO will serve growing loads “reliably and affordably” through a combination of fossil-fueled generation, wind, solar, nuclear, hydro and battery storage resources. 

Engineering Vice President Casey Cathey said the study was aggressive in 2023 and that SPP already has surpassed the study assumptions.  

SPC members also approved transitioning the Future Grid Strategy Advisory Group to the Grid Transformation Advisory Group, advising and reporting to the SPC. It will continue as an advisory group, reporting directly to the SPC, and collaborate with other groups and staff while focusing on developing ideas that bring long-term strategic advantage. 

Mike Skelly Lunches with SPC

Renewable energy entrepreneur Mike Skelly, escorted by board member Stuart Solomon, crashed the SPC’s pre-meeting lunch. He then looked on as the meeting began. 

“I heard there was a lunch here,” he explained to an SPP stakeholder inquiring about his presence. 

Skelly attended the Gulf Coast Power Association’s spring conference in the morning before making the seven-block trek to the SPC’s hotel.  

“How could you tell? Was it because of this?” he said to RTO Insider, flipping his brightly colored tie. 

Skelly grew Horizon Wind Energy, now part of EDP Renewables North America, and founded Clean Line Energy. Clean Line went under in 2017 in the face of legal, political and bureaucratic obstacles. Skelly since has co-founded Grid United, where he is the CEO. 

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Consumer Groups Invoke DOJ Stance in Stalled Complaint on ROFRs in MISO Planning

A collective of consumer groups has invoked a recent letter from the U.S. Department of Justice to get FERC to act on its three-year-old complaint against MISO for deferring to state right of first refusal laws in regional planning.

The complaint — from the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers and others — asks FERC to force MISO to brush off state ROFRs when planning transmission (EL22-78). FERC has yet to address it. (See Consumer Collective Again Asks FERC to Strike ROFR Laws from MISO Planning.)

In mid-April, Paul Cicio of Industrial Energy Consumers of America entered a letter into the record from the DOJ to Iowa State Sen. Jesse Green (R), urging the Iowa Legislature to rethink a reintroduction of the state’s ROFR law that was overturned in 2023. (See Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.)

Iowa legislators in early 2025 reintroduced an Iowa ROFR bill in the Senate (SB 1113).

The collection of consumer groups challenging MISO’s regard for ROFRs in planning has said Iowa provides a case study in the delay and litigation that ROFR laws introduced. It argues MISO should be able to disregard them.

The March letter from Assistant Attorney General Abigail Slater calls competition a “core organizing principle of the American economy” and said ROFRs’ bypass of competitive bidding disadvantages firms “that could offer lower prices, greater innovation and superior terms to Iowa’s utility customers.”

Slater reminded the Iowa Legislature that President Donald Trump declared a National Energy Emergency in early 2025 and that the DOJ has filed briefs in other cases that challenge the constitutionality of state ROFR laws.

“The bill turns a ‘preference for further investment in Iowa transmission infrastructure by electric transmission owners’ into a legal grant that shields incumbents from competition,” the letter said. “In some cases, incumbent operators will be best positioned to deliver high quality, cost-effective infrastructure projects quickly. But even in such circumstances the threat of competitive pressure from potential rivals will incentivize better outcomes like lower prices for consumers and more robust and innovative project designs. In other cases, non-incumbent firms may offer lower costs, and better project designs, and they should be allowed to compete on the basis of the better value they offer.”

MISO: Complaint Still Has No Legs

MISO, as it has for years, continues to oppose the complaint. In an early April response, it said the consumer alliance’s attempt to cut the state ROFR exemption from its tariff is a collateral attack on MISO’s accepted compliance under FERC’s Order 1000.

MISO in 2022 assigned several projects from its first, $10.4-billion long-range transmission plan (LRTP) portfolio to incumbent transmission owners in Iowa based on the valid state ROFR in place in Iowa at the time. The RTO pointed out that it wasn’t until early December 2023 that the Iowa District Court overturned the ROFR on a remand from the Iowa Supreme Court.

“MISO has been clear that, following the Iowa District Court’s decision on the merits, the Iowa ROFR law was no longer applicable, on a prospective basis,” the RTO said. It ended up using its variance analysis to examine project assignments in Iowa for the subsequent, $21.9 billion LRTP portfolio. MISO ultimately left that round of projects also to its incumbents, concluding the district court’s order did not change project assignments nor direct that projects be reclassified into competitive facilities. MISO also said the district court specifically said it was not a party to the court’s action.

“Far from indicating that the state ROFR exemption is unjust and unreasonable or otherwise unworkable, the tariff process worked in the Iowa case despite its complicated litigation posture and the attendant uncertainty,” MISO argued. “Further, to the extent the consumer alliance suggests that MISO must apply ROFR determinations retroactively for the state ROFR exemption to be just and reasonable, such a position lacks merit. The filed rate doctrine and the rule against retroactive ratemaking are clear that MISO cannot revisit such determinations without a binding legal directive from the commission, subject to the applicable FPA process.”

MISO acknowledged Indiana’s ROFR also is the target of fluid and complex litigation. (See 7th Circuit Lifts Injunction on Indiana ROFR, Remands LS Power’s Case.) The RTO said, so far, the ROFR has been in effect throughout the development of the second LRTP portfolio, and as such, it again assigned the lines to the incumbent transmission owners. It said it again would draw on a variance analysis to confirm project assignments in Indiana, if needed.

“MISO does not know what conclusion the federal courts ultimately will reach with respect to the constitutionality of the Indiana ROFR law. As the 7th Circuit recognized, there are many different unknowns at this time. … If the Indiana ROFR law is determined to be unconstitutional, MISO will give a prospective effect to any such determination, consistent with the filed rate doctrine and any directives from the commission,” MISO said.

The grid operator pushed back against the consumer alliance’s claims that MISO “default[s] to incumbent project assignment regardless of questions regarding the constitutionality of state laws.” It said it was simply applying its tariff as written.

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Oregon House Passes Bill to Shift Energy Costs onto Data Centers

The Oregon House of Representatives has approved a bill that would require data center developers to shoulder a larger share of their own energy costs in an effort to mitigate risk to smaller consumers. 

House Bill 3546, or the POWER Act, passed in a 41-16 vote on April 22. It empowers the Oregon Public Utility Commission to create a separate customer category for large energy users, such as data centers, and requires those users to pay a proportionate share of their infrastructure and energy costs. 

The legislation now moves to the state Senate. 

Rep. Pam Marsh (D), one of the bill’s chief sponsors, said the “explosion of huge technology facilities has upended” the traditional idea of distributing energy demand costs equally among consumers. 

“Since 2019, data center growth in [the Portland General Electric] territory has been equivalent to an increase of 400,000 residential customers, but residential demand has actually grown by only 63,000 people, or 24,000 customer accounts,” according to Marsh. “Without intervention, the cost created by the disproportionate demand of big energy users will be borne by residential and small business consumers who are already struggling.” 

The bill defines a large energy use facility as one that uses more than 20 MW. The law would apply only to Oregon’s investor-owned utilities. 

Additionally, under the bill, data centers must sign contracts for at least 10 years with energy companies to protect energy infrastructure investments. The contract requires the data center operators to pay for a minimum amount of energy based on the center’s expected energy usage during the contract period, and “[m]ay include a charge for excess demand that is in addition to the tariff schedule,” according to the bill. 

“If a utility is going to make investments to serve a large user, we need some assurances that those investments do not become a stranded asset that is essentially shifted to other ratepayers,” Marsh said. 

The bill also requires the Oregon PUC to provide the legislature with reports detailing trends in load requirements. 

Kandi Young, a spokesperson for the PUC, told RTO Insider that the commission “appreciates the legislature’s recognition of the challenges new large loads can present to utilities and their customers. The PUC already is working to help ensure that other electricity customers do not inappropriately pay for the costs to serve these large users of electricity and will work with stakeholders from all perspectives to implement additional policy direction on this issue should the bill be signed into law.” 

Pacific Power spokesperson Simon Gutierrez said the utility, a subsidiary of PacifiCorp, “supports HB 3546 as a meaningful framework to ensure continued economic growth with fairness for all customers.” 

“While the existing regulatory framework is established to protect customers and align the costs of energy infrastructure with the customers benefiting from these investments, the scale, pace and uncertainty surrounding this potential load growth [require] additional regulatory updates to protect all customers while creating a path for large customers to expand their businesses,” he said. 

Organizations like the Northwest Energy Coalition, BlueGreen Alliance and Sierra Club have supported the bill. 

‘Disparate Rate Treatment’

The bill also faced opposition. Republican Rep. Bobby Levy called it a “regulatory overreach.” 

Data centers are “legally operating businesses already regulated under existing PUC authority, and they provide critical infrastructure, jobs [and] economic development, especially in rural areas,” Levy said. “Under this bill, they would face entirely separate tariff schedules, new reporting burdens and regulatory uncertainty, not because they’ve done anything wrong but because they’ve grown and used power efficiently.” 

Writing in opposition to the bill in March, the Data Center Coalition, a membership association, said it “supports the underlying intent of HB 3546, and the data center industry is committed to paying its full cost of service.” 

But “no customer, industry or class should be singled out for differential or disparate rate treatment unless that approach is backed by verifiable cost-based reasoning,” DCC wrote. “Data centers are but one large end user of electric utilities and part of a larger portfolio of end users driving increased electricity demand. Any rate design that focuses on a single end use, without showing a measurable difference in service requirements or cost responsibility, risks creating unjustified distinctions among similar customers.” 

Shannon Kellogg, vice president of public policy at Amazon Web Services, which has been operating data centers in Eastern Oregon since 2011, provided neutral testimony, writing that “a significant bottleneck to bringing new carbon-free energy projects online is the interconnection process to the grid.” 

“To unlock these projects, it is important for transmission infrastructure and regional energy systems to modernize and expand quickly, and we are working closely with lawmakers and regulators to accelerate these changes,” Kellogg wrote. 

The proposed legislation comes as data center growth in Oregon has increased rapidly. The amount of data centers seeking service “is unprecedented,” according to an Oregon Citizens’ Utility Board presentation. 

In December 2024, WECC predicted that annual demand in the Western Interconnection would grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and double the 9.6% growth forecast in 2022 resource plans. (See West to See ‘Staggering’ Load Growth, WECC Report Says.) 

Similarly, the Pacific Northwest Utilities Conference Committee’s Northwest regional forecast for 2024 found that electricity demand would increase from about 23,700 average MW in 2024 to about 31,100 aMW in 2033, an increase of more than 30% in the next 10 years. 

In February, Washington Gov. Bob Ferguson directed three state agencies, electric utilities and other groups to collaborate in developing a report recommending policies for addressing with data center energy use. (See Wash. Governor Orders Study to Explore Data Center Impact.) 

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Texas RE Speaker Emphasizes Human Role in Security

Devin Ferris, the Texas Reliability Entity’s manager of critical infrastructure protection compliance monitoring, did not mince words in his briefing on cyber readiness at the regional entity’s Spring Standards, Security and Reliability Workshop on April 23.

“It’s important to understand what we’re up against. The threat landscape is changing; the speed at which it is changing, the volume the sophistication of those threats, is ever-increasing,” Ferris said. “Attackers are using [generative artificial intelligence], and that’s changing the game on certain things. These attackers are able to gain initial access quickly, weaponize whatever they’re doing, exploit it, and be out of there and cover their tracks.”

Despite his invocation of AI and other new technologies, Ferris emphasized that one of the biggest risks entities face is an old one: human error. But, he continued, this danger also represents an opportunity.

“You hear a lot in the security world [that] people are the weakest link in security,” Ferris said. “That could be true, but I truly believe if you shift your mindset on that, you could turn it on its head. You can create a culture of security, and they are going to be the strongest link in that.”

The theme of Ferris’ presentation was the risks posed by low-impact grid cyber systems, which NERC defines as systems not considered a significant risk to grid security. He told attendees that while some might assume these systems are low priority, Texas RE and the ERO in general have devoted considerable attention to them in recent years because “there’s a lot of growth in that space,” particularly with the rapid spread of internet-connected inverter-based resources “that are more than likely going to be low-impact.”

In his presentation, Ferris aimed to help utilities prepare for compliance audits of CIP-003-8 (Cybersecurity – security management controls). The standard requires entities to have “consistent and sustainable security management controls that establish responsibility and accountability to protect [high-, medium- and low-impact] cyber systems against compromise that could lead to misoperation or instability in the” grid.

Rather than give the bulk of his time to compliance, Ferris said he wanted listeners to think more about risks, saying that “if you mitigate these risks, you can effectively still … achieve compliance. It’s going to be a byproduct of that.”

For example, he noted that CIP-003-8 requires entities to permit only “necessary” inbound and outbound electronic access. With many new IBR facilities relying on remote connections, this requirement creates a challenge for utility staff.

“One of the risks that you have is if you haven’t identified what’s necessary, and you’re proactively looking to see if access is still needed on a periodic basis, you may not be able to address it, and so the compliance and risk overlap,” Ferris said. “And when you do these reviews, if you’re documenting what the justification … or your business need is, it’s going to help you make sure that only necessary rules are in place and that you still need them as access changes and you implement new technologies, or there’s different threats you’re trying to mitigate.”

He then returned to the theme of human error, noting that phishing and social engineering frequently are used by attackers to gain a foothold in a target system. Without knowledgeable, educated staff, he warned, utilities remain vulnerable to such attacks, especially with their systems increasingly dependent on remote connections.

Ferris said that multifactor authentication (MFA) can be an effective way to mitigate the phishing and social engineering risks, but he urged listeners to remember that “some are better than others.” An MFA approach that uses a hardware key may be more effective than one that depends on text messages or an app.

Human attention remains the most important factor, Ferris said, as much for physical security as for cybersecurity. Whether it involves periodic checks of cyber access permissions or walk-downs of fences and other physical infrastructure, utilities must maintain awareness of who is allowed into their systems and why.

“The key to all of this, to remain compliant and be reliable and address those risks, is, are you controlling the access? Because that’s what the standard says you have to be able to control,” Ferris said.

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NextEra Energy Continues to Rack up Renewables Deals

NextEra Energy posted solid first-quarter financials and said its renewables portfolio continued to grow even as President Donald Trump began implementing pro-fossil fuel policies.

CEO John Ketchum said during an April 23 conference call that wind, solar and storage are indispensable now as the U.S. expects to need a lot more megawatts because renewables can be brought online much faster than natural gas generation and much, much faster than nuclear.

He called renewables “a critical bridge” to a future when other technologies can be brought online at scale.

Until fairly recently, many people were calling natural gas the “bridge fuel” to a decarbonized future. But natural gas has problems, said Ketchum, whose company is an all-of-the-above energy provider operating renewable, nuclear and natural gas generation.

The cost to build a gas plant has tripled in just a few years, and Trump’s tariffs will drive the cost higher, he said. Meanwhile, companies building LNG export terminals, factories and data centers have lured away the skilled workers who would build gas plants, and gas turbine manufacturers are booked up with yearslong wait times on new units.

“Gas is such a long-term solution,” Ketchum told analysts on the conference call. “We’ve gone up from four and a half years to build a combined cycle unit to six or longer.”

This state of affairs, he said, calls for energy realism — understanding the high demand and embracing all solutions — and calls for energy pragmatism — recognizing that some solutions are not ready today and accepting the tradeoffs this implies.

“Renewables and battery storage are the lowest-cost form of power generation and capacity,” Ketchum said, “and we can build these projects and get new electrons on the grid in 12 to 18 months.”

The U.S. is expected to need more than 450 GW of new generation by 2030, he said, and only 75 GW of that is expected to be natural gas fired. Canceling every planned coal retirement would yield only about 40 GW more. Meaningful increases in nuclear generation are 10 years away at best and likely to be much more expensive than gas when they arrive, he added.

In this scenario, NextEra expects to thrive, despite renewables suddenly falling into presidential disfavor.

In the first quarter, subsidiary NextEra Energy Resources originated 3.2 GW of new renewables and storage and scored its largest-ever quarter for solar and solar-plus-storage origination, bringing its project backlog to 28 GW.

Meanwhile, subsidiary Florida Power & Light placed 894 MW of new solar generation into service, bringing its owned-and-operated solar portfolio to more than 7.9 GW — the most of any U.S. utility.

“We continue to see a lot of appetite for renewables,” Ketchum said.

And what of the actual and threatened tariffs that are causing such consternation in so many sectors of the economy? NextEra began to get ready for this years ago. Because it is so large and its competitors are mostly small, it had the leverage and buying power to shift tariff risks onto suppliers in most of its contracts, Ketchum said. NextEra forecasts only $150 million in tariff exposure through 2028 on $75 billion in projected capital expenditures, he said, and may be able to negotiate that exposure down as low as $0.

It also shifted to U.S.-made components, where possible.

“We didn’t just wake up on Nov. 6 and say, ‘Oh my God, what do we do about our supply chain?’” Ketchum said. “We’ve been thinking about this for years, and so we put the right things in place.”

NextEra reported first-quarter revenue of $6.25 billion, up from $5.73 billion a year earlier, and GAAP net income of $833 million ($0.40/share), down from $2.27 billion ($1.10/share).

Adjusted (non-GAAP) earnings were $2.04 billion ($0.99/share), up from $1.87 billion ($0.91/share).

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All-electric Rebuild After L.A. Fires Could be Better than Dual-fuel, Report Finds

Los Angeles leaders should consider rebuilding the more than 20,000 structures destroyed by the January 2025 wildfires as all-electric rather than as dual-fuel despite the potential higher life cycle costs of all-electric buildings, a new report finds. 

After the fires, which burned for much of January, L.A. Mayor Karen Bass issued an executive order that temporarily waived the city’s all-electric building code requirement for rebuilding projects in fire areas, the report by the U.C. Berkeley Center for Law, Energy and the Environment says.  

Typically, an all-electric new single-family home can be $7,500 to $8,200 cheaper to build than a dual-fuel home, while installing a gas line to a new home can cost between $500 and $2,000, according to the report.

But in the neighborhoods burned by the fires — specifically the Pacific Palisades and Altadena — much of the existing natural gas underground piping was undamaged. This negates savings typically found on new construction sites where natural gas infrastructure must be built from scratch.  

Along with reusing existing gas piping, rebuilding homes as dual-fuel homes could be cheaper due to bills: Natural gas bills in L.A. currently are lower than electricity bills for most residents, the report says.  

“Given the possibility of high electricity costs into the future, the most cost-effective option over the building life cycle may be a dual-fuel rebuild, but this scenario is uncertain and necessarily affected by the context of the climate transition in California,” the report says. 

In the long run, all-electric homes could end up as a better investment for a homeowner if more buildings in the region switch to electric-only service. In such a future, there would be fewer ratepayers to share the burden of gas recovery costs, thereby increasing the cost of gas bills.   

All-electric buildings also provide other benefits to homeowners, such as improved indoor air quality, the report says. Natural gas contains volatile organic chemicals (VOCs) that are associated with numerous adverse health impacts and generate indoor air pollution even when appliances, such as stoves, are turned off. Switching from a gas stove to electric induction can reduce indoor nitrogen dioxide air pollution by over 50%, the report says. 

As for speed, all-electric construction tends to be faster than dual-fuel construction: Many rebuilt homes will need to issue separate gas and electric service requests, creating potential coordination issues. Additionally, electricity service will be restored to all homes and businesses regardless of the recovery approach, the report says. 

Policymakers should support streamlining all-electric construction and facilitating electricity affordability, while educating consumers about the cost effectiveness, speed, safety and sustainability of all-electric infrastructure, the report says. 

Last month, Mayor Bass issued an executive order directing city departments to streamline pathways for all-electric and fire-resistant construction.