Filed pursuant to Rule 424(b)(3)

Registration No. 333-292610





ONCOR ELECTRIC DELIVERY COMPANY LLC





SUPPLEMENT NO. 2 TO

PROSPECTUS DATED

JANUARY 20, 2026





THE DATE OF THIS SUPPLEMENT IS FEBRUARY 26, 2026







On February 26, 2026, Oncor Electric Delivery Company LLC filed the attached Annual Report on Form 10-K for the year ended December 31, 2025, with the Securities and Exchange Commission.









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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________

FORM 10-K



☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the Fiscal Year Ended December 31, 2025



— OR —



☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Commission File Number: 333-100240



Oncor Electric Delivery Company LLC

(Exact name of registrant as specified in its charter)







Securities registered pursuant to Section 12(b) of the Act: 





Securities registered pursuant to Section 12(g) of the Act: None



Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. 

Yes ☐ No ☒ 



Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. 

Yes ☐ No ☒



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  

Yes ☐ No ☒



Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). 

Yes ☒ No ☐ 



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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.



                                 Large accelerated filer ☐                                                 Accelerated filer ☐  

                                 Non-accelerated filer ☒                                               Smaller reporting company ☐  

                                                                                                                           Emerging growth company ☐



If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

☐



Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

☒



If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

☐



Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

☐



Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). 

Yes ☐ No ☒



Aggregate market value of Oncor Electric Delivery Company LLC limited liability company membership interests held by non-affiliates: N/A



As of February 26, 2026,  635,000,000 limited liability company membership interests of Oncor Electric Delivery Company LLC were outstanding, 80.25% of which were directly held by Oncor Electric Delivery Holdings Company LLC and 19.75% of which were held by Texas Transmission Investment LLC. None of the membership interests are publicly traded.



DOCUMENTS INCORPORATED BY REFERENCE: None





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Oncor Electric Delivery Company LLC (Oncor) makes its filings with the Securities and Exchange Commission available to the public, free of charge, on Oncor’s website at http://www.oncor.com as soon as reasonably practicable after they have been filed with or furnished to the Securities and Exchange Commission. The information on Oncor’s website or available by hyperlink from its website shall not be deemed a part of, or incorporated by reference into, this Annual Report on Form 10-K. The representations and warranties contained in any agreement that we have filed as an exhibit to this Annual Report on Form 10-K or that we have or may publicly file in the future may contain representations and warranties made by and to the parties thereto as of specific dates. Such representations and warranties may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent the parties’ risk allocation in the particular transaction, or may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes.



This Annual Report on Form 10-K and other Securities and Exchange Commission filings of Oncor occasionally make references to Oncor (or “we,” “our,” “us,” or “the company”) when describing actions, rights or obligations of Oncor and/or its subsidiaries. These references reflect the fact that the subsidiaries are consolidated with Oncor for financial reporting purposes. However, these references should not be interpreted to imply that Oncor is actually undertaking the action or has the rights or obligations of any subsidiary or that any subsidiary company is undertaking an action or has the rights or obligations of its parent company or of any other affiliate.

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GLOSSARY







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PART I



Items 1. and 2.  BUSINESS AND PROPERTIES



References in this report to “we,” “our,” “us” and “the company” are to Oncor and/or its subsidiaries as apparent in the context. See “Glossary” starting on page 4 for the definition of terms and abbreviations.



Overview of Oncor 



We are a regulated electricity transmission and distribution company. We operate the largest transmission and distribution system in Texas based on the number of end-use customers and circuit miles of transmission and distribution lines, delivering electricity to more than 4.1 million homes and businesses and operating more than 145,000 circuit miles of transmission and distribution lines at December 31, 2025, all with a focus on safety, reliability, and affordability. We provide:





We also provide transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas.



The rates we charge for our electricity delivery services are set pursuant to tariffs approved by the PUCT and certain cities and, in the case of transmission service related to limited interconnections to other markets, the FERC. We are not a seller of electricity, nor do we purchase electricity for resale. The majority of consumers of the electricity we deliver through our distribution business are free to choose their electricity supplier from REPs who compete for their business.



Our transmission and distribution assets are located principally in the north-central, eastern, western and panhandle regions of Texas, in over 120 counties and more than 400 incorporated municipalities. We deliver electricity across a distribution service territory that has an estimated population of approximately 14 million, including the cities of Dallas and Fort Worth and the surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler, Temple, Killeen and Round Rock, among others. 



We are a limited liability company organized under the laws of the State of Delaware, formed in 2007 as the successor entity to Oncor Electric Delivery Company, a corporation formed under the laws of the State of Texas in 2001. Our website address is www.oncor.com. The information on our website or available by hyperlink from the website shall not be deemed a part of, or incorporated by reference into, this Annual Report on Form 10-K.



Ownership Structure and Ring-Fencing Measures



We are a direct, majority-owned subsidiary of Oncor Holdings, which is indirectly and wholly owned by Sempra. Oncor Holdings owns 80.25% of our membership interests and Texas Transmission owns 19.75% of our membership interests. Since 2007, various ring-fencing measures have been taken to enhance our credit quality and the separateness between the Oncor Ring-Fenced Entities and entities with a direct or indirect ownership interest in Oncor or Oncor Holdings. These ring-fencing measures serve to mitigate the Oncor Ring-Fenced Entities’ credit exposure to Sempra and its affiliates and any other direct or indirect owners of Oncor and Oncor Holdings, and reduce the risk that the assets and liabilities of the Oncor Ring-Fenced Entities would be substantively consolidated with the assets and liabilities of any Sempra entity or any other direct or indirect owners of Oncor and Oncor Holdings in connection with a bankruptcy of any such entities. 



In March 2018, Sempra indirectly acquired Oncor Holdings. The final order issued by the PUCT approving that transaction outlines certain ring-fencing measures, governance mechanisms and restrictions that apply to Oncor Holdings and Oncor. As a result of these ring-fencing measures, Sempra does not control Oncor, and the ring-fencing measures limit Sempra’s ability to direct the management, policies and operations of Oncor, including the deployment or disposition of Oncor’s assets, declarations of dividends, strategic planning and other important corporate issues and actions. Our LLC

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Agreement requires PUCT approval of certain revisions to the agreement, including, among other things, revisions to our governance structure and other various ring-fencing measures.



None of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or obligations of any Sempra entity or any other direct or indirect owner of Oncor or Oncor Holdings. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of any Sempra entities and any other direct or indirect owner of Oncor or Oncor Holdings. We do not bear any liability for debt or contractual obligations of Sempra and its affiliates or any other direct or indirect owner of Oncor or Oncor Holdings, and vice versa. Accordingly, our operations are conducted, and our cash flows are managed, independently from Sempra and its affiliates and any other direct or indirect owner of Oncor or Oncor Holdings.



Oncor is a limited liability company governed by a board of directors, not its members. The Sempra Order and our LLC Agreement require that the board of directors of Oncor consist of 13 members, constituted as follows:





Until March 9, 2028, in order for a current or former officer of Oncor to be eligible to serve as an Oncor Officer Director, the officer cannot have worked for Sempra or any of its subsidiaries or affiliated entities (excluding Oncor Holdings and Oncor) or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings in the ten-year period prior to the date on which the officer first became employed by Oncor. Oncor Holdings, at the direction of STIH, has the right to nominate and/or seek the removal of the Oncor Officer Directors, subject to approval by a majority of the Oncor board of directors.



In addition, the Sempra Order provides that Oncor’s board of directors cannot be overruled by the board of directors of Sempra or any of its subsidiaries on dividend policy, the issuance of dividends or other distributions (except for contractual tax payments), debt issuance, capital expenditures, operation and maintenance expenditures, management and service fees, and appointment or removal of members of the board of directors, provided that certain actions may also require the additional approval of the Oncor Holdings board of directors. The Sempra Order also provides that any changes to the size, composition, structure or rights of the board of directors must first be approved by the PUCT. In addition, if Sempra acquires Texas Transmission’s interest in Oncor, the two board of director positions on Oncor’s board of directors that Texas Transmission is entitled to appoint will be eliminated and the size of Oncor’s board of directors will be reduced by two.



Additional regulatory commitments, governance mechanisms and restrictions provided in the Sempra Order and our LLC Agreement to ring-fence Oncor from its owners include, among others:



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Oncor’s Market

(ERCOT statistics below were derived from information published by ERCOT and/or the PUCT)



We are a member utility and operate within the ERCOT market. This market represents approximately 90% of the electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the Independent System Operator (ISO) of the interconnected transmission grid for those systems. ERCOT is subject to oversight by the PUCT and the Texas Legislature. ERCOT is responsible for ensuring reliability, adequacy and security of the electric systems, as well as nondiscriminatory access to transmission service by all wholesale market participants in the ERCOT region. ERCOT’s membership consists of corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, transmission service providers, distribution services providers, independent REPs and consumers.



Wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC. The ERCOT market has limited interconnections to other markets in the U.S. and Mexico, which limits potential electricity imports into and exports out of the ERCOT market.



The ERCOT market operates under reliability standards set by NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’ main interconnected transmission grid. We, along with other owners of transmission and distribution facilities in Texas, assist the ERCOT ISO in its operations. We have planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and the load-serving substations we own, primarily within our certificated distribution service area. We participate with the ERCOT ISO and other ERCOT utilities in obtaining regulatory approvals and planning, designing, constructing and upgrading transmission lines in order to remove existing constraints and interconnect generation on the ERCOT transmission grid. The transmission line projects are necessary to meet reliability needs, support energy production and increase bulk power transfer capability.



ERCOT has been experiencing significant growth in recent years, including trends of notable demand for more electricity and increasing penetration of intermittent generation, and ERCOT expects rising demand to continue, driven by factors such as the further electrification of oil and gas processes in the Permian Basin as well as continued interest in connecting large load customers (such as data centers, crypto miners, and manufacturers) to the ERCOT grid. ERCOT’s December 2025 regional transmission plan forecasts 159,000 MW of peak demand for 2031, compared to the current peak hourly demand record of 85,508 MW set in the summer of 2023. Certifications submitted by various transmission service providers in the ERCOT market suggest 2031 peak demand could potentially exceed that. The Texas Legislature, the PUCT and ERCOT have implemented, and are expected to continue to implement, measures to address anticipated ERCOT growth forecasts. For example, to address significant anticipated load growth, ERCOT developed the STEP, which includes thousands of miles of new transmission build and upgrades to existing lines, including the introduction of 765-kV infrastructure to the ERCOT market. In April 2025, the PUCT approved the first use of the 765-kV voltage class as part of the PBRP, a portion of the STEP covering projects in the Permian Basin. In December 2025, ERCOT endorsed the

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remaining projects within the STEP. Oncor has responsibility for designing, building, and maintaining a significant portion of the projects in the STEP, including projects in both the PBRP and the non-Permian Basin portions of the STEP.



Oncor’s Strategies



We focus on delivering electricity in a safe, reliable, and cost-effective manner, minimizing service interruptions, investing in our transmission and distribution infrastructure to maintain our system, constructing new facilities to support the growing electricity needs of the ERCOT market, serving our customers with a modernized grid, providing interconnections to other transmission systems in Texas, and supporting energy production through transmission grid connections to merchant generation facilities.



Our five-year capital plan reflects significant expected investments, primarily related to constructing transmission and distribution facilities and investing in reliability measures and technology upgrades to support the needs of our growing customer base, the state of Texas, and the ERCOT market. We are focused on continuing to expand our processes, workforce, and supply chain to meet the needs of those capital projects and our growing system. We have been particularly focused on leveraging our supplier relationships, and developing new supplier relationships, to help us meet project timelines. We strive to maintain a diversified supplier base, including expanding the number of suppliers for critical inventory, and engaging in long-term supply forecasts. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources” for more information on our projected capital expenditures.



Our capital expenditure plans include the large-scale buildout of new transmission lines, including 765-kV lines, a new voltage for the ERCOT market. The scope and timeline of these projects in particular requires extensive planning, including the acquisition of significant amounts of materials and labor to complete the projects, multiple regulatory filings, the acquisition of thousands of miles of right-of-way, and community and stakeholder coordination. We have implemented various strategies to help meet those expected needs, including cross-functional project teams, improvements to our supply chain, such as increasing the number of vendors for certain products and reserving long-lead time materials, long-term contracting for service providers, coordinating an extensive right-of-way acquisition process, and extensive community, stakeholder and regulatory engagement.



Keeping rates affordable for our customers is a key consideration for us, and we emphasize operating in a cost-effective manner. We believe that building upon opportunities to scale capital projects across our existing infrastructure enables us to create value by minimizing duplicative costs, creating efficiencies of scale, managing supply costs more efficiently, and building and standardizing distinctive process expertise.



Serving new and existing LC&I customers, including data centers, represent a significant and growing component of our long-term growth. We believe demand in the ERCOT market is being driven, and could be significantly increased, as a result of large load customers utilizing growing computing power needs related to cloud computing, cryptocurrency mining, AI technology, data storage, advanced manufacturing, and other technological and electrification needs and advances. We also believe there are continued growth opportunities with increased electrification efforts in the ERCOT market, particularly through oil and gas producers electrifying their operations. Such increased demand could result in higher electricity volumes delivered by us as well as obligations for additional capital investments to interconnect sources to the ERCOT grid and meet service reliability needs. We are actively planning and investing to support this growth through transmission and distribution infrastructure enhancements, and close coordination with regulators, ERCOT, stakeholders, and our customers. However, there are risks that the demand expected from these customers may not materialize. See “Item 1A. Risk Factors—Risks Related to Our Business and Operations—Demand for energy from high usage customers, including data centers, will require a rapid and significant increase in our infrastructure, but that forecasted energy demand may not be fully realized and we may not be able to recover all of the costs expended by us on projects related to those customers.” 



In addition to organic growth strategies, we also regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets.



Oncor’s Operations



Electricity Transmission — Our electricity transmission business is responsible for the safe and reliable operations of our transmission network and substations. These responsibilities consist of the construction, operation, maintenance, and

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security of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over our transmission facilities in coordination with ERCOT.



As an ERCOT member utility, our transmission business, with applicable regulatory approval, also participates with ERCOT and other member utilities to plan, design, construct and operate new transmission lines to maintain reliability, interconnect to merchant generation facilities, increase bulk power transfer capability and/or minimize limitations and constraints on the ERCOT transmission grid.



Transmission revenues, also known as TCOS revenues or network transmission revenues, are provided under tariffs approved by either the PUCT or, to a small degree related to limited interconnections to other markets, the FERC. Network transmission revenues compensate us for delivery of electricity over our transmission facilities operating at 60kV and above and are collected from load serving entities benefitting from our transmission system. Other services we offer through our transmission business that we classify as other miscellaneous revenues include system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.



At December 31, 2025, our transmission system included:





At December 31, 2025, our transmission facilities had the following connections to other transmission grids in Texas:



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Electricity Distribution — Our electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including electricity delivery, power quality, security, and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within our certificated service area. Our distribution system receives electricity from the ERCOT transmission system through substations and distributes electricity to end-users and wholesale customers through 3,874 distribution feeders at December 31, 2025.



At December 31, 2025, our distribution system included:





In general, distribution revenues from residential and small business users are based on actual monthly consumption (kWh), and, depending on size and annual load factor, revenues from LC&I users are generally based either on actual monthly demand (kilowatts) or the greater of actual monthly demand (kilowatts) or 80% of peak monthly demand during the prior 11 months.



Regulation and Rates — As our operations are wholly within Texas, we believe we are not a public utility as defined in the Federal Power Act and, as a result, are generally not subject to FERC regulation under the Federal Power Act However, we are subject to reliability standards adopted and enforced by Texas RE and NERC (including critical infrastructure protection) under the Federal Power Act.



The PUCT has original jurisdiction over wholesale transmission rates and services and retail rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the retail rates, retail services, and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (i.e., the PUCT or the municipality with original jurisdiction).



At the state level, PURA requires utility owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for all utilities, including us, that are subject to the PUCT’s jurisdiction over transmission services.



PUCT rules allow for interim rate adjustments for capital trackers that allow utilities to recover, subject to reconciliation, the cost of certain investments before a comprehensive base rate review. As a result of legislation signed into law in 2025 establishing the UTM, we can now, through 2035, request capital tracker interim rate adjustments each year through the filing of either (i) a single UTM application (subject to meeting annual eligibility requirements) or (ii) up to two TCOS capital tracker applications to reflect changes in transmission-related capital investments and up to two DCRF capital tracker applications to reflect changes in distribution-related capital investments. All investments included in a capital tracker update application are ultimately subject to prudence review by the PUCT in the next base rate review after such assets are put into service. We anticipate filing our initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result have recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. See Note 2 to Financial Statements for more information on the UTM.



As a regulated utility, our business is subject to extensive governmental regulations and compliance obligations, which could greatly impact our business. See “Item 1A. Risk Factors—Risks Related to Regulatory and Legislative Matters” as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2 and 7 to Financial Statements for a discussion of certain regulatory matters and commitments and the material effects of compliance with regulations on our business.



Properties —  Most of our power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way pursuant to permits, public utility easements, franchise or other agreements or as otherwise permitted by law. In addition to power lines and related assets in our transmission and distribution system, we also own or lease land, offices, facilities, equipment, and vehicles to operate our business. Certain of our transmission and distribution assets, including certain real property assets, are subject to a first priority lien pursuant to our Deed of Trust. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources” for more information on our Deed of Trust.



Customers — Our transmission business customers consist of municipally-owned utilities, electric cooperatives and other distribution companies. At December 31, 2025, our distribution business customers primarily consisted of over 100 REPs that sell electricity we distribute to consumers in our certificated service area. Revenues from REP subsidiaries of Vistra and NRG Energy, Inc., our two largest customers, collectively represented 25% and 21%, respectively, of our total operating revenues for the year ended December 31, 2025, and 25% and 23%, respectively, of our total operating revenues

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for each of the years ended December 31, 2024 and December 31, 2023. No other customer represented more than 10% of our total operating revenues during such periods. The majority of consumers of the electricity we deliver through our distribution business are free to choose their electricity supplier from REPs who compete for their business.



Competition — Oncor operates in certificated areas designated by the PUCT. The majority of Oncor’s service territory is singularly certificated, with Oncor as the sole certificated transmission and distribution provider. However, in multi-certificated areas of Texas, Oncor competes with certain municipal utilities and electric cooperatives for the right to serve end-use customers. In addition, the electric industry is undergoing rapid technological change, and third-party DER (including behind the meter alternatives and private use networks) and virtual power plants and other technologies may increasingly compete with our traditional transmission and distribution infrastructure for meeting customers’ electricity needs. See “Item 1A. Risk Factors—Risks Related to Our Business and Operations—The growth of DER and similar technologies or actions that decrease demand or consumption of electricity we deliver may significantly adversely impact us.”



Seasonality —  Our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer season.



Investing in Infrastructure —  In 2025,  we invested approximately $6.8 billion in our transmission and distribution system to extend and upgrade the transmission system and associated facilities, to extend and upgrade the distribution infrastructure and to pursue certain initiatives in infrastructure, including investments to support system growth, reliability and resiliency. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources” for more information on our capital expenditures, including our projected capital expenditures for the next five years.



Environmental Regulations and Related Considerations —  The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believe we hold all required wastewater discharge permits from the TCEQ for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals. In addition, there are federal rules pertaining to Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil that affect certain of our facilities. We have implemented SPCC plans as required for those substations, work centers and distribution systems.



Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to our facilities.



Our capital expenditures for environmental matters totaled $163 million in 2025 and are expected to total approximately $238 million in 2026.



Human Capital Management —  At December 31, 2025, we had approximately 5,600 employees, including nearly 860 employees covered under a collective bargaining agreement that expires in October 2026. As of December 31, 2025, the average length of service among all employees was 11.1 years, and over 99% of our employees were employed on a full-time basis. For the year ended December 31, 2025, we experienced an annual employee turnover rate of approximately 5.4%, including approximately 1.8% that was attributable to retirements. Our employee data excludes interns, and we had about 70 interns serving in full-time or part-time internships at December 31, 2025.



Attracting, retaining, and developing high quality talent is key to our human capital management strategy. In light of the anticipated growth of our business and the expected increase in headcount needed to meet that growth, recruiting remained a significant focus of our human capital management efforts in 2025 and is expected to be a continued focus over the next few years. We employ a multi-faceted recruiting strategy to recruit a diverse, high quality talent pool, including leveraging several higher education and high school partnerships established across our service territory and assisting higher education and technical institutions in developing linemen schools and courses. In 2025, we expanded our recruiting efforts through more targeted activities, such as military veteran hiring recruiting initiatives and a collaboration between hiring managers and recruiters to strengthen our intern pool. We have also been actively focused on retention and

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developing our existing talent through upskilling managers and supervisors and increasing our customized talent development offerings.



We believe market-competitive compensation and benefits packages are necessary to attract and retain talent, and we annually conduct a market assessment using third party benchmark salary and benefit data to determine the competitiveness of our compensation and benefit programs against utility/energy services companies and general industry companies. In addition, we continuously monitor the competitive labor market and macroeconomic conditions with a view toward adjusting compensation and benefit practices as needed in advance of the annual market assessment to attract, develop, and retain talent. We strive to provide competitive packages that include performance-based compensation that rewards organizational achievement as well as individual efforts. 



Our workplace culture is central to our efforts to attract, retain, and develop talent. We strive to create a workplace culture that emphasizes the following key areas:





Item 1A.RISK FACTORS



Risks Related to Regulatory and Legislative Matters



We are subject to ongoing complex governmental regulations that require significant compliance efforts and are subject to change by regulators and legislative action, and adverse public perception of us, our industry, or ERCOT could result in new or revised regulations or laws applicable to us.

 

As a regulated electricity transmission and distribution company, our business is subject to numerous local, state, and federal laws (including PURA, certain provisions of the Federal Power Act, the Public Utility Regulatory Policies Act of 1978, and the Energy Policy Act of 2005), executive orders issued by the President of the U.S. and the Governor of Texas, as well as governmental policies, regulations, and administrative actions by the PUCT and other governmental authorities (including city governments, NERC, Texas RE, the FERC, environmental agencies, and others). As an ERCOT member utility, we are also subject to ERCOT rules, guidelines, directives, and protocols for transmission and distribution utilities operating in ERCOT.



We devote a significant amount of employee time and expenditures to continued compliance with the laws, policies, regulations, rules, guidelines, directives, protocols and administrative actions applicable to us. Developing and implementing plans for continued compliance with laws, regulations, and policies applicable to us or expected to be applicable to us has led, and may continue to lead, to increased costs, particularly to address new or revised laws and regulations. For example, our operations are subject to various mandatory regulatory standards and requirements, including service quality, reliability (including cybersecurity and physical security requirements), and weatherization of facilities. Compliance with such standards is subject to regular reporting, reviews, and audits, and maintaining such compliance may subject us to higher than expected costs. If we were found at some point to be noncompliant with applicable regulatory standards, we could be subject to reputational harm, regulatory scrutiny, or sanctions, including monetary penalties. For example, the PUCT may impose penalties on us if it finds that we violated PURA or any PUCT rule or order adopted under PURA, including penalties of up to $1 million per day per violation for failure to meet certain weatherization requirements and up to $25,000 per day per violation for other violations. Penalties imposed on us by the PUCT, Texas RE, the FERC,

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and/or NERC may not be recoverable from our customers through regulated rates and could have a material adverse impact on our financial condition, results of operations and cash flows.



In recent years, the PUCT and the Texas Legislature have instituted various changes relating to operations in the ERCOT market and both continue to actively review the operations of the ERCOT market. Significant changes to the ERCOT market that impact transmission and distribution utilities, including additional or revised regulatory requirements or oversight, could materially and adversely impact our business, operations, financial condition, results of operations, and/or business prospects.



Negative public perception of us, our industry, or ERCOT could adversely affect legislative or regulatory processes or outcomes and result in new or changed laws or regulatory requirements, adverse rate decisions, governmental investigations, administrative actions, fines, penalties, or other sanctions or requirements against us that could have a material adverse effect on us, our operations, financial position, results of operations and cash flows. Factors contributing to our public perception could be outside our control, including severe weather, wildfires, ERCOT mandates such as mandatory load shed events, the level of electricity produced by generators in ERCOT, economic conditions, non-Oncor charges on customers’ overall electric bills, ERCOT market requirements, actions by other transmission and distribution utilities or ERCOT market participants, and emergency events. Addressing any adverse publicity, regulatory scrutiny, enforcement or other legal proceedings has been, and would be, time consuming and result in increased expenses.



Our business is subject to rate regulation, and the regulatory review process could materially adversely impact us, including by limiting our ability to fully recover costs or reducing the rate we earn on invested capital and the timing of such recovery.

 

The rates we charge are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide assurance as to achievement of earnings levels or recovery of actual costs. Our rates are based on an analysis of our costs and capital structure in a designated historical test year, as reviewed and approved in regulatory proceedings. As a result, the rates we are allowed to charge will generally not match our costs at a given point in time, which could materially and adversely affect our financial condition, cash flows, and results of operations.



In accordance with PUCT rules, we must file a comprehensive base rate review within four years of the last order in our most recent comprehensive rate proceeding, unless an extension is otherwise approved by the PUCT. However, the PUCT or any city retaining original jurisdiction over rates may direct Oncor to file a base rate review, or Oncor may voluntarily file a base rate review, any time prior to that deadline. In June 2025, we voluntarily filed a request for a comprehensive base rate review earlier than required. That base rate review relies on a 2024 historical test year, with certain adjustments. On January 29, 2026, we filed a stipulation in the comprehensive base rate review proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. The PUCT may choose to adopt, modify, or reject the stipulation and the proposed order included in the stipulation. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulation and Rates—Regulatory Matters” for a discussion of that base rate review proceeding.



Our rates may not be sufficient to recover all amounts spent after test year periods and/or the full return on invested capital allowed by the PUCT, particularly during periods of increased capital spending by us, high inflation, increases in interest rates, increases in storm-related costs, and increases in other operating costs as compared to the test year in our most recently decided base rate review. In recent years we have not in fact earned our full regulatory authorized return on invested capital. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge any of our costs, including invested capital and costs included in a regulatory asset reported on the balance sheet, to have been prudently incurred and therefore fully recoverable. The levels and timing of any approved recovery could also significantly differ from our requests. Intervening parties in our rate proceedings (including, but not limited to, governmental agencies, cities in our service territory, customers, and consumer groups) can challenge, and have in the past challenged, various portions of our rate proceedings, and such challenges, as well as any recommendations from the administrative law judges overseeing proceedings, could influence the PUCT’s decisions in those proceedings. Failure to receive approval of our requests in any rate proceeding could adversely impact our financial condition, results of operations, cash flows, liquidity and/or business prospects, and those impacts could be material.



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PUCT rule-making proceedings and statutory interpretations could also materially impact us. In June 2025, legislation was signed into law in Texas that helps minimize the regulatory lag on transmission and distribution capital investments through the UTM process, which allows qualifying electric utilities to apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments. Utilities electing to use the UTM are allowed to defer to a regulatory asset certain transmission and distribution capital investment costs as they are placed into service. We anticipate filing our initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result have recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. However, the PUCT has not finalized rules with respect to use of the UTM, and as a result any positions we have taken with respect to interpreting the legislation could be revised as a result of the PUCT’s final rules and interpretations, and such revisions could have a material adverse impact on our earnings, financial condition, cash flows, and results of operations.

 

Risks Related to Our Business and Operations

 

Cyber-attacks on us or our third-party vendors could disrupt business operations, initiate the loss or disclosure of critical operating or confidential data, adversely impact our reputation, and expose us to significant liabilities.

 

As an owner and operator of critical infrastructure assets, we are subject to cybersecurity threats from domestic and foreign threat actors who wish to disrupt our electricity delivery operations and/or the ERCOT bulk power grid. In particular, U.S. government warnings have indicated that infrastructure assets such as electric transmission and distribution systems have been specifically targeted by both foreign and domestic actors, including as a result of increased worldwide conflict and domestic extremism.

 

We are subject to evolving cyber risks related to adversaries attacking our technology infrastructure and platforms and the technology infrastructure and platforms of third-party vendors. With the proliferation of computing and telecommunications technologies and various digital tools used by us in our business, cyber risk arises in multiple areas of our operations. While we have not experienced a cybersecurity incident to date that has had a material impact on Oncor, we have experienced, and expect to continue to experience, threats and attempted intrusions into our technology systems and platforms. We face various cyber threats, including malware intrusion, computer viruses, unauthorized access attempts, ransomware attacks, social engineering attacks, hacktivism and potential insider threats. Certain of these cyber threats have seen changes, and we expect to continue to see changes, in sophistication, magnitude and frequency with the advancement of technology, including AI that is used to develop new hacking tools, exploit vulnerabilities, obscure malicious activities, and increase the difficulty detecting threats. As domestic and global cyber threats are ongoing and increasing in sophistication, magnitude and frequency, our transmission, distribution and technology infrastructure may be targets of state-sponsored attacks, terrorist activities, or other threats, including attacks designed to collect ransoms or inflict large-scale harm on us, our customers or our service territory. Geopolitical events could increase those cyber threats. Any breach of cyber/data security measures could result in a material and adverse impairment of our ability to operate, monitor and control our technology or transmission and distribution assets (which could impact the stability of the ERCOT power grid), conduct our normal operations, process customer information, and comply with regulatory and disclosure obligations. A cybersecurity breach could limit or disable communications, including communications within our technology platforms and between our technology platforms and systems operated by third parties. In the ordinary course of business, we also collect and retain data that could be sensitive in nature, including customer information and personal information about employees, and a cybersecurity breach could result in the release of such confidential information.

 

Our third-party vendors have been subject, and will likely continue to be subject, to acts that disrupt or attempt to disrupt the services they provide to us. Threat actors could also attempt to use our third-party vendors as a conduit to attack us. In addition, our operations in ERCOT also require communication with certain third-party systems, and disruptions in those systems could impact our operations. If our third-party vendors or any third-party systems integral to operations in the ERCOT market are impacted by cyber-attacks or are otherwise unable to perform the services they provide to us, our operations could be impacted, which could negatively affect our results of operations, financial condition and/or reputation. In addition, the theft, damage, or disclosure of sensitive data held by these third parties may subject us to further harm.

 

Any loss of control of our critical infrastructure, including control or disruption of our technology platforms, or loss of confidential or proprietary data through a cybersecurity breach, including a breach involving one of our third-party vendors, could adversely affect our reputation, expose us to material legal and regulatory claims and fines, require compliance with notification and monitoring regulations, expose us to significant remediation and compliance costs, result

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in legislative or regulatory actions, impair our ability to execute on business strategies and/or materially adversely impact our results of operations, financial condition, liquidity and/or cash flows. Insurance may not cover any or all of the costs associated with the consequences of any cyber breach.

 

We develop and maintain systems and processes aimed at identification, protection, detection, response and recovery from cybersecurity incidents, which require significant investment, maintenance, and ongoing monitoring and updating as threats, technologies and regulatory requirements change. There can be no assurance that these systems and processes will be successful in mitigating all risks relating to cybersecurity incidents. Systems and processes are also subject to vulnerabilities related to social engineering and potential insider threats. In addition, due to the nature of cybersecurity incidents, and the evolving threat landscape, updates and enhancements to such systems and processes may require complex solutions that could require significant time and resources. We are also subject to various laws and regulatory standards relating to our operations and information disclosure, including required compliance with NERC cybersecurity standards. Changes in existing standards or the imposition of new standards could increase our compliance costs and our exposure to the potential risk of violations of such standards.

 

The loss or malfunction of key technology platforms maintained by us or our third-party vendors could have an adverse impact on our reputation and operations.

 

Our operations are dependent upon the proper functioning of our internal systems, including our key technology platforms that support our underlying business processes. Any significant failure or malfunction of a key internal technology platform may result in disruptions to our business or electric grid operations. Some of the technology systems, hardware, software, and technical applications and platforms used in our business are managed, hosted, provided or used by third parties to assist in our business operations. Certain of our key externally hosted technology platforms are dependent upon global communications and cloud service providers, as well as their respective vendors, many of whom have at some point experienced significant system failures and outages in the past and may experience such failures and outages in the future. Any of the key technology platforms we rely on could experience cybersecurity and data breaches, vulnerability in third-party software code, outages from fire, floods, power loss, telecommunications failures, unintended consequences as a result of upgrades to a particular software or human error, break-ins and similar events. Failure by us or our third-party vendors to prevent or mitigate operational impacts or data loss from system failures or outages could materially affect our reputation and results of operations, financial position and cash flows.

 

Severe weather, natural disasters, and other related phenomena have in the past and could in the future adversely impact us, and climate change could make such phenomena more prevalent and unpredictable.

 

Our electric delivery facilities and related assets are located in over 120 counties in Texas and could be, and have in the past been, damaged or impacted by severe weather events, such as significant storms, as well as natural disasters, wildfires or other emergency events. Our service territory covers a highly variable range of geographic, climatic, and vegetative regions, and weather conditions can vary significantly across our service territory. Any severe weather or similar events that cause extensive damage on our system or that affect the reliability of the ERCOT grid and market generally (including the amount of electricity produced by third-party generators and available for delivery by us to our customers) could have a material adverse impact on us, including causing outages or other disruptions in our operations, negatively impacting the reliability of our electricity delivery services, increasing our costs to repair or replace damaged facilities or equipment, and causing disruptions in planned projects, property damage, and personal injuries or loss of life for which we could face legal actions or risks, negative public perception, and regulatory, legislative, or legal actions. While our rates include an annual amount of revenue to recover ongoing self-insurance reserve costs, including storm damage costs, the amounts we actually incur in connection with any such events could significantly exceed the annual amount of recovery, which could negatively impact our cash from operations. We rely on our ability to deploy resources timely to complete restoration efforts and the availability of outside contractors (including industry-wide mutual assistance from third party public utilities). During severe weather events we may be unable to deploy sufficient resources to complete restoration efforts in a timeframe and manner acceptable to our customers due to increased demand for supplies and the high demand for outside contractors, which may expose us to fines, penalties, reputational harm, and other liabilities. Any costs and liabilities relating to severe weather events, natural disasters, wildfires or other emergency events may not be fully covered by our insurance policies and may not be fully recovered in rates, and any rate recovery may be delayed.

 

Severe weather, natural disasters, and other related phenomena could become more prevalent and unpredictable as a result of climate change or other factors, which could negatively affect our business and financial condition to the extent

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such events occur in or impact our service territory or lead to constraints in our supply chain. Customer energy needs vary with weather conditions, primarily due to fluctuations in temperature and humidity. To the extent weather conditions are affected by climate change, customer energy use could increase or decrease depending on the duration and magnitude of the changes. More frequent extreme weather conditions and seasonal fluctuations also impact the variability of load and generation. Weather conditions also impact transmission and distribution system operations. For example, exceptionally warm weather conditions for a long duration, which generally would result in increased customer energy usage, would also result in increased operational risks for transmission and distribution infrastructure, such as the risk of equipment malfunction due to continuous operation. In 2025, our service territory saw various severe weather events, including both extreme drought and extreme flooding, significant rainfall, storms, large hail, damaging winds, ice storms and tornados, which impacted our service territory and led to prolonged outages and extensive restoration efforts. Prolonged power outages to customers and business interruptions from outages could damage our reputation and have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Wildfires could have a material adverse effect on our business.

 

Wildfires have the potential to negatively affect communities within our service territory and the surrounding areas, as well as our transmission and distribution system. The possibility of wildfires and the risk of damage to our network and facilities resulting from them may be exacerbated by severe weather events or weather conditions, including prolonged periods of hot, dry weather potentially combined with strong winds, and such weather conditions could worsen as a result of climate change. The continued expansion of the wildland-urban interface has also increased wildfire risk to communities in our service territories. More frequent and severe drought conditions, extreme swings in amount and timing of precipitation, changes in vegetation, unseasonably warm temperatures, very low humidity, stronger winds and other factors have increased the duration of the wildfire season and the potential impact of an event. Although we proactively take steps to mitigate wildfire risk, wildfires can occur even when effective mitigation procedures are followed. Wildfires caused, or allegedly caused, by our transmission and distribution assets or our operation or maintenance practices, could expose us to litigation, costs, fines, penalties, reputational harm, and other liabilities, including for economic damages, personal injury, loss of life, or property damage. Furthermore, any damage caused to our assets, loss of service to our customers, or liability imposed on us as a result of wildfires could negatively impact our business, reputation, financial condition, results of operations and cash flows. Recent Texas legislation requires filing of a wildfire mitigation plan for PUCT approval, and it is expected that failure to appropriately implement any approved plan could result in penalties. While we have maintained a wildfire mitigation plan for several years, that plan could be subject to revision to obtain the required PUCT approvals and those revisions could subject us to increased costs and compliance activities.



Rating agencies have also indicated concerns regarding wildfire risk for our industry in general, noting changing climate conditions as a factor in elevating wildfire risks. In addition, rating agencies have highlighted wildfire risk in Texas in particular given that Texas does not have certain legal protections available in other jurisdictions, such as an aggregate liability cap on damages relating to a wildfire event and the lack of an affirmative defense to shield utilities from liabilities when faced with wildfire litigation. In July 2025, one of the credit rating agencies lowered our credit rating, citing elevated wildfire risk as a primary consideration in the downgrade. The downgrade has caused increases in borrowing and commitment fees under our Credit Facilities. Furthermore, any further action taken by rating agencies with respect to our ratings as a result of their perception of our wildfire risk could negatively impact our business, reputation, financial condition, results of operations and cash flows.

 

We maintain excess liability insurance that includes wildfire coverage, although this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover all of the costs associated with the consequences of any wildfire. Likewise, our ability to obtain wildfire insurance at rates we believe are commercially reasonable, or at all, and the coverage provided by any such insurance could be affected by events outside our control. While recent Texas legislation clarifies the ability of utilities to self-insure certain wildfire risks, any such self-insurance plan is subject to various restrictions, including PUCT approval. 



Insufficient electricity generation, overall system congestion, and disruptions in the power supply within ERCOT are outside of our control and could interrupt and/or negatively impact our operations and impact public perception of us.

 

We are not a generator of electricity and have no control over the amount of electricity generated and the mix of generation resources within the ERCOT market. The electricity we transmit and distribute to REPs, electricity distribution companies, electric cooperatives and municipally-owned utilities is obtained by these entities from electricity generation facilities. Electricity demand in ERCOT has increased in recent years and is expected to continue to increase. Projected

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load growth across the ERCOT system could, if not sufficiently addressed through system design and reliability measures, negatively impact electric infrastructure reliability and potentially cause system-wide stresses. ERCOT’s December 2025 regional transmission plan forecasts 159,000 MW of peak demand for 2031, compared to the current peak hourly demand record of 85,508 MW set in the summer of 2023. Demand may be further increased during periods of extreme weather, such as during hotter than normal temperatures and prolonged cold temperatures. In November 2025, NERC issued its winter reliability assessment and noted the risk of reserve shortage during the peak load hour and high-net-load hours, particularly under extreme load conditions that accompany freezing temperatures for the 2025-2026 winter season in the ERCOT market. The continued risk remains elevated due primarily to strong load growth from new data centers and other large industrial end users where peak demands occur during reduced output from dispatchable resources. In addition to the unprecedented load growth in ERCOT, the ERCOT system is experiencing a growing amount of congestion. The STEP is designed to mitigate some of this congestion. However, there is no guarantee that the execution of STEP and the PBRP will eliminate or reduce the amount of congestion within the ERCOT system. Significant uncertainty exists regarding future increases in energy demand within the ERCOT system, including whether and how the generation to supply this power will be built at the scale and on the timeframe currently projected. In the event insufficient electricity generation or stresses on the system result in power outages, public perception of our industry as well as economic development in ERCOT could be adversely impacted. In addition, if electricity generation is disrupted or if electricity generation is inadequate, our electricity delivery services may be diminished or interrupted, which could have an adverse impact on our reputation, results of operations, financial condition, and cash flows.



We are subject to ERCOT directives with respect to the flow of power on the electric grid. In the event of extreme weather or other emergency events that impact power availability within the ERCOT market, ERCOT could require us to reduce demand on the grid. If we are required by ERCOT to institute outages, it could negatively impact our reputation, our revenues from transmission and distribution services may be diminished or interrupted, and our results of operations, financial condition and cash flows may be materially and adversely affected.



Our capital deployment plan may not be executed as planned, which could adversely impact the services we provide as well as our reputation, financial condition and results of operations.

 

There can be no guarantee that the execution of our capital plan will be successful or done in accordance with current anticipated spend amounts, and there can be no assurance that the capital investments we currently intend to make in connection with our electricity delivery business will be implemented as contemplated or produce the desired improvements to service and reliability or cost management. A significant portion of our five-year capital expenditure plan is attributable to addressing expected growth in ERCOT, particularly due to increased projected demand due to large scale transmission projects and LC&I customers. Any changes in planned projects or projected growth in our service territory could materially impact our capital expenditures and consequently our capital expenditures plan, which could have a material adverse effect on our results of operations, financial condition, cash flows and/or prospects. Furthermore, there can be no guarantee that our capital investments will ultimately be fully recoverable in rates.



A significant portion of our facilities were constructed many years ago; older transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant expenditures to keep operating at peak efficiency or reliability. While our capital expenditure plans include projects to successfully maintain or replace our aging infrastructure and address the expected growth of electricity demand in our service territory, there can be no assurance that any such projects will be completed in a timely manner or at all, or fully meet all customer requirements at all times. Our capital expenditure plan includes a significant number of customer-requested projects, such as transmission point of interconnection requests from large load customers. These projects involve risks, as they could be cancelled for various reasons, including by the customer or due to failure to receive necessary regulatory approvals or permits. Projects to construct, upgrade, or maintain transmission and distribution infrastructure are subject to various additional uncertainties, including regulatory approvals, permit/license acquisition, land/easement acquisition (including requirements and constraints relating to eminent domain), labor and contractor availability, global trade restrictions, volatile commodity prices, supply chain disruptions, inflation, tariffs, executive orders, costs of materials and labor, and forecasts of future electric load needs. Execution of our capital plan could also be impacted by capital availability, macroeconomic conditions, regulations, ERCOT policies or directives, ERCOT grid needs, weather, natural disasters, wildfires, emergency events, equipment malfunction or failure, accidents, terrorist attacks, cybersecurity events, failure of technology platforms, or other events outside of our control. Failure to execute on our capital deployment program as planned could adversely impact service reliability, as well as our reputation, financial condition, results of operations, and prospects.



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Our capital expenditure plan includes the significant, large-scale buildout of new transmission lines, including lines that will introduce the 765-kV voltage class to the ERCOT market, and these large-scale projects face various challenges that could impact our execution strategy.



ERCOT’s STEP provides for significant transmission buildout in the state of Texas over the next several years, including the PBRP to support the electricity needs of the Permian Basin as well as additional new lines to serve the non-Permian Basin portions of the state. Among the projects are new lines that will introduce the 765-kV voltage class to the ERCOT market. We have responsibility for designing, building, and maintaining a significant portion of the projects in the STEP, which is expected to total billions of dollars in investments. These projects require execution at a larger scale and more aggressive pace than ordinary course construction projects. Oncor’s PBRP projects alone are currently anticipated to require approximately $8 billion in capital investment over the next five years, and are targeted to be placed into service by December 31, 2030. Under the legislation implementing the UTM, if the in-service date for PBRP projects (including the 765-kV PBRP projects) is delayed, we could lose the ability to defer certain expenses unless we demonstrate the reasonableness of such delay. These significant transmission projects have required, and will continue to require, increases in both our internal headcount and contractor resources, which requires significant time and resources given the training and skill required for personnel working on these projects. Additionally, these aggressive timelines challenge our ability, and the ability of our vendors and suppliers, to meet milestones and procure sufficient materials. The projects also require significant new rights-of-way, requiring negotiations with landowners and potential condemnation proceedings that have resulted in, and could continue to result in, higher than anticipated real property-related costs. Any delays or cost escalations could adversely affect our abilities to execute our development strategy.



Timely advancement of these projects will also be dependent on actions by parties outside of our control. For example, numerous Certificates of Convenience and Necessity (CCN) applications are required to be filed in connection with our 765-kV projects. These applications are subject to review and approval by the PUCT. Applications filed to date for these projects have resulted in increased participation by community groups, landowners, and other stakeholders. Additionally, state and local officials have expressed increased interest in these projects, including the transmission routing, cost allocation, and overall infrastructure design. We expect similar engagement with respect to the remaining 765-kV CCN applications to be filed. Heightened public or political scrutiny may extend regulatory timelines, result in additional studies or route modifications, or create additional opposition that increases costs, impairs our ability to secure rights-of ways and other property rights, delays construction timing, necessitates design modifications, results in negative publicity or adversely impacts our relationship with the communities we serve. Approved applications may be on terms significantly different than what we currently expect or project with regards to construction timing and capital expenditures. Legislative or regulatory action that changes, delays, or stops the development of any of the 765-kV or other large-scale transmission projects that we have the responsibility to construct could result in a material adverse impact on our financial conditions and results of operations.



Demand for energy from high usage customers, including data centers, will require a rapid and significant increase in our infrastructure, but that forecasted energy demand may not be fully realized and we may not be able to recover all of the costs expended by us on projects related to those customers. 



We have seen and expect to continue to see significant demand for transmission interconnection from LC&I customers, including data centers. Projected electric demand from these LC&I customers, based on the customers’ transmission interconnection requests, is currently expected to far exceed our current system peak load. Data center electric demand associated with increasing demand for cloud services, AI technology, and blockchain technology is likely to require a rapid and significant increase in our grid infrastructure. The ability to serve these new LC&I requests, including the activities and costs related to the planning, analysis, financing, and construction of transmission infrastructure required to meet these high demands of such customers is significant in terms of both cost and time, and we may not be able to plan, receive required regulatory approvals, finance, and execute on requests in a timely manner. Additionally, forecasting future demand is challenging due to the possibility that a high usage customer may decide not to take energy, to take less energy than anticipated, or not to take service on the anticipated schedule, due to changes in business needs, construction delays, technological advances that improve energy efficiency, or other factors which may result in lower energy demand for energy than anticipated and planned for. In addition, various statutes, regulatory requirements, and ERCOT rules and policies increasingly govern the connection of new LC&I customers to the grid, and these regulations and procedures are under significant and rapidly evolving scrutiny, development and modification.  How these provisions are ultimately implemented could significantly impact the desirability of the ERCOT market to these customers or our ability to interconnect them upon the timelines requested by the customers. Certain of these new customers may be transitory and exit our service territory for reasons outside of our control. In the event that actual demand is lower than projected, our

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capital expenditure plans, results of operations, financial condition, cash flows, business projects, and public perception could be adversely impacted.



While we require customers who do not meet certain credit quality thresholds to provide collateral to us before we commence construction on certain customer-requested construction projects for generation interconnection or new/expanded electricity delivery system facilities, there can be no assurance that if such projects are canceled we’ll be able to recover all of the costs expended by us on those projects. We would generally expect to recover our costs for such construction projects once the projects are placed into service and become part of our rate base, but requiring security helps us to mitigate the risk of expending funds on construction projects that are not put into service due to customer cancellation and as a result not recoverable in rates. At December 31, 2025, we held an aggregate of approximately $2.4 billion in letters of credit, $266 million in parent/affiliate guarantees and $632 million in restricted cash as customer-provided collateral. Such customer-provided collateral is subject to return in accordance with PUCT rules, ERCOT requirements, our tariffs, or the terms of various extension or interconnection agreements we have with our customers. Any cash provided as security is held by us in an escrow account and classified as restricted cash. We require letter of credit and parent/affiliate guarantee providers to meet certain minimum credit rating requirements. However, there can be no guarantee that we will ultimately be able to collect on any such non-cash collateral. In addition, an economic event leading to bank failures or resulting in significant distress on the financial system could have a negative impact on our ability to recover cash for cancelled projects already under construction. If we are not able to recoup our costs for a project through the customer provided collateral and the project is not put into service, we would likely not be able to recover our construction costs in rates. Failure to recover construction project investments through customer-provided collateral or rates could have an adverse impact on us, and those amounts could be material.



As an owner and operator of electricity delivery facilities, we face significant operational risks, including the risk of physical attacks on our infrastructure, that could adversely affect us.

 

The construction, ownership, operation and maintenance of electricity delivery facilities involves many operational risks, including equipment breakdown, failure of facilities, lack of sufficient capital and unexpected costs to maintain the facilities, replacement or refurbishment of aging infrastructure, equipment interruptions, design or construction flaws in equipment or facilities, supply chain disruptions, labor and contractor shortages, inflation, fires, explosions, impact of unusual or adverse weather conditions or other natural events, human operation errors, and interrupted or degraded service on key technology platforms, as well as the risk of performance below expected levels of efficiency or reliability, the occurrence of any of which could result in lost revenues, regulatory penalties for failure to meet reliability or other standards, and/or increased expenses that may not be recoverable in rates. There are also many hazards associated with the ownership, operation, and construction of electricity transmission and distribution assets, and these hazards expose us to risk of personal injury and loss of life, damage or destruction of property, or environmental damage, any of which could result in legal proceedings and liabilities to our business.



In addition, we face threats from threat actors who wish to disrupt the ERCOT bulk power grid or electricity delivery operations in our service territory by physically damaging our transmission and distribution assets. We also face threats related to vandalism, theft, trespassing and acts of civil disobedience that could result in interruptions to our operations. In recent years, physical attacks on utility assets have increased in frequency and severity across the nation. A physical attack on our assets could interfere with normal business operations and affect our ability to control our transmission and distribution system. Certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a breach in any one key physical asset could potentially impact other areas of our system. A physical security breach could adversely affect our reputation, expose us to material regulatory penalties and/or materially affect our results of operations, liquidity and financial condition. Additionally, threats of violence, actual violence and other concerns may result in field employees being unable or unwilling to complete critical functions.

 

Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses that could result from the risks discussed above. In addition, costs incurred in connection with the hazards associated with the operation and maintenance of electricity delivery facilities may not be fully recovered through rates. If the amount of insurance is insufficient or otherwise unavailable, and if we are unable to fully recover in rates the costs of uninsured losses, we could be materially affected.



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The litigation environment in which we operate poses a significant risk to our business.

 

We are involved in the ordinary course of business in a number of lawsuits arising out of our business operations, including personal injury litigation, and have spent, and continue to spend, significant money, time and employee and management focus on such lawsuits and other proceedings. Electricity poses hazards for our workforce and the general public in the event that either comes in contact with electrical currents or energized equipment. Deaths, injuries, property and equipment damage and environmental damage caused by such events can subject us to liability. We are also involved in lawsuits relating to power outages. Insufficient electric generation availability during winter storm Uri in February 2021, led ERCOT to mandate that Oncor and other Texas distribution utilities significantly reduce demand on the grid by rotating outages. As a result of the load shed, customers experienced power outages across ERCOT, including in our service territory, some for prolonged periods of time. Approximately 200 cases have been filed against us as well as various ERCOT market participants relating to such power outages. The litigation is currently consolidated in Texas state court in Harris County, Texas, as part of a multi-district litigation proceeding. In one of the motions to dismiss, all claims against the transmission and distribution utilities that were party to the proceeding, including Oncor, have been dismissed from the proceeding, but that dismissal has been appealed and we cannot predict the outcome of the appeals process relating to the dismissal of those claims, or other appeals, and the ultimate impact of the litigation on our business.

 

We similarly cannot predict whether or to what extent any litigation will impact our business. Judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a business risk. Insurance may not cover any or all of the costs associated with any litigation, and any costs not covered by insurance may not be recoverable in rates. Adverse decisions in litigation proceedings could materially adversely affect our reputation, results of operations, financial condition, cash flows and/or prospects.

 

Our revenues are concentrated in and collected through a small number of customers and a significant delay or default in payment, particularly from REPs, could adversely affect us.

 

Our revenues from each of the transmission and distribution operations of our business are concentrated in a small number of customers. As of December 31, 2025, our revenues from our distribution operations are primarily collected from over 100 REPs that sell the electricity we distribute to end-use consumers in our certificated service area. REPs are generally noninvestment grade. Revenues from REP subsidiaries of our two largest customers collectively represented 25% and 21%, respectively, of our total operating revenues for the year ended December 31, 2025 and 25% and 23%, respectively, of our total operating revenues for the year ended December 31, 2024. We also collect network transmission revenues from nearly 40 different customers, consisting primarily of distribution companies, cooperatives and municipally-owned utilities. Currently, the majority of this network transmission customer revenue comes from customers who are investment grade and, as a result, are generally considered low credit risk.



If a REP cannot make timely payments, PUCT rules require that customers be shifted to another REP or a provider of last resort. Applicable PUCT regulations significantly limit the extent to which we can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and we thus remain at risk for payments related to services provided prior to the shift to another REP or the provider of last resort. While PUCT rules allow for the recovery of uncollectible amounts due from REPs (but not network transmission customers) through rates, such recovery is ultimately subject to PUCT approval.



Adverse economic conditions, structural problems in the market served by ERCOT or the financial difficulties of one or more customers could adversely impact the credit quality of our customers, impair the ability of these customers to pay for our services or could cause them to delay such payments. We depend on these customers to timely remit these revenues to us. Delays or defaults in payment from customers could materially and adversely affect our cash flows, liquidity, financial condition and/or results of operations, particularly in the event of any moratoriums on the ability of REPs to disconnect customers for nonpayment or other regulatory actions that impact our receipt of electricity delivery charges owed to us.



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We are dependent upon a limited number of suppliers and service providers, and disruptions in our supply chain or the availability of our suppliers to perform on expected or acceptable terms, could negatively impact us. 

 

We rely on a limited number of suppliers and service providers in certain circumstances to provide us with specialized materials and services, including for construction, maintenance and repair of electricity delivery facilities and power lines, information technology and customer operations. We often compete with other companies both in our industry and outside of our industry for materials and services from certain suppliers and service providers. The financial condition of our suppliers and service providers or their ability to perform has been, and may continue to be in the future, adversely affected by local, national and global events, including health epidemics or pandemics, climate change, severe weather events, natural disasters, supply chain issues, foreign policy and global trade restrictions, tariffs, executive orders, demand, wars, terrorist attacks, regulations, or general economic conditions, such as credit risk, commodity availability and pricing, inflation, labor availability and cost, and turbulent macroeconomic events. We have made a concerted effort where possible to expand the number of suppliers and service providers that provide us materials and services. Despite these efforts we may not be successful in mitigating our reliance on a limited number of suppliers and service providers. Furthermore, it may not be possible, efficient, or cost effective to expand the number of suppliers and service providers due to the standard of materials and services that we require and expect. Sourcing from additional suppliers and service providers could expose us to substandard quality of materials and services or substandard deliverables, which could result in missed deadlines, non-compliance with industry standards, or lower reliability metrics, each of which would have an adverse effect on our business, financial condition, results of operation, reputation and/or business prospects.



We have seen and expect to continue to see increased pricing from service providers and suppliers as a result of the contractor labor market, competition for equipment and materials, and longer lead times for delivery. Because many of the tasks of these suppliers and service providers require specialized electric industry knowledge and equipment, if any of these parties fails to perform or otherwise fully satisfy its contractual obligations, chooses not to renew contracts, goes out of business or otherwise becomes unable to perform on terms acceptable to us, or unexpectedly delays performance or increases the cost of performance, we may not be able to transition to substitute suppliers or service providers in a timely manner, on terms acceptable to us, or at all. This could delay our construction and improvement projects, increase our costs and/or disrupt our operations, which could negatively impact our business, financial condition, results of operations, cash flows, liquidity, reputation, corporate strategy, and/or business prospects. In addition, we could be subject to fines or penalties in the event a delay resulted in a violation of a PUCT or other regulatory order.

 

The delivery of components, materials, equipment and other resources that are critical to our business operations and corporate strategy has been, and may continue to be in the future, restricted by domestic and global supply chain challenges. Reduced availability of necessary materials, import/export restrictions, tariffs, and delays in delivery have delayed, and could continue to delay, maintenance, repair and construction projects, which have increased, and could continue to increase, costs and could also have an adverse impact on our reputation, capital plan, cash flows, liquidity, financial condition and/or results of operations. For example, in 2025, the current administration began implementing tariffs on materials and equipment that has impacted our suppliers. Our suppliers in many instances have shifted that increased cost directly to us. Additional or higher than anticipated costs in the future could have an adverse impact on our business, financial condition, results of operations, liquidity, and cash flows. International and political tensions as well as a decline in the manufacturing workforce could further exacerbate supply chain challenges. Increasing cost and availability of labor and inflation have also contributed to supply chain disruptions and higher construction and operating costs.

 

Disruptions in the insurance market could impact our ability to obtain coverage on reasonable terms, and insurance may not cover all potential losses.

 

Our ability to obtain insurance at rates we believe are commercially reasonable, and the cost of and coverage provided by such insurance, could be affected by events outside our control, including the willingness of insurers to provide such coverage. The occurrence of wildfires and other natural disasters, among other things, have had disruptive effects on insurance markets in recent years, particularly for electric utilities, making the process of obtaining insurance coverage increasingly more difficult and costly. In the future, the availability of insurance covering risks that we and other electric utilities typically insure against (including cyber liability insurance and excess liability insurance including wildfire coverage and litigation coverage) may decrease, and the insurance that we are able to obtain may have higher deductibles, higher premiums, and/or more restrictive policy terms. Further, the insurance policies may not cover all of the potential exposures or the actual amount of any loss incurred. Any losses not covered by insurance, or any increases in the cost of applicable insurance, could adversely affect our results of operations, financial position or cash flows.



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Our future success is dependent on our ability to identify, attract, develop and retain sufficient qualified personnel to meet our business needs, and failure to do so could adversely impact our operations.

 

Our future success will depend on our ability to continue to attract and retain highly qualified personnel, particularly in light of increases in our workforce over the next few years that we anticipate will be needed to meet the expected growth of our business. We compete for such personnel with many other companies, both in and outside our industry, as well as government entities and other organizations. Our workforce strategy to attract, develop, reward and retain a qualified workforce includes a market competitive total reward strategy along with strengthening and targeting recruiting efforts, upskilling supervisors, increasing customized talent development offerings and succession planning for critical roles to retain key talent and build succession strength for future leadership roles. However, we may not be successful in retaining our current personnel or in hiring or retaining qualified personnel, particularly in certain highly technical or specialized roles, in the future. In addition, we have incurred, and may continue to incur, increased costs in order to remain a competitive employer in a highly competitive labor market. Further tightening of the labor markets may adversely affect our ability to attract new personnel and retain existing personnel, which could adversely impact our operations. In addition, because of our reliance on the expertise of our senior management team, our future success depends in part on our ability to identify, retain and develop talent to succeed our senior management. Senior management succession planning is, and we expect it will continue to be, critically important to the successful implementation of our strategies.

 

As of December 31, 2025, approximately 13% of our employee population is retirement eligible and approximately 28% of our employee population, excluding interns, has worked with us for less than three years. Failure to adequately replace those retiring employees and transfer significant internal historical knowledge and expertise to new employees may adversely affect our business operations. In addition, limited availability of contract resources, could cause the cost of contract labor to rise.

 

Our revenues and results of operations are seasonal and significantly impacted by weather conditions and other electricity usage drivers.

 

A significant portion of our revenues is derived from rates that we collect from REPs based on the amount of electricity we distribute to end-use customers on behalf of such REPs. Deliveries of electricity to residential and commercial customers are influenced by time of year, fluctuations in temperature and other weather conditions. Thus, our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer season. Unusual weather patterns, including as a result of climate change or other factors, could significantly impact revenues.

 

Our business could be adversely affected by health epidemics and pandemics.

 

We face risks related to health epidemics and pandemics, which could lead to the disruption of our business operations by impacting the global economy and our employees, REPs, end-users, wholesale customers, network transmission customers, service providers, vendors and suppliers. These effects could also have a variety of adverse impacts on us, including reduced demand for electricity, delayed or delinquent customer payments to us (including as a result of end use customer failures to pay REPs and/or any state or national moratoriums on customer disconnections), slowed growth in our service territory, reduced availability or productivity of our workforce, constraints on our supply chain, increased supplier, labor and contractor costs, reduced labor or contractor availability, impairment of goodwill or long-lived assets, increased pension funding requirements due to a decline in pension asset values, impairment of our ability to develop, construct and/or operate our facilities, and impairment of our ability to access funds from financial institutions and capital markets.

 

The costs of providing pension benefits and OPEB and related funding requirements may have a material adverse effect on our financial condition, results of operations and cash flows.

 

We offer certain pension and health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees through pension plans and OPEB plans, and also have contractual obligations related to certain pension and OPEB benefits of eligible retirees of our former affiliates. See Note 9 to Financial Statements for more information regarding pension and OPEB obligations.

 

Our costs or share of the costs of providing pension and OPEB benefits and related funding requirements are dependent upon numerous factors, many of which are outside our control, assumptions and estimates and are subject to

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changes, including the market value of the assets funding the pension plans and OPEB plans and future benefit costs for pension plans and OPEB plans. Benefits costs and related funding requirements could also increase or decrease due to changes in employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, mortality assumptions, expected and actual earnings on plan assets, general interest rates, and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Significant unplanned increases in benefit costs could have an adverse impact on our financial condition, results of operations, and/or cash flows.

 

PURA provides for our recovery of pension and OPEB costs related to the regulated utility service of our employees as well as certain employees of our former affiliates, and we are authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings related to recoverable service. Amounts in these regulatory assets are ultimately subject to regulatory approval, and disallowance of any of these regulatory assets could have an adverse effect on our financial condition, results of operations and/or cash flows. At December 31, 2025 and 2024, we had recorded net regulatory assets (after taking into account related regulatory liabilities) totaling $247 million and $242 million, respectively, related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income. See Note 2 to Financial Statements for further information regarding these regulatory assets.

 

We regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets, and we may not be able to realize the anticipated benefits of any such acquisitions.

 

We regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets. Additional equity or debt capital may be required to complete any acquisition. In addition, any acquisition may be structured in such a manner that could result in the assumption of secured or unsecured debt and other liabilities. Any such transaction may require PUCT and other regulatory approvals. An acquisition may involve risks relating to the combination of assets and facilities, the diversion of management’s attention and the impact on our credit ratings or ratings outlook.

 

The growth of DER and similar technologies or actions that decrease demand or consumption of electricity we deliver may significantly adversely impact us.

 

The electric industry is undergoing significant technological change, particularly regarding development and availability of DER, alternatives to traditional transmission and distribution solutions such as distributed generation (including solar panels and microgrids), batteries and other energy storage, energy efficiency technologies, demand response technologies (such as electric vehicle-to-grid or vehicle-to-home solutions) and other grid management solutions. As DER usage continues to grow, it could reduce the amount of or alter the nature of electricity delivery usage and demand on our system, complicate the operation of our delivery system (such as by increased multi-directional power flow through use of aggregated DERs that may export power to the grid under ERCOT instruction), negatively impact the reliability of our system, or make investments in transmission and distribution infrastructure less desirable. Regulatory decisions made with respect to DER, including with respect to ERCOT market rules and transmission and distribution utilities’ ability to invest in non-traditional electricity delivery solutions, could adversely impact our costs, revenues, and operations. To the extent DER controlled by entities other than Oncor (including behind the meter alternatives and private use networks) become a more cost-effective or otherwise preferred option for certain customers, our revenues, financial condition, results of operations, cash flows, capital expenditures, and business prospects could be materially adversely impacted. Additionally, under the existing regulatory framework, DER usage could force us to spread costs over fewer customers, thereby increasing costs for those that do not have DER.

 

Also, electricity demand and usage could be reduced or modified by effective energy conservation or demand management by our customers. Such a reduction, absent regulatory changes related to how Oncor recovers investments in rates, could materially adversely impact our revenues, financial condition, results of operations and cash flows.

 

We may not be successful in our adoption of AI, which could adversely affect us.

 

We currently use AI in selective instances and are exploring additional uses of AI and its potential to enhance our operations. However, there are significant risks involved in developing and using AI, and there can be no assurance that the use of AI will enhance our operations or be beneficial to our business. Furthermore, our AI-related efforts may give rise to new or different risks including those related to harmful content, accuracy, bias, discrimination, intellectual property

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infringement or misappropriation, defamation, data privacy, and cybersecurity, among others. In addition, the adoption of AI may subject us to new or enhanced governmental or regulatory scrutiny, new or amended laws, rules, directives, and regulations governing the use of AI, litigation, ethical concerns, negative public perception, or other complications that could adversely affect our business, reputation, or financial results. Similarly, as AI continues to evolve, we may not be able to adopt and implement AI as quickly as our customers or communities desire or regulators may require, which could also adversely affect us. AI is a relatively new and rapidly evolving technology, and we are unable to predict all of the risks that may result from the adoption of AI initiatives.

 

Goodwill that we have recorded on the balance sheet is subject to at least annual impairment testing, and as a result, we could be required to write off all or a portion of this goodwill, which may adversely impact our reported financial condition and results of operations.

 

In accordance with accounting standards, recorded goodwill is not amortized but is tested for impairment annually, or more frequently if certain conditions exist. Any impairment of all or a portion of the value of goodwill will result in a charge against current earnings, which may adversely impact our reported financial condition and results of operations. See Note 1 to Financial Statements for more information on our goodwill impairment assessment and testing.

 

Risks Related to Financial and Market Matters

 

Adverse actions with respect to our credit ratings or ratings outlook could negatively affect our cost of debt and our ability to access capital.

 

Our access to U.S. and foreign capital and credit markets and our cost of debt could be directly affected by changes in our credit ratings or ratings outlook. Regulatory or legislative actions (particularly any affecting our ability to recover costs or earn an adequate return), changes in our financial performance, our capital expenditures plan, liquidity needs, extreme weather events and wildfires, as well as unfavorable conditions in the capital and credit markets, among other things, could result in credit agencies changing our credit ratings or ratings outlook. In addition, specific regulatory decisions with respect to us or other utilities comparable to us could also have an impact on our credit ratings or ratings outlook. For example, rating agencies have noted that in Texas, regulators have mandated equity ratios significantly lower than the national average for rate-making purposes and this reflects unfavorably in our credit metrics. In addition, one rating agency lowered our credit ratings in July 2025 citing elevated wildfire risk as a result of changing climate conditions and the lack of certain legal protections available to us for wildfire litigation in Texas. Adverse action with respect to our credit ratings or ratings outlook generally causes debt issuance and borrowing costs to increase and the potential pool of investors and funding sources to decrease. Our Credit Facilities also provide that interest rates charged for borrowings and commitment fees on undrawn amounts may be adjusted based on our credit ratings.

 

In addition, most of our large suppliers and counterparties require an expected level of creditworthiness. If there is an adverse action with respect to our credit ratings or ratings outlook, the costs to operate our business could increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with us. In addition, if there is any adverse action with respect to our credit rating or ratings outlook which causes our borrowing costs to increase, we may not be able to recover such increased costs if they exceed our cost of debt as approved by the PUCT in our most recent base rate review or subsequent base rate reviews.

 

Certain of our credit ratings are currently higher than those of Sempra, our indirect majority equity owner. If credit rating agencies were to change their views of our independence from Sempra and its affiliates (other than the Oncor Ring-Fenced Entities), our credit ratings or ratings outlook could decline. Despite our ring-fencing measures, rating agencies have in the past taken, and could in the future take, an adverse action with respect to our credit ratings or ratings outlook in response to activities involving financing and liability management activities by our indirect majority equity owner.

 

Market volatility may impact our business and financial condition in ways that we currently cannot predict.

 

We expect to rely on access to U.S. and foreign financial markets as a significant source of funding for capital requirements. It is likely we will incur additional debt in connection with our large capital expenditure projections, which include continuing significant investments in transmission and distribution infrastructure. Our ability to access the capital, credit, or commercial paper markets may be severely restricted, or limited entirely, due to market conditions at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. Any such adverse market conditions could be due to circumstances completely outside

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of our control, such as a recession, depressed economic conditions, interest rates, political instability, pandemics, inflation, war, terrorism, sanctions, bank failures, or extreme volatility. In addition, the cost of debt financing may be materially and adversely impacted by changes in general interest rates. In 2025, we saw increased borrowing costs continue due to elevated interest rates. Disruptions in the banking sector could increase the cost of capital and reduce our access to capital, lines of credit, and certain financing options. Even if we are able to obtain debt financing, we may be unable to recover in rates some or all of the costs of such debt financing if they exceed our cost of debt as approved by the PUCT in our most recent base rate review or subsequent base rate reviews, which could adversely affect our earnings and cash flows. Fluctuations in actual market returns, as well as changes in general interest rates may also result in increased or decreased employee/retiree benefit costs in future periods. Additionally, disruptions in the financial markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, slowing growth in our service territory, payment defaults by REPs or other customers, or failure by our suppliers to perform their contractual obligations, which could have a negative impact on our revenues, financial condition or results of operations, or have an impact on our customers, counterparties and/or lenders, causing them to fail to meet their obligations to us.

 

We use derivative instruments to manage our interest rate exposure related to our forecasted issuances of debt and foreign currency exchange rate exposure on our foreign currency denominated debt. Derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, particularly during periods of market volatility, resulting in financial losses. We could also recognize financial losses if a counterparty fails to perform its obligations under the derivative instrument. While these risks are managed through a risk management strategy, that strategy may not work as planned and we cannot entirely eliminate the risks associated with these activities. See Note 11 to Financial Statements for additional information regarding derivative financial instruments.

 

Our significant capital needs could be difficult to satisfy under some circumstances, including existing limitations on our ability to incur indebtedness and uncertain financial market conditions.

 

Our operations are capital intensive. We expect to rely on access to U.S. and foreign financial markets as a significant source of funding for capital requirements not satisfied by cash-on-hand, operating cash flows, our Credit Facilities, the Term Loan Credit Agreement, the CP Program, or our AR Facility. We have also historically retained earnings that could have been distributed to our members and invested them in the business. In addition, we have regularly received capital contributions from our members and expect to continue to seek member capital contributions in the future. However, our LLC Agreement provides that no member may be required to make any additional capital contributions to us.

 

The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty, could adversely impact our ability to sustain and grow our business and would likely increase capital costs that may not be recoverable through rates. Accordingly, there can be no assurance that the capital, credit, and commercial paper markets will continue to be a reliable or acceptable source of short-term or long-term financing for us. Additionally, we may not be able to access certain financing products as a result of our governance structure, including the terms of our LLC Agreement. Our access to the capital, credit, and commercial paper markets, our Credit Facilities and our AR Facility, and the pricing and terms we receive in the financial markets, could be adversely impacted by various factors, such as:

 

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We are also subject to certain limitations on our ability to incur indebtedness. We are required to maintain a regulatory capital structure at or below the debt-to-equity ratio established periodically by the PUCT for ratemaking purposes. Currently, our authorized regulatory capital structure set by the PUCT is 57.5% debt to 42.5% equity. At December 31, 2025, our regulatory capital structure was 56.3% debt to 43.7% equity. Our ability to incur additional long-term debt is limited by our authorized regulatory capital structure and we are able to issue future long-term debt only to the extent that such issuance would not cause our regulatory capital structure to exceed the authorized regulatory debt-to-equity ratio. In addition, certain of our debt agreements contain debt-to-capital ratio covenants that effectively limit our ability to incur indebtedness in the future.



Our ring-fencing measures may not work as planned, which may result in a bankruptcy court subjecting Oncor to the claims of its affiliates’ creditors.

 

Various ring-fencing measures have been taken to enhance our credit quality and the separateness between the Oncor Ring-Fenced Entities and entities with a direct or indirect ownership interest in Oncor or Oncor Holdings. These enhancements are intended to minimize the risk that a court would order any of the Oncor Ring-Fenced Entities’ assets and liabilities to be substantively consolidated with those of Sempra or any of its affiliates or any other direct or indirect owners of Oncor or Oncor Holdings or their affiliates in connection with a bankruptcy of any such entities. Substantive consolidation is an equitable remedy in bankruptcy that results in the pooling of the assets and liabilities of the debtor and one or more of its affiliates solely for purposes of the bankruptcy case, including for purposes of distributions to creditors and voting on and treatment under a reorganization plan. Bankruptcy courts have broad equitable powers, and as a result, outcomes in bankruptcy proceedings are inherently difficult to predict. To the extent a bankruptcy court were to determine that substantive consolidation is appropriate under the facts and circumstances, then the assets and liabilities of any Oncor Ring-Fenced Entity that is subject to the substantive consolidation order would be available to help satisfy the debt or contractual obligations of the affiliated entity that is a debtor in bankruptcy and subject to the same substantive consolidation order. If any Oncor Ring-Fenced Entity were included in such a substantive consolidation order, the secured creditors of Oncor would retain their liens and priority with respect to Oncor’s assets. See “Items 1. and 2. Business and Properties—Ownership Structure and Ring-Fencing Measures” for additional information on our ring-fencing measures.

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Item 1B.UNRESOLVED STAFF COMMENTS



None.



Item 1C.CYBERSECURITY



Maintaining a robust cybersecurity strategy to safeguard and protect the confidentiality, integrity and availability of our critical infrastructure assets as well as all other information systems and the information residing in them is critically important to our business. We face various cyber threats, including malware intrusion, computer viruses, unauthorized access attempts, ransomware attacks, social engineering attacks, hacktivism and potential insider threats. In addition to the cybersecurity threats faced by any business with a cyber presence, as an owner and operator of critical infrastructure assets, we are subject to cybersecurity threats from domestic and foreign threat actors who wish to disrupt our electricity delivery operations and/or the ERCOT bulk power grid. With an ever-increasing share of our operational and administrative activity being dependent on our information systems, we strive to create a company-wide culture of cyber safety that continually monitors risk.



Our Cybersecurity Strategy



Our cybersecurity strategy is built on “defense-in-depth” as recommended by the National Institute of Standards and Technology. We have processes in place to identify, assess, and manage material risks from cybersecurity threats. We have developed and implemented, and we continue to develop and implement, protective measures to reduce risk, manage incidents, and sustain our security posture. For example, in our efforts to lower the risk of ransomware attacks, we have increased our cybersecurity operations by strengthening our defense-in-depth approach to protections and controls, operational resiliency, cyber hygiene and monitoring. Specific steps include tool deployments to mitigate ransomware threats and impacts, as well as implementation of practices and enhancements to minimize the risk of ransomware launching and spreading across the organization. These efforts also include the ongoing identification, review and mitigation of vulnerabilities to our owned or operated systems. An additional protective measure to reduce risk with respect to the unauthorized access to confidential and sensitive data in Oncor’s possession includes our data risk management (DRM) program. Our DRM program focuses on data loss prevention, including as the result of unauthorized access or acquisition, by taking proactive steps to limit confidential and sensitive information from being managed or distributed electronically in an unsecure manner. Led by our executive leadership team, as well as a governance committee and operational stakeholders, our DRM group provides formal guidance, including policies and standards, to reduce our data risk. We continue to participate, review, assess and adjust our mix of activities to improve our grid operations, digital perimeter security and information security. For example, we continuously evaluate and implement additional governance focused defensive measures as a result of National Institute of Standards and Technology guidance.



We have policies and procedures in place to identify, protect, detect, respond and recover from cybersecurity incidents. The life cycle of our incident response includes: (i) preparation through employee training and drills, including regular simulation exercises that include management from various departments in addition to representatives from our information technology security team; (ii) detection and analysis of the cybersecurity incident; (iii) assembling the appropriate response team and escalating the incident to the appropriate parties internally and externally; (iv) containment, eradication, recovery and monitoring; and (v) post incident activity to document the root cause and discuss areas of improvement.



In accordance with our policies and procedures, we investigate any technological, computer, or network security event or incident within our networks or involving confidential and sensitive data maintained by Oncor, including events or incidents involving third-party vendors that interface with our networks or otherwise hold confidential and sensitive data maintained by Oncor. With respect to certain of our third-party vendors, we may also require such third-party vendors to notify us of any cybersecurity incidents and/or vulnerabilities that may impact our operations or involve confidential and sensitive data maintained by Oncor. Multiple security operations centers monitor our digital environment at all times for anomalies, threats, and indicators of compromise. We have a variety of tests performed by internal and external parties related to the integrity of our networks, cyber protections and policies and procedures. Third-party and internal security testing of our network, applications, perimeter, physical equipment and other areas of security are used to test cybersecurity readiness. When a cybersecurity threat either newly materializes or escalates, we elevate communication both internally and externally to ensure situational intelligence is both known and shared to help in defending against that threat.



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We are also subject to mandatory and enforceable regulatory standards for critical infrastructure protection, which include cybersecurity-related standards. We are subject to periodic audits by Texas RE of our compliance with critical infrastructure protection standards. In addition, we are required to file an emergency operation plan with the PUCT, including our procedures relating to addressing cyber incidents.



We also participate in, and work with, multiple federal, state, industry, and academic groups dedicated to cybersecurity, such as the U.S. Department of Homeland Security’s Cybersecurity & Infrastructure Security Agency, the Federal Bureau of Investigations’ InfraGard, an ERCOT critical infrastructure protection working group, the Electricity Information Sharing and Analysis Center, and the Texas Information Sharing and Analysis Organization. This includes information-sharing and coordination with ERCOT, the PUCT, and other ERCOT market participants with a view toward protecting and enhancing the ERCOT grid from cyber and physical attacks and response preparation. In addition, we participate on various technical and advisory boards, such as the advisory board of the Energy Sector Security Consortium, Inc., a nonprofit organization that supports energy sector organizations with the security of their critical technology infrastructures, and the Electricity Subsector Coordinating Council. We believe that our participation and membership within these groups and organizations contributes to security improvements that directly impact our cyber operations.



We believe that cyber safety is everyone’s responsibility at Oncor. We take proactive steps to train, re-train, educate and test our workforce on cyber safety practices and work to strengthen the cyber community within our company. We require an annual cybersecurity training of all credentialled individuals, and each year we hold an annual cyber awareness month, which includes informational events, speakers and additional training resources to increase our workforce’s engagement in cyber safety.



 While we have not experienced a cybersecurity incident to date that has had a material impact on Oncor, we have experienced, and expect to continue to experience, threats and attempted intrusions into our technology systems and platforms. Our third-party vendors have been subject, and will likely continue to be subject, to acts that disrupt or attempt to disrupt the services they provide to us. Our technology team works to evaluate third-party solutions purchased, implemented or upgraded to ensure they meet our cybersecurity requirements. Threat actors could also attempt to use our third-party vendors as a conduit to attack us. We are subject to evolving cyber risks related to adversaries attacking our technology infrastructure and platforms and the technology infrastructure and platforms of third-party vendors. See “Item 1A. Risk Factors—Risk Related to Our Business and Operations—Cyber-attacks on us or our third-party vendors could disrupt business operations, initiate the loss or disclosure of critical operating or confidential data, adversely impact our reputation, and expose us to significant liabilities.” A future cybersecurity incident could potentially have a material impact on our business, operations and financial condition. In addition, non-compliance with electric industry specific regulations or violation of laws could have financial penalties, as well as impact our reputation, which could materially impact our results of operations or financial condition. Cybersecurity risk has also contributed to, and is expected to continue to contribute to, increased capital expenditures and operation and maintenance expenses, including as a result of the need for additional hardware, software, equipment, personnel, training and third-party service providers, as well as increased cyber insurance costs.



Our Cybersecurity Team



Our management is responsible for assessing, managing and mitigating all risks relative to our business, including material risks from cybersecurity threats. Within our management team, assessment, management, and mitigation of cybersecurity threats is primarily overseen by our technology group, which has extensive experience in cybersecurity, technology, and digital grid operations. Our technology group is led by Joel Austin, our senior vice president and chief digital officer, and Malia Hodges, our senior vice president and chief information officer. Mr. Austin has nearly 40 years of technology operations, utility industry, and leadership experience, including nearly 20 years of cybersecurity oversight experience. Ms. Hodges has more than 25 years of technology operations, utility industry, and leadership experience, including nearly 10 years as our chief information officer, with responsibility in that role for management of Oncor’s technology function, including cybersecurity. Both Mr. Austin and Ms. Hodges are long-time members of the Edison Electric Institute security and technology policy committee, which focuses on working with federal agencies on cybersecurity risks relevant to the electric industry. Mr. Austin has testified on cybersecurity issues facing the State of Texas and the electric utility industry in front of multiple Texas legislative sub-committees and been asked to discuss cybersecurity risks with members of the U.S. Congress. Mr. Austin and Ms. Hodges also work closely and regularly with PUCT staff and PUCT commissioners on cybersecurity risks and mitigations. We have recently created a new vice president of technology operations position that is focused on further enhancing our cyber and digital grid security and operations. Our vice president of technology operations has over 40 years of experience in the utility and technology

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industries, including implementing and overseeing our programs designed to protect our digital grid and critical infrastructure. Additionally, we have a designated chief information security officer who has over 40 years of experience in cybersecurity, a master’s degree in cybersecurity and a doctorate degree in cybersecurity/information assurance. Within our technology group, we maintain a dedicated cybersecurity group and 24/7/365 team that responds to and protects against cybersecurity risks. Our collective cybersecurity staff consists of a group of employees and contractors located inside and outside the state of Texas with a wide range of specialized skills and experience, including through service in the U.S. military and federal agencies, cybersecurity-related certifications, membership and advisory and board positions with industry groups and non-profit organizations focused on cybersecurity, and training in the cyber defense tools and methods we deploy, as well as various higher education degrees related to cybersecurity.



Governance



Cybersecurity risk is considered a significant corporate risk by management. Our technology security team provides our management with a weekly cyber update that discusses cybersecurity threats impacting Oncor. Management of our cybersecurity risks begins at the individual employee level, with each employee having responsibility for operating in a cyber safe manner, and flows up to our board of directors, which has overall oversight over Oncor’s corporate risk management efforts. The board of directors has delegated its risk management oversight to the Audit Committee, whose charter provides that it is responsible for discussing with management our major risk exposure, and the steps management takes to monitor and control such exposure, including our risk assessment and risk management process, guidelines, policies and practices.



Our senior leadership team, which includes Mr. Austin and Ms. Hodges, has established a risk management framework to actively manage, mitigate and report on the various risks faced by Oncor. Pursuant to that framework, as frequently as necessary, but not less than quarterly, members of our senior leadership team and additional members of management meet to review and assess various operational, functional, legal and other types of risks facing the company, including risks related to cybersecurity. Discussions at these risk management forums include mitigation strategies and actions to provide oversight and assign responsibility for ongoing treatment and monitoring each specific risk. Risk management information collected at these meetings is then distributed at least quarterly to the Audit Committee and/or our full board of directors. In addition, our risk management efforts, including risks related to cybersecurity, are reported on to the Audit Committee and/or the full board of directors at least quarterly. Mr. Austin and Ms. Hodges also provide separate written reports on cybersecurity risks and activities to both the Audit Committee and the full board of directors, with specific discussion time devoted to cybersecurity at the Audit Committee and/or the full board of directors at least quarterly.



Item 3.LEGAL PROCEEDINGS



For a discussion of material regulatory proceedings, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulation and Rates—Regulatory Matters.” We are also involved in other legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations, or cash flows. 



Item 4.MINE SAFETY DISCLOSURES



Not applicable.

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PART II



Item 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES



At December 31, 2025, 80.25% of our membership interests were held by Oncor Holdings and 19.75% were held by Texas Transmission. For information on beneficial ownership of our membership interests, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” None of the membership interests are publicly traded, and none were issued by Oncor in 2025.  



See Note 8 to Financial Statements for a description of cash capital contributions and distributions between us and our members.



Item 6.RESERVED



Item 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



The following discussion and analysis of our financial condition and results of operations for the fiscal years ended December 31, 2025 and 2024 should be read in conjunction with our audited consolidated financial statements and the notes to those statements as well as “Item 1A. Risk Factors.”



Our Annual Report on Form 10-K for the year ended December 31, 2024 includes a discussion and analysis of our financial condition and results of operations for the year ended December 31, 2023 in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



All dollar amounts in the tables in the following discussion and analysis are stated in U.S. dollars in millions and/or in millions of the applicable foreign currency unless otherwise indicated.



BUSINESS



We are a regulated electricity transmission and distribution company. We operate the largest transmission and distribution system in Texas based on the number of end-use customers and circuit miles of transmission and distribution lines, delivering electricity to more than 4.1 million homes and businesses and operating more than 145,000 circuit miles of transmission and distribution lines at December 31, 2025, all with a focus on safety, reliability, and affordability. For more information on our business, see “Items 1. and 2. Business and Properties.”



Ring-Fencing Measures



We are a direct, majority-owned subsidiary of Oncor Holdings, which is indirectly and wholly owned by Sempra. Oncor Holdings owns 80.25% of our membership interests and Texas Transmission owns 19.75% of our membership interests.



Since 2007, various ring-fencing measures have been taken to enhance our credit quality and the separateness between the Oncor Ring-Fenced Entities and entities with a direct or indirect ownership interest in Oncor or Oncor Holdings. These ring-fencing measures serve to mitigate the Oncor Ring-Fenced Entities’ credit exposure to Sempra and its affiliates and any other direct or indirect owners of Oncor and Oncor Holdings, and reduce the risk that the assets and liabilities of the Oncor Ring-Fenced Entities would be substantively consolidated with the assets and liabilities of any Sempra entity or any other direct or indirect owners of Oncor and Oncor Holdings in connection with a bankruptcy of any such entities. Such measures include, among other things: the 19.75% equity interest held by Texas Transmission; maintenance of separate books and records for the Oncor Ring-Fenced Entities; and our board of directors being comprised of a majority of Disinterested Directors. As a result, none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or obligations of any Sempra entity or any other direct or indirect owner of Oncor or Oncor Holdings. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of any Sempra entities and any other direct or indirect owner of Oncor or Oncor Holdings. We do not bear any liability for debt or contractual obligations of Sempra and its affiliates or any other direct or indirect owner of Oncor or Oncor Holdings, and vice versa. Accordingly, our operations are conducted, and our cash flows are managed, independently from Sempra and its affiliates and any other

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direct or indirect owner of Oncor or Oncor Holdings. For more information on the ring-fencing measures, see “Items 1. and 2. Business and Properties—Ownership Structure and Ring-Fencing Measures.”



Significant Activities and Events



2025 Comprehensive Base Rate Review (PUCT Docket No. 58306)  — In June 2025, we filed a request for a comprehensive base rate review with the PUCT and the 210 cities in our service territory that have retained original jurisdiction over rates. On January 29, 2026, we filed a stipulation in the comprehensive base rate review proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. See Note 2 to Financial Statements and “—Regulation and Rates—Regulatory Matters” below for a discussion of the comprehensive base rate review.



UTM — On June 20, 2025, Texas House Bill 5247 (HB 5247) was signed into law and became effective. The bill establishes the UTM, which allows qualifying electric utilities to apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments, as an alternative to separate DCRF and TCOS capital tracker filings. We anticipate filing our initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result have recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. We also currently anticipate requesting interim TCRF updates through our UTM applications. See Notes 2 and 3 to Financial Statements and “—Regulation and Rates—State Legislation” below for more information on the UTM and our recognition of revenues and recording of regulatory assets following the enactment of HB 5247.



Debt-Related Activities —  See “—Financial Condition—Liquidity and Capital Resources” below and Notes 5 and 6 to Financial Statements for information regarding our debt-related activities.



KEY FACTORS RELATING TO FUTURE EARNINGS AND RESULTS OF OPERATIONS



Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including certain key risks and challenges facing management discussed below. For additional information concerning risks related to our business, see “Item 1A. Risk Factors” in this report.



Regulation, Rates and Cost Recovery



The rates we charge for our electricity delivery services are set pursuant to tariffs approved by the PUCT and certain cities and, in the case of transmission service related to limited interconnections to other markets, the FERC. Our rates are subject to regulatory rate-setting processes and earnings oversight. This regulatory treatment does not provide assurance as to achievement of earnings levels or recovery of actual costs. Our rates are based on an analysis of our costs and capital structure in a designated historical test year, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT in a base rate review will judge any of our costs, including invested capital and costs included in a regulatory asset reported on the balance sheet, to have been prudently incurred and therefore fully recoverable. For example, in 2023 we recorded a charge against net income for a write-off of certain rate base disallowances in a comprehensive base rate review proceeding. The levels and timing of any approved recovery could also significantly differ from our requests. In addition, since rate recovery requests are made after spend on investment-related costs and operating costs have occurred, there is no assurance that our rates will produce recovery of our costs in line with amounts spent after test year periods and/or the full return on invested capital allowed by the PUCT, particularly during periods of increased capital spending by us, high inflation, increases in general interest rates, increases in insurance premiums or other situations resulting in increased costs incurred by us after our most recent base rate review.



We are required by PUCT rules to file a comprehensive base rate review within four years of the last order in our most recent comprehensive rate proceeding, unless an extension is otherwise approved by the PUCT.  However, the PUCT or any city retaining original jurisdiction over rates may direct Oncor to file a base rate review, or Oncor may voluntarily file a base rate review, any time prior to that deadline. In June 2025, we voluntarily filed a request for a comprehensive base rate review earlier than required. On January 29, 2026, we filed a stipulation in the comprehensive base rate review

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proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. The PUCT may choose to adopt, modify, or reject the stipulation and the proposed order included in the stipulation. See Note 2 to Financial Statements and “—Regulation and Rates—Regulatory Matters” below for a discussion of the comprehensive base rate review.



In between comprehensive base rate reviews, we are eligible to file capital trackers that help shorten the regulatory lag associated with recovery of transmission and distribution investments through regulated rates. PUCT rules allow for interim rate adjustments for these capital trackers that allow utilities to recover, subject to reconciliation, the cost of certain investments before a comprehensive base rate review. As a result of legislation signed into law in 2025 establishing the UTM, we can now through 2035 request capital tracker interim rate adjustments each year through the filing of either (i) a single UTM application (subject to meeting annual eligibility requirements) or (ii) up to two TCOS capital tracker applications for changes in transmission-related capital investments and up to two DCRF capital tracker applications for changes in distribution-related capital investments. It also allows utilities to defer to a regulatory asset all costs, including depreciation expense, taxes, and carrying costs, as soon as the capital investments are placed into service, as compared to the pre-UTM capital tracker process of beginning recovery for capital investments only upon issuance of a final order in a capital tracker proceeding. We anticipate filing our initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result have recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues.



All investments included in a capital tracker update application are ultimately subject to prudence review by the PUCT in the next comprehensive base rate review after such assets are put into service, with a potential for the PUCT to also order refunds of previously collected amounts if a particular investment or related costs are found to be imprudent or inappropriately included in an interim rate adjustment.



Capital tracker rate adjustment applications include related updates of billing units arising from changes in customer growth and demand, whether positive or negative. Distribution billing units reflect the electricity demand or delivery volumes of our distribution end-use customers and transmission billing units reflect certain changes in average ERCOT-wide peak electricity demand. Regardless of whether a capital tracker is filed, billing unit changes will result in a variation of transmission and distribution base revenues and such changes in annual billing units could mitigate the need to file capital tracker applications.



The rate-setting and cost-recovery process is intended to provide revenues to recover the cost of providing electricity delivery service and a return on and recovery of our investment in rate base assets. As a result, management closely monitors our regulatory rate base and the capital expenditure budget which historically has increased our rate base. Our capital expenditure projections through 2030 are largely tied to expected continued ERCOT growth, particularly new transmission projects to meet that growth, as well as customer transmission interconnection projects and measures to maintain reliability on the system. The amounts we earn, particularly with respect to retail delivery services, are heavily impacted by the amount of electricity we deliver. Management monitors various drivers that could impact electricity consumption or demand on our system. Such drivers include weather, premise growth, ERCOT electricity demand growth, customer transmission interconnection requests, number of end use customers, and average customer usage and demand. In recent years, ERCOT has seen increasing population, business, and demand growth, and we expect growth in the number of customers we serve and volumes of electricity we deliver to continue as ERCOT growth continues. See “Items 1. and 2. Business and Properties—Oncor’s Market” for more information regarding ERCOT projected growth.



Except in certain instances, we are required to file an earnings report annually with the PUCT that includes our estimated regulatory rate base (representing total invested capital in service, as adjusted in accordance with PUCT rules) at the end of the previous calendar year. Our regulatory rate base as reported in these filings as of December 31, 2024 and 2023 was $26.6 billion and $23.1 billion, respectively. As calculated on a similar basis, our estimated regulatory rate base at December 31, 2025 was $31.5 billion. The increase in rate base in each of the last three years over each prior year reflects the significant capital investments we have made, and we expect rate base to continue to increase in 2026 and beyond based on Oncor’s anticipated capital investments. See “—Financial Condition—Liquidity and Capital Resources” for more information regarding our anticipated capital expenditures.



In addition to rate regulation and earnings oversight as discussed above, our business is subject to numerous other complex governmental regulations and legislation, which has materially impacted our business in the past and could materially impact our business in the future. In addition, public perception regarding us, our industry and our business

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priorities could influence regulations, administrative actions and legislation. See “Item 1A. Risk Factors—Risks Related to Regulatory and Legislative Matters” for further discussion of regulatory and legislative risks and “—Regulation and Rates” below for further information on legislative and regulatory matters.



Weather



Weather is a significant driver of distribution base revenues, as increased cooling and heating needs generally result in higher electricity consumption. As a result, management closely monitors weather and its potential impact on our financial performance. The exact amount of revenue variation due to weather is difficult to measure due to other electricity usage drivers that contribute to revenues. With continued growth in our transmission and distribution system and unusual weather patterns, including those that may be impacted as a result of climate change and other factors, we cannot predict how much the variation to our distribution base revenues due to weather could be in the future. See “—Results of Operations” below for information on volumes of electricity delivered, heating and cooling degree days and a discussion of distribution base revenues and revenues contributing to earnings and “Item 1A. Risk Factors—Risks Related to Our Business and Operations—Our revenues and results of operations are seasonal and significantly impacted by weather conditions and other electricity usage drivers.”



Significant storms and other emergency events that cause extensive damage on our system or affect electric capacity in the ERCOT market could result in unexpected challenges, including negative public perception, disruptions in our ability to provide electricity delivery services, regulatory and legislative actions, and increased maintenance expenses or capital expenditures. See “Item 1A. Risk Factors—Risks Related to Our Business and Operations—Severe weather, natural disasters, and other related phenomena have in the past and could in the future adversely impact us, and climate change could make such phenomena more prevalent and unpredictable,” for discussion of the potential impact significant storms could have on our business. Storm related costs are generally recorded as a regulatory asset and our ability to recover any amounts included in those regulatory assets in rates as well as the time period for such recovery is subject to PUCT review and approval.



Capital Availability and Cost



Our business is capital intensive and we expect to rely on access to financial markets as a significant source of funding. Our access to the capital, credit, or commercial paper markets and cost of any such debt could be directly affected by our credit ratings, ratings outlook and financial market conditions. Any adverse action with respect to our credit ratings could generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease. Certain of our credit ratings are currently higher than those of Sempra. If credit rating agencies were to change their views of our independence from Sempra and its affiliates (other than the Oncor Ring-Fenced Entities), our credit ratings could change. We believe this risk is substantially mitigated by the ring-fencing measures as described in Note 1 to Financial Statements. See “Item 1A. Risk Factors—Risks Related to Financial and Market Matters—Adverse actions with respect to our credit ratings or ratings outlook could negatively affect our cost of debt and our ability to access capital,” and “Item 1A. Risk Factors—Risks Related to Financial and Market Matters—Our significant capital needs could be difficult to satisfy under some circumstances, including existing limitations on our ability to incur indebtedness and uncertain financial market conditions.”  



In addition, we may be unable to recover in rates some or all of the costs of any such debt financing if they exceed our cost of debt approved by the PUCT in our most recent base rate review or subsequent base rate reviews, which could adversely affect our earnings and cash flows.

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CRITICAL ACCOUNTING ESTIMATES



Our significant accounting policies are discussed in Note 1 to Financial Statements. We prepare our financial statements in accordance with GAAP governing rate-regulated operations. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting estimates that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.



Accounting for the Effects of Certain Types of Regulation



We are subject to rate regulation and our financial statements reflect regulatory assets and liabilities in accordance with accounting standards related to the effect of certain types of regulation (ASC 980). Regulatory assets and liabilities represent probable future amounts recoverable from or refundable to customers through the ratemaking process based on PURA and/or the PUCT’s orders, precedents, or substantive rules. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital subject to PUCT review for reasonableness. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 2 to Financial Statements for more information regarding regulatory assets and liabilities.



Accounting for the Effects of Income Taxes



Our tax sharing agreement with Oncor Holdings, STH and Texas Transmission provides for the calculation of amounts related to income taxes for each of Oncor Holdings and Oncor substantially as if these entities were taxed as corporations and requires payments to the members determined on that basis (without duplication for any income taxes paid by a subsidiary of Oncor Holdings).



We are a partnership for U.S. federal income tax purposes. Accordingly, while partnerships are not subject to income taxes, in consideration of the presentation of our financial statements as an entity subject to cost-based regulatory rate-setting processes with such costs historically including income taxes and the tax sharing agreement, the financial statements present amounts determined under the tax sharing agreement as “provision in lieu of income taxes” and “liability in lieu of deferred income taxes.” Such amounts are determined in accordance with the provisions of the accounting guidance for income taxes and accounting standards that provide interpretive guidance for accounting for uncertain tax positions and thus differences between the book and tax bases of assets and liabilities are accounted for as if we were a stand-alone corporation. In the event such amounts are not paid under the tax sharing agreement, it is probable that this regulatory liability will continue to be included in Oncor’s rate setting processes.



Our expense amounts related to income taxes and related balance sheet amounts are recorded pursuant to our tax sharing agreement, as discussed above. Recording of such amounts involves significant management estimates and judgments, including judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of assets related to income taxes, management considers estimates of the amount and character of future taxable income. Actual amounts related to income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Our income tax returns, as well as the STH Texas margin tax returns in which we are consolidated filers, are regularly subject to examination by applicable tax authorities. In management’s opinion, any liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future amounts that may be owed as a result of any examination. There were no significant changes in estimates or assumptions in the accounting for the effects of income taxes during 2025.



Amounts payable to and receivable from our members related to income taxes on our balance sheet reflect our tax provision net of quarterly estimated tax payments required by the tax sharing agreement that are trued up the following year when the annual tax return is filed.



See Notes 1 and 4 to Financial Statements for additional information.



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Impairment of Long-Lived Assets and Goodwill



We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The evaluation of our goodwill and other long-lived assets for which uncertainty exists regarding the recoverability of the carrying value of such assets involves the assessment of future cash flows and external market conditions and other subjective factors that could impact the estimation of future cash flows including, but not limited to, the amount and timing of future cash flows, future growth rates and the discount rate. Unforeseen events and changes in circumstances or market conditions could adversely affect these estimates, which could result in an impairment charge in the event regulatory recovery is not allowed.



We also evaluate goodwill for impairment annually, as of October 1, and whenever events or changes in circumstances indicate that an impairment may exist. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows.



For our annual goodwill impairment testing, we generally have the option to directly perform a quantitative assessment or first make a qualitative assessment of whether it is more likely than not that our estimated enterprise fair value is less than our enterprise carrying value before applying the quantitative assessment. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors and our overall financial performance. If, after assessing these qualitative factors, we determine that it is more-likely-than-not that our estimated enterprise fair value is less than our enterprise carrying book value, then we perform a quantitative assessment. If, after performing the quantitative assessment, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of enterprise carrying book value over estimated enterprise fair value, not to exceed the carrying amount of goodwill.



For our annual goodwill impairment testing as of October 1, 2025, we elected to make a qualitative assessment of whether it is more likely than not that our estimated enterprise fair value is less than our enterprise carrying value. We concluded that our estimated enterprise fair value was more likely than not greater than our enterprise carrying book value. As a result, no quantitative assessment for impairment was required and no impairment was recognized in 2025.



Goodwill totaling $4.740 billion was reported on our balance sheet at each of December 31, 2025 and 2024.



Defined Benefit Pension Plans and OPEB Plans



We offer certain pension, health care and life insurance benefits to eligible employees (and certain eligible former employees of our former affiliates whose service was partially assigned to Oncor in connection with the deregulation and disaggregation of the Texas electric market in 2002) and their eligible dependents upon the retirement of such employees as we discuss in Note 9 to Financial Statements. We are authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in our PUCT-approved billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings related to recoverable service. Accordingly, we recognize (principally as a regulatory asset or property) additional recoverable pension and OPEB costs consistent with PURA. Net regulatory assets related to our pension and OPEB costs increased $5 million during 2025. Amounts deferred are ultimately subject to regulatory approval. 



Benefit costs are impacted by actual and actuarial estimates of employee demographics (including but not limited to age, compensation levels and years of accredited service), future health care costs, the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Actuarial assumptions are reviewed and updated annually based on current economic conditions and trends. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.



In accordance with accounting rules, changes in benefit obligations associated with factors discussed above may be immediately recognized as a regulatory asset if related to recoverable service or in other comprehensive income and reclassified as a current cost in future years. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. 



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See Note 9 to Financial Statements regarding other disclosures related to obligations of our pension plans and OPEB plans.

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RESULTS OF OPERATIONS



Operating Data

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Financial Results ─ Year Ended December 31, 2025 Compared to Year Ended December 31, 2024



Total operating revenues increased $696 million, or 11%, to $6.778 billion in 2025.



Revenues contributing to earnings increased $618 million to $5.240 billion in 2025. The net increase reflected the following components:







Distribution base rates are set periodically in a comprehensive base rate review docket. The most recent base rates implementing the final order in PUCT Docket No. 53601 went into effect in 2023. We may request interim updates to our distribution base rates between comprehensive base rate reviews through a UTM application or interim DCRF rate adjustment application. 



See the Interim DCRF Filings Table below for a listing of the interim DCRF rate adjustment applications impacting revenues for 2025 and 2024, as well as filings currently impacting revenues for 2026. As we currently intend to recover costs related to distribution capital investments placed into service since December 31, 2024 through UTM applications beginning in 2026, we do not intend to file interim DCRF rate adjustment applications in 2026. See “—Key Factors Relating to Future Earnings and Results of Operations—Regulation, Rates and Cost Recovery” above and Note 2 to Financial Statements for more information on UTM and interim DCRF applications.

 

Interim DCRF Filings Table



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partially offset by



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TCOS revenues are collected from load serving entities benefiting from our transmission system, and the rates charged to those customers are adjusted based on the transmission billing units and other adjustments approved by the PUCT. We may request interim updates to our transmission base rates between comprehensive base rate reviews through a UTM application or interim TCOS rate adjustment application.



See the Interim TCOS Filings Table below for a listing of the interim TCOS filings impacting revenues for 2025 and 2024, as well as filings currently impacting revenues for 2026. As we currently intend to recover costs related to transmission capital investments placed into service since December 31, 2024 through UTM applications beginning in 2026, we do not intend to file interim TCOS rate adjustment applications in 2026. See “—Key Factors Relating to Future Earnings and Results of Operations—Regulation, Rates and Cost Recovery” above and Note 2 to Financial Statements for more information on UTM and interim TCOS applications.



Interim TCOS Filings Table

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Revenues collected for pass-through expenses increased $78 million to $1.538 billion in 2025. While changes in these pass-through tariffs affect revenues and the timing of cash flows, they do not impact operating income and do not contribute to earnings. The net increase reflected the following components:





TCRF is a reconcilable distribution rate charged to REPs to recover fees we pay to wholesale transmission service third-party providers under their TCOS rates and the retail portion of our own TCOS rate described above. We currently anticipate requesting interim TCRF updates through our UTM applications. The increase in our TCRF Third-Party revenue recognition reflects the pass-through effect of changes in third-party wholesale transmission service expense.

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EECRF is a reconcilable rate designed to recover current energy efficiency program costs and annual performance bonuses earned by exceeding PUCT targets in prior years and to refund or recover any over/under recovery of our costs in prior years. We recognize the annual performance bonuses in other regulated revenues upon approval by the PUCT. PUCT rules require us to file an annual EECRF tariff update by the first business day in June of each year for implementation on March 1 of the next calendar year. Other revenues generally include amounts collected through (i) the mobile generation rider, which is a reconcilable rate designed to recover mobile generation lease expenses and operation and maintenance expenses and is generally reviewed and approved by the PUCT in our mobile generation rider filing proceedings, and (ii) the rate case expense rider, which is a reconcilable rate designed to recover rate case expenses approved in comprehensive rate base review proceedings.



See the EECRF Filings Table below for a listing of the EECRF filings impacting revenues for 2025 and 2024, as well as filings currently impacting revenues for 2026.



EECRF Filings Table



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Wholesale transmission service expense increased $81 million to $1.475 billion in 2025. The increase was due to higher billings from third-party transmission service providers. Wholesale transmission service expense is a pass-through expense that is offset with TCRF Third-Party revenues as discussed above.



Operation and maintenance expense increased $249 million to $1.542 billion in 2025. The increase was primarily due to $111 million in higher employee labor and contractor related costs, $105 million in higher vegetation management expenses, $16 million in higher insurance premium expenses and a $10 million rate case expense regulatory asset write-off. We expect operation and maintenance expense to continue to increase in 2026 due to anticipated higher labor and contractor related costs.



The overall $249 million increase in operation and maintenance expense includes $170 million increase in incremental SRP operation expenses in 2025. We expect distribution-related SRP operation and maintenance expenses to ultimately be recovered in rates. For more information on our SRP, see Note 2 to Financial Statements.   



Depreciation and amortization increased $124 million to $1.184 billion in 2025. The increase was primarily attributable to ongoing investments in property, plant and equipment. We expect depreciation and amortization to continue to increase, particularly given our capital expenditure plans. See “—Financial Condition—Liquidity and Capital Resources” for more information on our five-year capital plan.



Provision in lieu of income taxes netted to $228 million (including a $1 million benefit related to non-operating income) in 2025 compared to $206 million (including a $2 million benefit related to non-operating income) in 2024. 



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The effective income tax rate was 17.6% and 17.5% for 2025 and 2024, respectively. The effective tax rate on pretax income differs from the U.S. federal statutory rate of 21% primarily due to the amortization of the regulatory liability for excess deferred taxes as a result of the TCJA, partially offset by the effects of the Texas margin tax.



Taxes other than amounts related to income taxes increased $19 million to $590 million in 2025. The increase was primarily due to higher property taxes, and higher local franchise taxes payable by us to municipalities. We anticipate taxes other than amounts related to income taxes to continue to increase, particularly given our capital expenditure plans. See “—Financial Condition—Liquidity and Capital Resources” for more information on our five-year capital plan.



Other (income) and deductions - net was $36 million favorable in 2025 compared to 2024. The variance was primarily due to $38 million in higher AFUDC – equity income and $3 million in interest income related to the sales tax refund settled in 2025, partially offset by $5 million in higher reconcilable employee retirement benefit expenses, which are generally recoverable through operating revenues, and $2 million in higher professional fees.



Interest expense and related charges increased $135 million to $788 million in 2025. The increase was primarily due to higher average borrowings attributable to ongoing investments in property, plant and equipment and higher average interest rates on the borrowings.



Net income increased $102 million to $1.07 billion in 2025. The increase was driven by:

partially offset by



OTHER COMPREHENSIVE (LOSS) INCOME



Cash Flow Hedges



In the first quarter of 2025, we entered into interest rate swap transactions hedging the variability of benchmark bond rates used to determine the interest rates on 10-year and 30-year senior secured notes. The hedges were terminated in March 2025 upon the issuance of our 5.35% Senior Secured Notes due 2035 (2035 Notes) and 5.80% Senior Secured Notes due 2055 (2055 Notes) and a $15 million ($12 million net of tax) net fair value loss was realized and recorded in OCI. The AOCI will be reclassified into net income as an increase in interest expense over the life of the 2035 Notes and 2055 Notes respectively.



In April 2025, we began entering into interest rate swap transactions hedging the variability of benchmark bond rates in anticipation of future debt financings through 2028. As of December 31, 2025, all such derivative instruments remained outstanding. In 2025, we recorded a $5 million ($4 million net of tax) net unrealized fair value gain on the interest rate swaps in OCI.



We previously entered into multiple interest rate swap transactions in advance of certain senior secured notes issuances to hedge the variability of benchmark bond rates before March 31, 2025. All of these hedges had been terminated as of December 31, 2025, with losses reported in OCI. There were approximately $6 million in net losses recorded in AOCI at December 31, 2025 related to the interest rate swaps to be reclassified into net income as an increase to interest expense within the next 12 months.



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Fair Value Hedges



In May 2024 and June 2025, we entered into multiple cross-currency swaps, designated as fair value hedges, that effectively converted our euro-denominated fixed rate payment obligations under our Euro Notes with respect to principal and interest payments to U.S. dollar-denominated fixed rate payment obligations.  



In September 2025, we entered into multiple cross-currency swaps, also designated as fair value hedges, that effectively converted our Canadian dollar-denominated fixed rate payment obligations under our CAD Notes with respect to principal and interest payments to U.S. dollar-denominated fixed rate payment obligations.



At December 31, 2025, we recorded a $31 million net fair value loss of the cross-currency swaps. The amount attributable to excluded components was a $58 million ($46 million net of tax) loss and was recorded in OCI at December 31, 2025.



FINANCIAL CONDITION



LIQUIDITY AND CAPITAL RESOURCES



Cash Flows —  Year Ended December 31, 2025 Compared to Year Ended December 31, 2024



Operating Activities —  The following items contributed to changes in sources (uses) of cash related to operating activities:





Depreciation and amortization expenses reported in operating activities in the statements of consolidated cash flows were $174 million and $173 million more than the amounts reported in the statements of consolidated income in 2025 and 2024, respectively. The differences are primarily due to certain regulatory asset amortization being reported as operation and maintenance expense in the statements of consolidated income in accordance with GAAP.



Financing Activities —  The following items contributed to changes in sources (uses) of cash related to financing activities:





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Investing Activities —  The following items contributed to changes in sources (uses) of cash related to investing activities:









Long-Term Debt-Related Activities in 2025 and 2026



At December 31, 2025, our long-term debt outstanding book value (including the remeasurement adjustment related to foreign currency denominated notes, but excluding unamortized discount, premium and debt issuance costs) totaled an aggregate principal amount of $19.224 billion, an increase of $3.831 billion over the $15.393 billion aggregate principal amount of long-term debt outstanding book value (including the remeasurement adjustment related to foreign currency denominated notes, but excluding unamortized discount, premium and debt issuance costs) at December 31, 2024.



Long-term debt outstanding at December 31, 2025 consisted of U.S. dollar-denominated, euro-denominated and Canadian dollar-denominated fixed rate senior secured notes, variable rate secured debt borrowed under the AR Facility, and variable rate unsecured debt borrowed under the $500M Credit Facility and the Term Loan Credit Agreement. See Note 6 to Financial Statements for more information on our long-term debt. For more information on our regulatory capital structure and limitations on our ability to incur additional long-term debt, see “—Capitalization and Return on Equity” and “—Credit Rating Provisions and Material Debt Covenants” below.



Senior Secured Notes Issuances —  The following table summarizes our issuances of senior secured notes in 2025:





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Our fixed rate senior secured notes are secured equally and ratably by a first priority lien on all property acquired or constructed by Oncor for use in our electricity transmission and distribution business, subject to certain exceptions. The property is mortgaged under the Deed of Trust. The Deed of Trust permits us to secure indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent. At December 31, 2025, the amount of available bond credits was $3.503 billion. The repayment in full of the $38 million outstanding principal amount of our 3.86% Senior Secured Notes, Series B, due January 14, 2026 (Series B Notes) upon their maturity on January 14,

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2026, increased the amount of available bond credits by such amount. At December 31, 2025, the amount of future debt we could secure with property additions, subject to those property additions being certified to the Deed of Trust collateral agent, was $8.011 billion. See Note 6 to Financial Statements for a listing of all of our fixed rate senior secured notes secured by the Deed of Trust.



Senior Secured Notes Repayment —  On March 14, 2025, we repaid the entire $350 million aggregate principal amount of the 2.95% Senior Secured Notes due 2025 (2.95% 2025 Notes) that were redeemed in full. The 2.95% 2025 Notes had a maturity date of April 1, 2025. With the redemption of the 2.95% 2025 Notes, none of the 2.95% 2025 Notes remain outstanding. On December 3, 2025, we repaid in full at maturity the $174 million aggregate principal amount of our 3.86% Senior Secured Notes, Series A, due December 3, 2025 (Series A Notes). On January 14, 2026, we repaid in full at maturity the $38 million aggregate principal amount of our Series B Notes.



Senior Secured Notes Extinguishment — On March 19, 2025, we extinguished all of the 0.55% Senior Secured Notes due 2025 (0.55% 2025 Notes), of which $450 million aggregate principal amount was outstanding. The 0.55% 2025 Notes matured on October 1, 2025. Pursuant to the terms of the indenture and officer’s certificate governing the 0.55% 2025 Notes, we irrevocably deposited with the trustee cash and U.S. Treasury Notes in an amount sufficient for defeasance of the 0.55% 2025 Notes, whereby our indebtedness in respect of the 0.55% 2025 Notes was satisfied and discharged. The trustee paid the holders of the 0.55% 2025 Notes in full on October 1, 2025. We recognized a $9 million unamortized gain on extinguishment as a regulatory liability due to the pricing of the U.S. Treasury Notes deposited with the trustee.



AR Facility  — In 2023, Oncor and Receivables LLC established the AR Facility, a revolving accounts receivable securitization facility secured by accounts receivable from REPs and related rights. Oncor has access to the AR Facility, under which Receivables LLC may borrow at any one time an amount equal to the borrowing base. The borrowing base is defined under the receivables financing agreement as an amount equal to the lesser of (i) the facility limit of $500 million and (ii) the amount calculated based on the outstanding balance of eligible REP receivables held as collateral at a particular time, subject to certain reserves, concentration limits, and other limitations. On May 5, 2025, the scheduled termination date of the AR Facility was extended by one year from April 28, 2027 to April 28, 2028.



At December 31, 2025,  the borrowing base for the AR Facility was $500 million and $325 million in borrowings were outstanding under the AR Facility.



On January 29, 2026, we borrowed an additional $150 million under the AR Facility.



The following table summarizes the borrowings and repayments under our AR Facility in 2025:



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$500M Credit Facility — In 2024, we entered into an unsecured revolving $500M Credit Facility. The $500M Credit Facility has a borrowing capacity of $500 million and a maturity date of February 21, 2027. The $500M Credit Facility gives us the option to request an increase in our borrowing capacity of up to $500 million in $100 million minimum increments, subject to certain conditions, including lender approvals. The $500M Credit Facility also provides us with the option to request that each lender extend the term of its commitment for up to two additional one-year periods, subject to certain conditions, including lender approvals. See Note 6 to Financial Statements for more information on the $500M Credit Facility. There were no borrowing and repayment activities under the $500M Credit Facility in 2025, and $480 million in borrowings were outstanding under the $500M Credit Facility at December 31, 2025 and at December 31, 2024.



$1B Credit Facility — On February 20, 2025, we entered into an unsecured revolving $1B Credit Facility. On February 20, 2026, we entered into an amendment to the $1B Credit Facility to, among other things, extend the maturity date by one year and to remove the SOFR Adjustment. The $1B Credit Facility has a borrowing capacity of $1.0 billion and a maturity date of February 20, 2029. The $1B Credit Facility gives us the option to request an increase in our borrowing capacity of up to $350 million in $100 million minimum increments, subject to certain conditions, including lender approvals. The $1B Credit Facility also provides us with the option to request that each lender extend the term of its commitment for up to two additional one-year periods, subject to certain conditions, including lender approvals. See Note 6 to Financial Statements for more information on the $1B Credit Facility. At December 31, 2025, there were no borrowings outstanding under the $1B Credit Facility.



Term Loan Credit Agreement — On December 23, 2025, we entered into an unsecured $1.4 billion Term Loan Credit Agreement. The Term Loan Credit Agreement matures on March 1, 2027. On December 26, 2025, we made our initial borrowing under the Term Loan Credit Agreement in the amount of $925 million and on January 29, 2026, we borrowed the remaining $475 million available for borrowing. Following such borrowing, no additional amounts remain available for future borrowings under the Term Loan Credit Agreement. See Note 6 to Financial Statements for more information on the Term Loan Credit Agreement.



Short-Term Debt-Related Activities in 2025 and 2026



$2B Credit Facility — On February 20, 2025, we entered into an amended and restated unsecured revolving $2B Credit Facility. On February 20, 2026, we entered into an amendment to the $2B Credit Facility to, among other things, extend the maturity date by one year and to remove the SOFR Adjustment. The $2B Credit Facility has a borrowing capacity of $2.0 billion and a maturity date of February 20, 2031. The $2B Credit Facility gives us the option to request an increase in our borrowing capacity of up to $650 million in $100 million minimum increments, subject to certain conditions, including lender approvals. The $2B Credit Facility also provides us with the option to request that each lender extend the term of its commitment for up to two additional one-year periods, subject to certain conditions, including lender approvals.



CP Program — We have established a CP Program, under which we may issue unsecured CP Notes on a private placement basis with maturity dates not exceeding 397 days from the date of issuance. To the extent any CP Notes are issued with maturity dates of over one year, we anticipate those would be classified as long-term debt and obtain liquidity support under the $1B Credit Facility. We anticipate that any CP Notes issued under the CP Program with a maturity date equal to or less than one year would be classified as short-term debt and obtain liquidity support under the $2B Credit Facility. Total CP Notes outstanding at any time may not exceed a maximum amount of $3.0 billion.



As of December 31, 2025, we had no CP Notes outstanding and at December 31, 2024, we had $594 million of CP Notes outstanding. The weighted average interest rate for CP Notes was 4.76% at December 31, 2024. All outstanding CP Notes at December 31, 2024 had maturity dates of less than one year.



See Note 5 to Financial Statements for additional information regarding the $2B Credit Facility and CP Program.



Available Liquidity and Liquidity Needs, Including Capital Expenditures 



Capital Expenditures —  Our board of directors, which approves annual capital expenditure budgets one year at a time, has approved a capital expenditures budget of approximately $9 billion for 2026. Based on the long-term plan presented to our board of directors, we have announced a 2026 through 2030 five-year base capital expenditure plan of approximately $47.5 billion, consisting of approximately $10.0 billion in 2027, $10.1 billion in 2028, $9.4 billion in 2029 and $9.0 billion in 2030. The increase in our five-year base capital expenditures plan from our prior 2025 through 2029

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base capital expenditure plan is largely attributable to targeted completion of all PBRP projects for which Oncor has responsibility by December 31, 2030, as well as other new transmission projects and distribution upgrades.



Our base capital plan does not include certain incremental capital expenditure opportunities over the 2026 through 2030 period that we believe could grow our five-year base capital plan by as much as approximately $10 billion over that period. These incremental capital expenditure opportunities consist of significant pending projects, including non-PBRP 765-kV transmission projects for which Oncor has responsibility in the STEP, additional transmission upgrades currently pending ERCOT approval, anticipated requested updates to our SRP for 2028 through 2030, and various LC&I customer interconnection projects that we believe have a strong likelihood of completion.

   

Long-Term Debt Maturities and Interest —  As of December 31, 2025, our obligations related to long-term debt (including the remeasurement adjustments related to foreign currency denominated notes, but excluding unamortized discount, premium and debt issuance costs) and related interest payments are as follows:





See Note 6 to Financial Statements for more information regarding our long-term debt, including long-term debt activity subsequent to December 31, 2025.



Pension Plans and OPEB Plans Funding — Based on funding considerations in the latest actuarial projections, including applicable minimum funding requirements, our future funding for the pension plans and the OPEB Plans is expected to total $101 million and $21 million, respectively, in 2026 and approximately $489 million and $160 million, respectively, in the five-year period 2026 to 2030. Future funding estimates for our pension plans and OPEB Plans are dependent on a variety of variables and assumptions, including investment returns on plan assets, market interest rates, and levels of discretionary contributions over minimum funding requirements, which we continue to monitor. Financial market volatility and its effects on the returns on our plan assets and liability valuations could significantly change our anticipated future funding amounts. We may also elect to make additional discretionary contributions based on market and/or business conditions. In 2025, we made cash contributions to the pension plans and OPEB Plans of $192 million and $24 million, respectively. See Note 9 to Financial Statements for additional information regarding pension plans and OPEB Plans.



Additional Liquidity Needs — In addition to the items discussed above, other material contractual obligations and commitments arising in the normal course of business primarily consist of purchase obligations under outsourcing agreements and operating lease obligations. The impact of potential price increases associated with raw materials used by our suppliers, including copper, aluminum, and steel, could be passed on to us through the terms of our contracts and create additional liquidity needs under our purchase obligations. See Note 7 to Financial Statements for information regarding leases. In addition, we regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets, which could potentially impact our liquidity and capital expenditures. See “Item 1A. Risk Factors—Risks Related to Our Business and Operations—We regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets, and we may not be able to realize the anticipated benefits of any such acquisitions.”

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Available Liquidity — Our primary source of liquidity, aside from operating cash flows, is our ability to issue CP Notes and borrow under our Credit Facilities and AR Facility. The following table summarizes available liquidity at December 31, 2025 and 2024:



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We currently anticipate issuing approximately $5.5 billion to $6.5 billion in new long-term debt securities in 2026, as well as an additional $5.0 billion to $6.0 billion in new long-term debt securities in 2027, to support our capital investment plan and repay maturing debt. We expect cash flows from operations combined with long-term debt issuances and credit agreements as well as availability under the Credit Facilities, the AR Facility and the CP Program to be sufficient to fund current obligations, projected working capital requirements, maturities of long-term debt, capital expenditures, minimum funding requirements for pension plans and OPEB Plans, operating lease obligations and purchase obligations under outsourcing agreements for at least the next 12 months. We also anticipate, consistent with past practice, continuing to request member contributions and preserving equity through reductions or suspension of distributions to members. In addition, we may also consider repurchases, exchange offers, additional financing facilities, additional accounts receivable financing arrangements, inventory financing arrangements, and other transactions in order to refinance or manage our debt and manage our liquidity and capital requirements.



Over both the short term and the long term, we expect to rely on access to financial markets as a significant source of funding not satisfied by cash-on-hand, operating cash flows, the Credit Facilities, the AR Facility and the CP Program. The inability to raise capital on favorable terms or failure of counterparties to perform under credit or other financial agreements, particularly during any uncertainty in the financial markets, could impact our ability to sustain and grow the business and would likely increase capital costs that may not be fully recoverable through rates. See “Item 1A. Risk Factors—Risks Related to Financial and Market Matters—Market volatility may impact our business and financial condition in ways that we currently cannot predict.”



Capitalization and Return on Equity 



The PUCT has the authority to determine what types of debt and equity are included in a utility’s debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt including any finance leases plus unamortized gains on reacquired debt less net unamortized issuance expenses, discounts,  premiums and losses on reacquired debt. Equity is calculated as membership interests determined in accordance with GAAP, excluding accumulated other comprehensive loss and the effects of acquisition accounting from a 2007 transaction.



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We have committed to the PUCT to maintain a regulatory capital structure at or below the debt-to-equity ratio established periodically by the PUCT for ratemaking purposes. Our authorized return on equity is 9.7%, which went into effect in May 2023 in connection with the effective date of our base rates implementing the terms of the PUCT’s final order in PUCT Docket No. 53601. If approved by the PUCT as requested, the settlement in our pending base rate review would set our authorized return on equity at 9.75%. See “—Rates and Regulation—Regulatory Matters” below for more information. Our ability to incur additional long-term debt is limited by our authorized regulatory capital structure, as we are able to issue future long-term debt only to the extent that the issuance of such debt would not cause us to exceed the authorized regulatory debt-to-equity ratio.



The following table summarizes the capitalization structure ratios under regulatory mandates and GAAP, at December 31, 2025 and 2024:





Member Contributions and Distributions





Contributions — On February 12, 2026, we received cash capital contributions from our members totaling $1.091 billion. During 2025, we received the following cash capital contributions from our members: 



Distributions —  The Sempra Order and our LLC Agreement set forth various restrictions on distributions to our members. Among those restrictions is the commitment that we will make no distributions (other than contractual tax payments) to our members that would cause us to exceed our debt-to-equity ratio authorized by the PUCT. The distribution restrictions also include the ability of a majority of our Disinterested Directors, or either of the two member directors designated by Texas Transmission, to limit distributions to the extent each determines it is necessary to meet expected future requirements of Oncor (including continuing compliance with the PUCT debt-to-equity ratio commitment). At December 31, 2025, we had $717 million available to distribute to our members without exceeding our authorized regulatory debt-to-equity ratio.



On February 11, 2026, our board of directors declared, and we paid, a cash distribution of  $286 million. During 2025, our board of directors declared, and we paid, the following cash distributions to our members:





Credit Rating Provisions and Material Debt Covenants



Impact on Liquidity of Credit Ratings — The rating agencies assign credit ratings to certain of our debt securities. Our access to capital markets and cost of debt could be directly affected by our credit ratings or ratings outlook. Any adverse action with respect to our credit ratings or ratings outlook could generally cause borrowing costs to increase, result in the imposition of financial or other burdensome covenants in the case of certain financing arrangements, and cause the

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potential pool of investors and funding sources to decrease. In particular, a decline in credit ratings would increase the cost of the Credit Facilities (as discussed below). In the event any adverse action with respect to our credit ratings or ratings outlook takes place and causes borrowing costs to increase, we may not be able to recover such increased costs if they exceed our PUCT-approved cost of debt determined in our most recent comprehensive base rate review or subsequent comprehensive base rate reviews.



Most of our large suppliers and counterparties require an expected level of creditworthiness in order for them to enter into transactions with us. If there is an adverse action with respect to our credit ratings or ratings outlook, the costs to operate our business could increase because counterparties could require the posting of collateral in the form of cash-related instruments, or counterparties could decline to do business with us.



Presented below are the credit ratings and ratings outlook assigned for our debt securities at February 26, 2026.  



A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Ratings can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant such a change.



Material Debt Credit Rating, Financial, and Cross-Default Covenants — Each of the Credit Facilities contains terms pursuant to which the interest rates and commitment fees charged under the applicable credit agreement may be adjusted depending on our credit ratings. A decline in our credit ratings would increase the cost of borrowings and the commitment fees on undrawn amounts under the Credit Facilities and likely increase the cost of the CP Program and any future debt issuances and additional credit facilities. The CP Program requires prompt notice to the dealers of any notice of intended or potential downgrade of our credit ratings. See Notes  5 and 6 to Financial Statements for additional information regarding each of the Credit Facilities and the CP Program.



The Term Loan Credit Agreement, the Credit Facilities, the AR Facility, and note purchase agreements each contain a financial covenant that requires maintenance of a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00. For purposes of this ratio, senior debt is calculated as indebtedness defined in the applicable agreement (principally, the sum of long-term debt, any finance leases, short-term debt and debt due currently in accordance with GAAP). Capitalization under the Term Loan Credit Agreement, the Credit Facilities, the AR Facility, and each of the note purchase agreements dated March 29, 2023, March 27, 2024, and January 30, 2025 is calculated as membership interests determined in accordance with GAAP plus debt described above. At December 31, 2025, we were in compliance with this covenant and all other covenants under the Term Loan Credit Agreement, the Credit Facilities, the AR Facility, and the note purchase agreements.



Certain of our financing arrangements contain provisions that may result in an event of default if there is a failure under other financing arrangements to meet payment terms or to observe other covenants that could result in an acceleration of payments due. Such provisions are referred to as “cross default” provisions.



Under the $500M Credit Facility, a default by us or any subsidiary in respect of indebtedness in a principal amount in excess of $100 million or any judgments for the payment of money in excess of $100 million that are not discharged or stayed within 60 days may cause the maturity of outstanding balances under the $500M Credit Facility to be accelerated. 



Under the Term Loan Credit Agreement, the $1B Credit Facility, the $2B Credit Facility and the AR Facility, a default by us or certain of our subsidiaries that results in acceleration of the maturity of such indebtedness in respect of indebtedness in a principal amount in excess $150 million or any judgments for the payment of money in excess of $150 million that are not discharged or stayed within 60 days may cause the maturity of outstanding balances under those facilities to be accelerated. 



Under the Deed of Trust, an event of default under our indentures or, after all applicable notices have been given and all applicable grace periods have expired, under the note purchase agreements would permit the holders of our secured debt under the indentures or the note purchase agreements to exercise their remedies under the Deed of Trust.

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Guarantees 



At December 31, 2025, we did not have any material guarantees.



COMMITMENTS AND CONTINGENCIES



See Note 7 to Financial Statements for a discussion of commitments and contingencies.



CHANGES IN ACCOUNTING STANDARDS



See Note 1 to Financial Statements for discussion of changes in accounting standards.



REGULATION AND RATES



Regulatory Matters  



2025 Comprehensive Base Rate Review (PUCT Docket No. 58306) — In June 2025, we filed a request for a comprehensive base rate review with the PUCT and the 210 cities in its service territory that have retained original jurisdiction over rates.



On January 29, 2026, we filed a stipulation in the comprehensive base rate review proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. The stipulation provides for an annual revenue requirement of approximately $6.975 billion, an increase of 8.8% over our adjusted annualized present revenues provided in the rate application. We estimate the terms of the stipulation would result in an aggregate annualized increase over those revenues of approximately $560 million. Moreover, the stipulation also provides for a revised regulatory capital structure ratio of 56.5% debt to 43.5% equity, an authorized return on equity of 9.75%, and an authorized cost of debt of 4.94%. In addition, the stipulation provides for (i) a self-insurance reserve with an annual accrual amount in rates of $200 million for storm costs and other self-insured losses, an increase from the $122 million self-insurance reserve annual accrual amount currently recovered in rates, as well as (ii) a five-year amortization period for applicable regulatory assets and liabilities, which would not include rate case expenses, year-end 2024 deferred system resiliency plan costs, and excess accumulated deferred income taxes.



The PUCT may choose to adopt, modify, or reject the stipulation and the proposed order included in the stipulation. We expect the PUCT to issue a final order in the proceeding in the first half of 2026. New billing rates would be implemented after that final order, and if the proposed new rates in the stipulation are approved as requested, we will surcharge the difference between those new rates and our current rates back to January 1, 2026, pursuant to a previously approved settlement regarding interim rates.



UTM — See Note 2 to Financial Statements and “—State Legislation” for more information on the UTM.



SRP (PUCT Docket No. 56545) — See Note 2 to Financial Statements for more information on the SRP.



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Appeal of 2023 Comprehensive Base Rate Review Order (PUCT Docket No. 53601) — In April 2023, the PUCT issued a final order in our comprehensive base rate review filed in May 2022 with the PUCT and the cities in our service territory that have retained original jurisdiction over rates. Base rates implementing the final order went into effect in May 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by us and certain intervening parties in the proceeding. The order on rehearing affirmed the material provisions of the final order. In September 2023, we filed an appeal in Travis County District Court. The appeal sought judicial review of certain of the order on rehearing’s rate base disallowances (the acquisition premium and its associated amortization costs relating to certain plant facilities acquired by Oncor in 2019 as well as certain of the employee benefit and compensation related costs that we had previously capitalized) and related expense effects of those disallowances. In February 2024, the court dismissed the appeal for lack of jurisdiction. In March 2024, we appealed the court’s dismissal to the Fifteenth Court of Appeals in Texas. On August 14, 2025, the Court issued its opinion in favor of the PUCT, denying our argument on appeal. We have elected not to pursue a further appeal.



State Legislation



The Texas Legislature operates under a biennial system and meets in regular session in every odd-numbered year. The Texas Legislature convened its 89th Legislature regular session in January 2025, which concluded on June 2, 2025. At any time, the Governor of Texas may convene a special session of the Texas Legislature. During any regular or special session, the Texas Legislature may hold hearings relevant to our business and bills may be introduced that, if adopted, could materially and adversely affect our business and our business prospects.



In June 2025, the Governor of Texas signed HB 5247. The bill establishes the UTM, which allows qualifying electric utilities to (i) apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments, as an alternative to separate DCRF and TCOS capital tracker filings, and (ii) defer to a regulatory asset certain UTM eligible capital investment costs as they are placed into service. Qualifying electric utilities consist of utilities that (i) operate solely inside ERCOT, (ii) have been identified by the PUCT as having responsibility for constructing transmission infrastructure as part of the PBRP, and (iii) make annual capital expenditures in transmission and distribution that exceed 300% of annual depreciation. In January 2026, we filed a notice with the PUCT (PUCT Docket No. 59249) indicating our intent to file our initial UTM application on or after March 16, 2026, and certifying that we meet the requirements for filing an application. We expect to include in that application all eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, and as a result have recorded regulatory assets for recoverable costs associated with those investments and recognized a corresponding amount in other regulated revenues. We also currently anticipate requesting interim TCRF updates through our UTM applications. See Notes 2 and 3 to Financial Statements for more information on the regulatory assets and recognition of revenues.



HB 5247 provides that the PUCT must review a UTM filing within 120 days, and if a final order is not issued by the PUCT within 165 days after the UTM is filed, we can place the requested rates into effect on a temporary basis and refund or credit against future customer bills any difference between such temporary rates and the final approved rates. UTM applications will be subject to a regulatory proceeding and PUCT approval, and we can make no assurance that they will result in full cost recovery or be timely approved. Investments included in the UTM are also subject to a future prudence review by the PUCT, with a potential for the PUCT to also order refunds of previously collected amounts if a particular investment is found to be imprudent or inappropriately included. In addition, HB 5247 provides that, except in certain circumstances, the amortization period authorized by the PUCT for rate recovery of UTM-related regulatory assets cannot exceed 18 months.



In addition, the Texas Legislature also passed legislation addressing wildfire risk mitigation, distribution pole inspection standards, and infrastructure planning related to large load interconnections to the electric grid.

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Federal Legislation



The OBBBA was signed into law in July 2025. The OBBBA includes revisions of the Inflation Reduction Act enacted in 2022 and extends or revises key provisions of the TCJA. Included in the OBBBA is the immediate expensing of domestic research and experimental expenditures, including internally developed software expenditures, under Code Section 174A. This change supersedes prior rules requiring a five-year amortization of domestic research and experimental expenditures under the TCJA. In accordance with I.R.S. transitional guidance (Revenue Procedure 2025-28), we plan to elect to accelerate deductions for domestic unamortized software development expenditures incurred in tax years 2022 through 2024, with remaining balances deductible in tax year 2025. As a result, we included a  tax deduction of $377 million (tax effect of $79 million) in the 2025 income tax provision. The deduction does not have a material impact on the consolidated financial statements and has no impact on the effective tax rate. We will continue to monitor guidance issued by the U.S. Department of the Treasury and the I.R.S.



Summary



We cannot predict future regulatory or legislative actions or any changes in economic and financial market conditions. Such actions or changes could significantly alter our financial position, results of operations, or cash flows.

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Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 



Market risk is the risk that we may experience a loss in value as a result of changes in market conditions such as interest rates and foreign currency exchange rates that occur in the ordinary course of business.



Interest Rate Risk



We use interest rate swaps, designated as cash flow hedges, in part, to hedge our interest payments related to our expected future debt financings. The future fixed rate debt issuances underlying these cash flow hedge relationships are largely dependent on market demand and liquidity in the debt market. At December 31, 2025, we believe our forecasted issuances of fixed rate debt in the related cash flow hedge relationships are probable. However, unexpected changes in market conditions in future periods could impact our ability to issue such fixed rate debt, or the timing of any such issuance. If our assumptions regarding the nature and timing of forecasted fixed rate debt issuances were to be inaccurate, we could be required to cease the application of hedge accounting to the related interest rate swaps, which could result in immediate reclassification of all the related gains or losses in AOCI to other (income) and deductions. See Note 11 to Financial Statements for more information on our interest rate risk hedging activities.



At December 31, 2025, all of our senior secured notes carried fixed interest rates.



Borrowings under the AR Facility bore interest at the daily cost of asset-backed commercial paper issued by the conduit lenders to fund the loans, plus related dealer commissions and note issuance costs. Additional borrowings under the AR Facility could bear interest, if funded by the committed lenders, at a rate per annum equal to SOFR calculated based on term SOFR for a one-month interest period, plus the SOFR Adjustment. Receivables LLC also pays a used and unused fee in connection with the AR Facility. At December 31, 2025, $325 million borrowings were outstanding under the AR Facility. On January 29, 2026, we borrowed an additional $150 million under the AR Facility.

 

Borrowings of long-term debt under the $500M Credit Facility at December 31, 2025 bore interest at a per annum rate equal to SOFR for the interest period relevant to such borrowings, plus the SOFR Adjustment, plus an applicable margin of between 0.875% and 1.50%, depending on certain credit ratings assigned to our debt. Additional borrowings under the $500M Credit Facility could bear interest at a per annum rate equal to, at our option, (i) term SOFR for the interest period relevant to such borrowing, plus the SOFR Adjustment, plus an applicable margin of between 0.875% and 1.50%, depending on certain credit ratings assigned to our debt, or (ii) an alternate base rate (equal to the greatest of (1) the prime rate publicly announced from time to time by the administrative agent as its prime rate, (2) the federal funds effective rate, plus 0.50%, and (3) term SOFR for a one-month interest period on such date, plus the SOFR Adjustment, plus 1.0%), plus, in the case of clauses (1) through (3), an applicable margin of between 0.00% and 0.50%, depending on certain credit ratings assigned to our debt. At December 31, 2025, $480 million in aggregate borrowings were outstanding under the $500M Credit Facility.



Borrowings of long-term debt under the Term Loan Credit Agreement at December 31, 2025 bore interest at a per annum rate equal to SOFR for the interest period relevant to such borrowings, plus an applicable margin of 0.875%. Additional borrowings under the Term Loan Credit Agreement could bear interest as a per annum rate equal to, at our option, (i) SOFR for the interest period relevant to such borrowing plus an applicable margin of 0.875%, or (ii) an alternate base rate (equal to the greatest of (1) the prime rate as quoted by The Wall Street Journal on such date, (2) the federal funds effective rate on such date, plus 0.50%, and (3) SOFR for a one-month interest period on such date plus 1.0%). At December 31, 2025, $925 million in aggregate borrowings were outstanding under the Term Loan Credit Agreement. On January 29, 2026, we borrowed the remaining $475 million available for borrowings. Following such borrowing, no additional amounts remain available for future borrowings under the Term Loan Credit Agreement.



In addition, borrowings of long-term debt under the $1B Credit Facility and short-term debt under the $2B Credit Facility would bear interest on a floating rate basis. At December 31, 2025, there were no borrowings outstanding under the $1B Credit Facility or the $2B Credit Facility.



Based on the amount of floating rate debt outstanding under the AR Facility, the $500M Credit Facility and the Term Loan Credit Agreement as of December 31, 2025, a hypothetical 100 basis point change (up or down) in the weighted average interest rates would not have a material impact on our results of operations or financial condition. For more information on our borrowings and interest rates charged, see Notes 5 and 6 to Financial Statements.

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The following table presents our long-term debt maturities and related information:



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Foreign Currency Exchange Rate Risk



In May 2024 and June 2025, we issued the 2031 Euro Notes and the 2034 Euro Notes, respectively. In September 2025, we issued the CAD Notes. The interest and principal payments on the Euro Notes and CAD Notes are due in euros and Canadian dollars, respectively, and as a result expose us to foreign currency exchange rate risk. Volatile market conditions arising from certain macroeconomic factors may result in significant fluctuations in foreign currency exchange rates. We have attempted to mitigate that risk exposure by entering into cross-currency swaps, a type of financial derivative instrument, which intends to mitigate foreign currency exchange rate exposure. A hypothetical 100 basis point change (up or down) in currency exchange rates would not have a material impact on our results of operations or financial condition. See Note 11 to Financial Statements for more information regarding foreign currency exchange rate hedging activities.



Credit Risk



Credit risk relates to the risk of loss associated with nonperformance by counterparties, including any counterparties to a swap or other derivative instrument. The fair value of derivative instruments in our derivative portfolio assets reflects credit valuation adjustments for our perceived credit risk exposure to the counterparties to such derivative instruments. See Note 11 to Financial Statements for more information.



Our distribution customers consist primarily of REPs. As a prerequisite for obtaining and maintaining certification, a REP must meet the financial resource standards established by the PUCT. Meeting these standards does not guarantee that a REP will be able to perform its obligations. REP certificates granted by the PUCT are subject to suspension and revocation for significant violation of PURA and PUCT rules. Significant violations include failure to timely remit payments for invoiced charges to a transmission and distribution utility pursuant to the terms of tariffs approved by the PUCT. We believe PUCT rules that allow for the recovery of uncollectible amounts due from REPs through rates significantly reduce our credit risk. At December 31, 2025 and December 31, 2024, we had accrued $7 million and $8 million, respectively, in a regulatory asset with respect to amounts deemed uncollectible from REPs.



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Our exposure to credit risk associated with accounts receivable totaled $1.07 billion and $987 million at December 31, 2025 and December 31, 2024, respectively. The accounts receivable balance is before the allowance for uncollectible accounts, which totaled $22 million and $17 million at December 31, 2025 and December 31, 2024, respectively. The exposure at December 31, 2025 and December 31, 2024 includes accounts receivable from REPs totaling $684 million and $628 million, respectively, which are generally noninvestment grade, and from transmission customers totaling $177 million and $171 million at December 31, 2025 and December 31, 2024, respectively, which primarily include investment grade distribution companies, as well as cooperatives and municipally-owned utilities, which are generally considered low credit risk. The accounts receivable balance from REP subsidiaries of Vistra and NRG Energy, Inc., our two largest customers, collectively represented 23% and 19%, respectively, of our accounts receivable balance at December 31, 2025 and 22% and 19%, respectively, of our accounts receivable balance at December 31, 2024. No other customers represented 10% or more of the total accounts receivable balance at either such date. We view our exposure to these customers to be within an acceptable level of risk tolerance considering PUCT rules and regulations; however, this concentration increases the risk that a default could have a material effect on cash flows, liquidity, financial position and/or results of operation.



Our net exposure to credit risk associated with accounts and other receivables from affiliates was zero at both December 31, 2025 and 2024. 



In the ordinary course of our business, we may also mitigate risk by requiring counterparties to provide us with security. For instance, we require customers who do not meet certain credit quality thresholds to provide security before we commence construction on certain customer-requested construction projects for generation interconnection or new/expanded electricity delivery system facilities. See “Item 1A. Risk Factors—Risks Related to Our Business and Operations—Demand for energy from high usage customers, including data centers, will require a rapid and significant increase in our infrastructure, but that forecasted energy demand may not be fully realized and we may not be able to recover all of the costs expended by us on projects related to those customers.” for more information on these customer collateral arrangements.



FORWARD-LOOKING STATEMENTS



This report and other presentations made by us contain “forward-looking statements,” which are subject to risks and uncertainties. All statements, other than statements of historical facts, that are included in this report, as well as statements made in presentations, in response to questions or otherwise, that address activities, events or developments that we expect or anticipate to occur in the future, including such matters as projections, capital allocation, future capital expenditures, business strategy, competitive strengths, goals, future acquisitions or dispositions, development or operation of facilities, market and industry developments and the growth of our business and operations (often, but not always, through the use of words or phrases such as “intends,” “plans,” “will likely result,” “expects,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “forecast,” “should,” “projection,” “target,” “goal,” “objective” and “outlook”), are forward-looking statements. Although we believe that in making any such forward-looking statement our expectations are based on reasonable assumptions, any such forward-looking statement involves risks, uncertainties and assumptions and is qualified in its entirety by reference to the discussion of risk factors under “Item 1A. Risk Factors” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

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Any forward-looking statement speaks only as of the date on which it is made, and, except as may be required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. As such, you should not unduly rely on such forward-looking statements.





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Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Members of Oncor Electric Delivery Company LLC 



Opinion on the Financial Statements



We have audited the accompanying consolidated balance sheets of Oncor Electric Delivery Company LLC and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, cash flows, and membership interests, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.



We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2025, expressed an unqualified opinion on the Company's internal control over financial reporting.



Basis for Opinion



These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. 



We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.



Critical Audit Matter



The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.



Regulatory Matters –Refer to Notes 1 and 2 to the financial statements



Critical Audit Matter Description



The Company is subject to rate regulation by the Public Utility Commission of Texas (the “PUCT”), which has jurisdiction with respect to the rates of electric transmission and distribution companies in Texas. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for effects of cost-based rate regulation.    



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The economic effects of regulation can result in regulated companies recording costs that have been, or are deemed probable to be, allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as regulatory assets and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities). The PUCT’s regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the PUCT will not approve: (1) full recovery of the costs of providing utility service or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment.



We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management in assessing whether the regulatory assets are probable of future recovery and the regulatory liabilities properly reflect all expected amounts of refund to customers by considering factors such as changes in the regulatory environment and recent rate orders. Auditing these judgments required specialized knowledge of accounting for rate regulation due to its inherent complexities. 



How the Critical Audit Matter Was Addressed in the Audit



Our audit procedures related to regulatory matters and accounting for the impacts of rate regulation included the following, among others: 







/s/ Deloitte & Touche LLP



Dallas, Texas



February 26, 2026



We have served as the Company's auditor since 2002.





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ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED INCOME







See Notes to Financial Statements.





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ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME











See Notes to Financial Statements.

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ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED CASH FLOWS



See Notes to Financial Statements.

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ONCOR ELECTRIC DELIVERY COMPANY LLC

CONSOLIDATED BALANCE SHEETS



See Notes to Financial Statements.



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ONCOR ELECTRIC DELIVERY COMPANY LLC

STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS



















See Notes to Financial Statements.

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ONCOR ELECTRIC DELIVERY COMPANY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



1.    DESCRIPTION OF BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES



Description of Business



References in this report to “we,” “our,” “us” and “the company” are to Oncor and/or its subsidiaries as apparent in the context. See “Glossary” for the definition of terms and abbreviations.



We are a regulated electricity transmission and distribution company that operates the largest transmission and distribution system in Texas based on the number of end-use customers and circuit miles of transmission and distribution lines. We provide wholesale transmission and distribution services, and we also provide transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. The rates we charge for our electricity delivery services are set pursuant to tariffs approved by the PUCT and certain cities and, in the case of transmission service related to limited interconnections to other markets, the FERC. We are not a seller of electricity, nor do we purchase electricity for resale. 



Ownership Structure and Ring-Fencing Measures



We are a direct, majority-owned subsidiary of Oncor Holdings, which is indirectly and wholly owned by Sempra. Oncor Holdings owns 80.25% of our membership interests and Texas Transmission owns 19.75% of our membership interests. The company is managed as an integrated business of electricity transmission and distribution with only one reportable segment.



Since 2007, various ring-fencing measures have been taken to enhance our credit quality and the separateness between the Oncor Ring-Fenced Entities and entities with a direct or indirect ownership interest in Oncor or Oncor Holdings. These ring-fencing measures serve to mitigate the Oncor Ring-Fenced Entities’ credit exposure to Sempra and its affiliates and any other direct or indirect owners of Oncor and Oncor Holdings, and reduce the risk that the assets and liabilities of the Oncor Ring-Fenced Entities would be substantively consolidated with the assets and liabilities of any Sempra entity or any other direct or indirect owners of Oncor and Oncor Holdings in connection with a bankruptcy of any such entities.



In March 2018, Sempra indirectly acquired Oncor Holdings. The final order issued by the PUCT approving that transaction outlines certain ring-fencing measures, governance mechanisms and restrictions that apply to Oncor Holdings and Oncor. As a result of these ring-fencing measures, Sempra does not control Oncor, and the ring-fencing measures limit Sempra’s ability to direct the management, policies and operations of Oncor, including the deployment or disposition of Oncor’s assets, declarations of dividends, strategic planning and other important corporate issues and actions. Our LLC Agreement requires PUCT approval of certain revisions to the agreement, including, among other things, revisions to our governance structure and other various ring-fencing measures.



None of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or obligations of any Sempra entity or any other direct or indirect owner of Oncor or Oncor Holdings. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of any Sempra entities and any other direct or indirect owner of Oncor or Oncor Holdings. We do not bear any liability for debt or contractual obligations of Sempra and its affiliates or any other direct or indirect owner of Oncor or Oncor Holdings, and vice versa. Accordingly, our operations are conducted, and our cash flows are managed, independently from Sempra and its affiliates and any other direct or indirect owner of Oncor or Oncor Holdings.



Oncor is a limited liability company governed by a board of directors, not its members. The Sempra Order and our LLC Agreement require that the board of directors of Oncor consist of 13 members, constituted as follows:



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Until March 9, 2028, in order for a current or former officer of Oncor to be eligible to serve as an Oncor Officer Director, the officer cannot have worked for Sempra or any of its subsidiaries or affiliated entities (excluding Oncor Holdings and Oncor) or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings in the ten-year period prior to the date on which the officer first became employed by Oncor. Oncor Holdings, at the direction of STIH, has the right to nominate and/or seek the removal of the Oncor Officer Directors, subject to approval by a majority of the Oncor board of directors.



In addition, the Sempra Order provides that Oncor’s board of directors cannot be overruled by the board of directors of Sempra or any of its subsidiaries on dividend policy, the issuance of dividends or other distributions (except for contractual tax payments), debt issuance, capital expenditures, operation and maintenance expenditures, management and service fees, and appointment or removal of members of the board of directors, provided that certain actions may also require the additional approval of the Oncor Holdings board of directors. The Sempra Order also provides that any changes to the size, composition, structure or rights of the board of directors must first be approved by the PUCT. In addition, if Sempra acquires Texas Transmission’s interest in Oncor, the two board of director positions on Oncor’s board of directors that Texas Transmission is entitled to appoint will be eliminated and the size of Oncor’s board of directors will be reduced by two.  



Additional regulatory commitments, governance mechanisms and restrictions provided in the Sempra Order and our LLC Agreement to ring-fence Oncor from its owners include, among others:





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Basis of Presentation



Our consolidated financial statements have been prepared in accordance with GAAP governing rate-regulated operations. Subsequent events have been evaluated through the date these consolidated financial statements were issued. Our consolidated financial statements include the accounts of Oncor, its subsidiaries, and its consolidated VIEs. All dollar and foreign currency amounts in the financial statements and the notes are stated in U.S. dollars in millions and/or in millions of the applicable foreign currency unless otherwise indicated. Certain prior period amounts have been reclassified to conform to the current period presentation.



Use of Estimates



Preparation of our financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting in connection with pension and OPEB; asset retirement obligations; income and other taxes; hedges for future debt financing; valuation of certain financial assets and liabilities; and accounting for contingencies. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.



Accounting for the Effects of Certain Types of Regulation



We are subject to rate regulation and our financial statements reflect regulatory assets and liabilities in accordance with accounting standards related to the effect of certain types of regulation (ASC 980). Regulatory assets and liabilities represent probable future amounts recoverable from or refundable to customers through the ratemaking process based on PURA, and/or the PUCT’s orders, precedents, or substantive rules. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital subject to PUCT review for reasonableness. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 2 for more information regarding regulatory assets and liabilities.



Revenue Recognition



Our revenues are generally recognized pursuant to tariffs approved by the PUCT or authorized by statute. The majority of revenues are related to providing electric delivery service to consumers. Tariff rates are designed to recover the cost of providing electric delivery service including a reasonable rate of return on invested capital. Revenues related to providing electric delivery service to consumers are generally recognized when the underlying service has been provided in accordance with ASC 606 (revenue from contracts with customers). Revenues related to regulated arrangements based on statutory recovery mechanisms between the utility and the applicable regulators are generally recognized in accordance with ASC 980. See Note 3 for additional information regarding revenues.



Derivatives and Hedging



We are exposed to changes in interest rates and foreign currency exchange rates primarily as a result of our current and expected future debt financings. We use derivative instruments typically designated as cash flow or fair value hedges to help mitigate our exposure related to those risks.



We use interest rate swaps, designated as cash flow hedges, in part, to hedge our interest payments related to our expected future debt financings. The future fixed rate debt issuances underlying these cash flow hedge relationships are largely dependent on market demand and liquidity in the debt market. At December 31, 2025, we believe our forecasted issuances of fixed rate debt in the related cash flow hedge relationships are probable. However, unexpected changes in market conditions in future periods could impact our ability to issue such fixed rate debt, or the timing of any such issuance. If our assumptions regarding the nature and timing of forecasted fixed rate debt issuances were to be inaccurate, we could be required to cease the application of hedge accounting to the related interest rate swaps, which could result in immediate reclassification of all the related gains or losses in AOCI to other (income) and deductions.  



We use cross-currency swaps, designated as fair value hedges, to help mitigate the foreign currency exchange rate risk as a result of the use of foreign currency denominated financing instruments, such as the Euro Notes and CAD Notes. Our existing cross-currency swaps exchange our foreign currency denominated principal payments due at maturity under

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the Euro Notes and CAD Notes into U.S. dollar-denominated notional amounts and swap the foreign currency denominated fixed interest rates for U.S. dollar-denominated fixed interest rates.



See Note 11 for more information regarding our derivative instruments.



Impairment of Long-Lived Assets and Goodwill



We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. 



We also evaluate goodwill for impairment annually, as of October 1, and whenever events or changes in circumstances indicate that an impairment may exist. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows.



For our annual goodwill impairment testing, we generally have the option to directly perform a quantitative assessment or first make a qualitative assessment of whether it is more likely than not that our estimated enterprise fair value is less than our enterprise carrying value before applying the quantitative assessment. If we elect to perform the qualitative assessment, we evaluate relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market considerations, cost factors and our overall financial performance. If, after assessing these qualitative factors, we determine that it is more-likely-than-not that our estimated enterprise fair value is less than our enterprise carrying book value, then we perform a quantitative assessment. If, after performing the quantitative assessment, we determine that goodwill is impaired, we record the amount of goodwill impairment as the excess of enterprise carrying book value over estimated enterprise fair value, not to exceed the carrying amount of goodwill.



For our annual goodwill impairment testing as of October 1, 2025, we elected to make a qualitative assessment of whether it is more likely than not that our enterprise fair value is less than our enterprise carrying value. We concluded that our estimated enterprise fair value was more likely than not greater than our enterprise carrying book value. As a result, no quantitative assessment for impairment was required and no impairment was recognized in 2025.



Goodwill totaling $4.740 billion was reported on our balance sheet at both December 31, 2025 and 2024.



Provision in Lieu of Income Taxes



Our tax sharing agreement with Oncor Holdings, Texas Transmission and STH provides for the calculation of amounts related to income taxes for each of Oncor Holdings and Oncor substantially as if these entities were taxed as corporations and requires payments to the members determined on that basis (without duplication for any income taxes paid by a subsidiary of Oncor Holdings).



We are a partnership for U.S. federal income tax purposes. Accordingly, while partnerships are not subject to income taxes, in consideration of the presentation of our financial statements as an entity subject to cost-based regulatory rate-setting processes, with such costs historically including income taxes, the financial statements present amounts determined under the tax sharing agreement as “provision in lieu of income taxes” and “liability in lieu of deferred income taxes”. Such amounts are determined in accordance with the provisions of the accounting guidance for income taxes and accounting standards that provide interpretive guidance for accounting for uncertain tax positions and thus differences between the book and tax bases of assets and liabilities are accounted for as if we were a stand-alone corporation. In the event such amounts are not paid under the tax sharing agreement, it is probable that this regulatory liability will continue to be included in Oncor’s rate setting processes.



We classify any interest and penalties expense related to uncertain tax positions as current provision in lieu of income taxes as discussed in Note 4.



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Defined Benefit Pension Plans and OPEB Plans



We have liabilities under pension plans that offer benefits based on either a traditional defined benefit formula or a cash balance formula and OPEB Plans that offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. Costs of pension and OPEB Plans are dependent on numerous factors, assumptions and estimates. See Note 9 for additional information regarding pension and OPEB Plans.



System of Accounts



Our accounting records have been maintained in accordance with the FERC Uniform System of Accounts as adopted by the PUCT.



Property, Plant and Equipment



Property, plant and equipment is stated at original cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead and AFUDC.



Depreciation of property, plant and equipment is calculated on a straight-line basis over the estimated useful lives of the properties based on depreciation rates approved by the PUCT. As is common in the industry, depreciation expense is recorded using composite depreciation rates that reflect blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis. Depreciation rates include plant removal costs as a component of depreciation expense, consistent with regulatory treatment. Actual removal costs incurred are charged to accumulated depreciation. Accrued removal costs in excess of incurred removal costs are reclassified as a regulatory liability to retire assets in the future.



Franchise Taxes



Franchise taxes are assessed to us by local governmental bodies, based on kWh delivered and are a principal component of taxes other than amounts related to income taxes as reported in the income statement. Franchise taxes are not a “pass through” item. The rates we charge customers are intended to recover the franchise taxes, but we are not acting as an agent to collect the taxes from customers.



Allowance for Funds Used During Construction



AFUDC is a regulatory cost accounting procedure whereby both interest charges on borrowed funds and a return on equity capital used to finance construction are included in the recorded cost of utility plant and equipment being constructed. AFUDC is capitalized on eligible projects involving construction periods lasting greater than thirty days. The interest portion of capitalized AFUDC is accounted for as a reduction to interest expense and the equity portion of capitalized AFUDC is accounted for as other income. See Note 13 for detail of amounts reducing interest expense and increasing other income.



Cash, Cash Equivalents and Restricted Cash



For purposes of reporting cash and cash equivalents, highly liquid investments with original maturities of three months or less at the date of purchase are considered to be cash equivalents. 



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The following table provides a reconciliation of cash, cash equivalents and restricted cash reported on the Consolidated Balance Sheets to the sum of such amounts reported on the Statements of Consolidated Cash Flows:





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Fair Value of Financial Instruments



The carrying amounts for financial instruments designated as hedging derivatives are recorded at fair value.



The carrying amounts for nonderivative financial assets classified as current assets and the carrying amounts for nonderivative financial liabilities classified as current liabilities approximate fair value due to the short maturity of such nonderivative financial instruments. The fair values of other nonderivative financial instruments, for which carrying amounts and fair values have not been presented, are not materially different than their related carrying amounts.



The following discussion of fair value accounting standards applies primarily to our determination of the fair value of financial instruments designated as hedging derivatives (see Note 11) and nonderivative financial assets in the pension plans’ and OPEB Plans’ trusts (see Note 9) and long-term debt (see Note 6).



Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.



We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:





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We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis.



The fair value of certain investments is measured using the NAV per share as a practical expedient. Such investments measured at NAV are not required to be categorized within the fair value hierarchy.



Contingencies



Our financial results may be affected by judgments and estimates related to contingencies. For loss contingencies, we accrue the loss if an event has occurred on or before the balance sheet date, and:





We do not accrue contingencies that might result in gains. We continuously assess contingencies for litigation claims, environmental remediation and other events. See Note 7 for a discussion of contingencies.



VIE



We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based on qualitative and quantitative analyses, which assesses:





We will continue to evaluate our business operations and VIEs for any changes that may impact our determination of whether an entity is a VIE and if we are the primary beneficiary. See Note 13 for more information on Oncor’s consolidated VIE.



Accounting Standards Updates (ASU)



ASU 2023-09 Improvements to Income Tax Disclosures (ASC 740)



In December 2023, the FASB issued ASU 2023-09, which expands income tax disclosure requirements to include additional information related to the rate reconciliation of our effective tax rates to statutory rates, as well as additional disaggregation of taxes paid. This ASU also removed disclosures related to certain unrecognized tax benefits and deferred taxes. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024. We adopted the standard on December 31, 2025 on a retrospective basis and have provided additional disclosure related to the table of reconciliation of provision in lieu of income taxes computed at the U.S. federal statutory rate to provision in lieu of income taxes in Note 4.



ASU 2024-03 Disaggregation of Income Statement Expenses (ASC 220)



In November 2024, the FASB issued ASU 2024-03, which requires disaggregated disclosure of income statement expenses for public business entities. This ASU adds ASC 220-40 to require a footnote disclosure in tabular presentation about specific expenses by requiring disaggregation of each relevant expense caption on the face of the income statement, when applicable. The ASU does not change or remove existing expense disclosure requirements; however, it may affect where that information appears in the footnotes to the financial statements. ASU 2024-03 will be effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted, and entities may adopt the standard on either a prospective or retrospective basis. We are currently evaluating the effect of the standard on our financial reporting and have not yet selected the year in which we will adopt the standard.



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ASU 2025-06 Targeted Improvements to the Accounting for Internal-Use Software (ASC 350)



In September 2025, the FASB issued ASU 2025-06, which amends certain aspects of the accounting for and disclosure of software costs under ASC 350-40. This ASU makes targeted improvements to ASC 350-40 for accounting for internally developed software costs. The amendments supersede the guidance on website development costs in ASC 350-50 and relocate that guidance, along with the recognition requirements for development costs specific to websites, to ASC 350-40. ASU 2025-06 will be effective for annual reporting periods beginning after December 15, 2027, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted in an interim or annual reporting period in which financial statements have not yet been issued or made available for issuance, and entities may adopt the standard prospectively, retrospectively, or via a modified prospective transition method. We are currently evaluating the effect of the guidance on our financial reporting and have not yet selected the period in which we will adopt the standard.



ASU 2025-11 Narrow-Scope Improvements (ASC 270)



In December 2025, the FASB issued ASU 2025-11, which is intended to improve the navigability of the guidance in ASC 270 and clarify when it applies. Under the amendments, an entity is subject to ASC 270 if it provides “interim financial statements and notes in accordance with GAAP.” The ASU also addresses the form and content of such financial statements, adds lists to ASC 270 of the interim disclosures required by all other Codification topics, and establishes a principle under which an entity must disclose events since the end of the last annual reporting period that have a material impact on the entity. ASU 2025-11 will be effective for interim reporting periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. We are currently evaluating the effect of the guidance on our financial reporting and have not yet selected the period in which we will adopt the standard.



All other newly issued accounting pronouncements not yet effective have been deemed either immaterial or not applicable.

 

2.    REGULATORY MATTERS



Regulatory Proceedings



2025 Comprehensive Base Rate Review (PUCT Docket No. 58306)



In June 2025, we filed a request for a comprehensive base rate review with the PUCT and the 210 cities in our service territory that have retained original jurisdiction over rates. On January 29, 2026, we filed a stipulation in the comprehensive base rate review proceeding requesting PUCT approval of an unopposed, comprehensive settlement among the parties to the proceeding. The stipulation provides for an annual revenue requirement of approximately $6.975 billion, an increase of 8.8% over our adjusted annualized present revenues provided in the rate application. We estimate the terms of the stipulation would result in an aggregate annualized increase over those revenues of approximately $560 million. Moreover, the stipulation also provides for a revised regulatory capital structure ratio of 56.5% debt to 43.5% equity, an authorized return on equity of 9.75%, and an authorized cost of debt of 4.94%. In addition, the stipulation provides for (i) a self-insurance reserve with an annual accrual amount in rates of $200 million for storm costs and other self-insured losses, an increase from the $122 million self-insurance reserve annual accrual amount currently recovered in rates, as well as (ii) a five-year amortization period for applicable regulatory assets and liabilities, which would not include rate case expenses, year-end 2024 deferred SRP costs, and excess accumulated deferred income taxes.



The PUCT may choose to adopt, modify, or reject the stipulation and the proposed order included in the stipulation. New billing rates would be implemented after that final order, and if the proposed new rates in the stipulation are approved as requested, we will surcharge the difference between those new rates and our current rates back to January 1, 2026, pursuant to a previously approved settlement regarding interim rates.



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Capital Tracker Filings



PUCT rules allow for interim rate adjustments for capital trackers that allow utilities to recover, subject to reconciliation, the cost of certain investments before a comprehensive base rate review. As a result of legislation signed into law in 2025 establishing the UTM, which is discussed in detail below, we can now request capital tracker interim rate adjustments each year through the filing of either (i) until 2035, a single UTM application (subject to meeting annual eligibility requirements) or (ii) up to two TCOS capital tracker applications to reflect changes in transmission-related capital investments and up to two DCRF capital tracker applications to reflect changes in distribution-related capital investments.



In 2025, Oncor filed the following capital tracker interim rate adjustment applications with the PUCT:

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In June 2025, the Governor of Texas signed Texas House Bill 5247. The bill establishes the UTM, which allows qualifying electric utilities that operate solely inside ERCOT to (i) apply for a single interim rate update annually through 2035 for cost recovery of certain transmission and distribution capital investments, as an alternative to separate DCRF and TCOS capital tracker filings, and (ii) defer to a regulatory asset costs associated with UTM eligible capital investments as they are placed into service.  Qualifying electric utilities consist of utilities that (i) operate solely inside ERCOT, (ii) have been identified by the PUCT as having responsibility for constructing transmission infrastructure as part of the PBRP, and (iii) make annual capital expenditures in transmission and distribution that exceed 300% of annual depreciation. In January 2026, we filed a notice with the PUCT (PUCT Docket No. 59249) indicating our intent to file a UTM application on or after March 16, 2026, and certifying that we meet the requirements for filing an application.



In anticipation of filing our initial UTM application on or after March 16, 2026 for eligible transmission and distribution investments placed into service after December 31, 2024 through December 31, 2025, we have recorded $104 million in regulatory assets for recoverable costs associated with our UTM eligible transmission and distribution capital investments placed into service and recognized a corresponding $104 million in other regulated revenues in 2025. See “Regulatory Assets and Liabilities” below for more information on the regulatory assets and Note 3 for more information on the recognition of revenues related to the UTM.



Appeal of 2023 Comprehensive Base Rate Review Order (PUCT Docket No. 53601)



In April 2023, the PUCT issued a final order in our comprehensive base rate review filed in May 2022 with the PUCT and the cities in our service territory that have retained original jurisdiction over rates. Base rates implementing the final order went into effect in May 2023. In June 2023, the PUCT issued an order on rehearing in response to the motions for rehearing filed by us and certain intervening parties in the proceeding. The order on rehearing affirmed the material provisions of the final order. In September 2023, we filed an appeal in Travis County District Court. The appeal sought judicial review of certain of the order on rehearing’s rate base disallowances (an acquisition premium and its associated amortization costs relating to certain plant facilities acquired by Oncor in 2019, as well as certain of the employee benefit and compensation-related costs that we had previously capitalized) and related expense effects of those disallowances. In February 2024, the court dismissed the appeal for lack of jurisdiction. In March 2024, we appealed the court’s dismissal to the Fifteenth Court of Appeals in Texas. On August 14, 2025, the Court issued its opinion in favor of the PUCT, denying our argument on appeal. We have elected not to pursue a further appeal.



SRP (PUCT Docket No. 56545)



In November 2024, the PUCT approved our SRP (PUCT Docket No. 56545), which provides for approximately $2.9 billion in capital expenditures and $520 million in operation and maintenance expenses to enhance the resiliency of our

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transmission and distribution system, including measures to address extreme weather, wildfires, physical security threats, and cybersecurity threats. The SRP provides for the majority of the spend to occur between 2025 and 2027, with approximately $300 million in capital expenditures and approximately $20 million in operation and maintenance expenses to be carried over into 2028 and either (i) automatically authorized if Oncor does not file an updated SRP for a future period beginning with 2028 or (ii) included in any subsequent update to the SRP as part of that updated SRP’s first year of spend. We began implementing the approved plan in the fourth quarter of 2024, and are recognizing the recoverable distribution-related operation and maintenance expenses, depreciation expenses, carrying costs on unrecovered balances, and related taxes as a regulatory asset for future recovery in interim rate adjustments or base rate proceedings. In 2025, we recorded $180 million in regulatory assets for distribution-related SRP costs and recognized a corresponding $180 million in other regulated revenues related to the distribution-related SRP. In 2025, we also recorded $3 million in regulatory assets for transmission-related SRP costs. See “Regulatory Assets and Liabilities” below for more information on the regulatory assets and Note 3 for more information on the recognition of revenues related to the SRP.



Regulatory Assets and Liabilities  



We are subject to rate regulation and our financial statements reflect regulatory assets and liabilities in accordance with accounting standards related to the effect of certain types of regulation. Regulatory assets and liabilities represent probable future amounts recoverable from or refundable to customers through the ratemaking process based on PURA, and/or the PUCT’s orders, precedents, or substantive rules. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital subject to PUCT review for reasonableness. The rate of return is generally based on our authorized weighted-average cost of capital. Regulatory decisions can have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates.



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The following table presents components of our regulatory assets and liabilities and their remaining recovery periods in effect at December 31, 2025:

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3.   REVENUES



General



Our revenues are generally recognized pursuant to tariffs approved by the PUCT or authorized by statute. The majority of revenues are related to providing electric delivery service to consumers. Tariff rates are designed to recover the cost of providing electric delivery service to customers including a reasonable rate of return on invested capital. As the volumes delivered can be directly measured, our billed revenues are recognized when the underlying service has been provided. We recognize revenue for the amounts that have been invoiced or that we have the right to invoice. The majority of our revenues are derived from contracts with customers and recognized in accordance with ASC 606. Other regulated revenues resulting from certain regulatory arrangements based on statutory recovery mechanisms between the utility and the applicable regulators are recognized in accordance with ASC 980, including SRP revenues, UTM revenues and alternative revenue program revenues discussed below.



Reconcilable Tariffs



The PUCT has designated certain tariffs (primarily TCRF, EECRF, rate case expense riders and mobile generation riders) as reconcilable, which means the differences between amounts billed under these tariffs and the related incurred costs are deferred as either regulatory assets or regulatory liabilities. Accordingly, at prescribed intervals, future tariffs are adjusted to either collect regulatory assets or refund regulatory liabilities. 



Other Regulated Revenues



SRP Revenues 



SRP revenues are recognized for the recoverable SRP distribution-related operation and maintenance expenses, depreciation expenses, carrying costs on unrecovered balances and related taxes that are eligible for future rate recovery. See Note 2 for additional information regarding the SRP.



UTM Revenues 



UTM revenues are recognized for the recoverable costs associated with transmission and distribution capital investments placed into service after December 31, 2024, including depreciation expenses, carrying costs on unrecovered balances and related taxes that are eligible for future rate recovery. See Note 2 for additional information regarding the UTM.



Alternative Revenue Program Revenues

(Energy Efficiency Program Performance Bonus Revenues)



The PUCT has implemented an incentive program allowing us to earn energy efficiency program performance bonuses by exceeding PURA-mandated energy efficiency program targets. This incentive program and the related performance bonus revenues are considered alternative revenue program revenues under ASC 980. Annual performance bonuses are generally recognized as revenue when approved by the PUCT, typically in the third or fourth quarter each year. The PUCT approved annual energy efficiency program performance bonuses of $33 million and $17 million in 2025 and 2024, respectively, which we recognized in other regulated revenues.



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Disaggregation of Revenues 



The following table reflects electric delivery revenues disaggregated by tariff:



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Customers



At December 31, 2025, our distribution business customers primarily consisted of over 100 REPs that sell electricity we distribute to end-use consumers in our certificated service area. The majority of consumers of the electricity we deliver through our distribution business are free to choose their electricity supplier from REPs who compete for their business. Our wholesale transmission revenues are collected from load serving entities benefitting from our transmission system. Our transmission business customers consist of municipally-owned utilities, electric cooperatives and other distribution companies. Revenues from REP subsidiaries of our two largest customers, collectively represented 25% and 21%, respectively, of our total operating revenues for the year ended December 31, 2025, and 25% and 23%, respectively, of our

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total operating revenues for each of the years ended December 31, 2024 and December 31, 2023. No other customer represented more than 10% of our total operating revenues during such periods.



Variability



Our revenues and cash flows are subject to seasonality, timing of customer billings, weather conditions and other electricity usage drivers, with revenues typically highest in the summer season. Payment of customer billings is due 35 days after invoicing. Under a PUCT rule relating to the Certification of Retail Electric Providers, write-offs of uncollectible amounts owed by REPs are recoverable as a regulatory asset. 



Pass-through Expenses



Revenues equal to expenses that are allowed to be passed-through to customers (primarily third-party wholesale transmission service and energy efficiency program costs) are recognized at the time the expense is recognized. Franchise taxes are assessed by local governmental bodies, based on kWh delivered and are not a “pass-through” item. The rates we charge customers are intended to recover the franchise taxes, but we are not acting as an agent to collect the taxes from customers; therefore, franchise taxes are reported as a principal component of “taxes other than amounts related to income taxes” instead of a reduction to “revenues” in the income statement.



4.    PROVISION IN LIEU OF INCOME TAXES



Components of Liability in Lieu of Deferred Income Taxes



The components of our liability in lieu of deferred income taxes are provided in the table below:





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Provision (Benefit) in Lieu of Income Taxes



The components of our reported provision (benefit) in lieu of income taxes are as follows:



Reconciliation of provision in lieu of income taxes computed at the U.S. federal statutory rate to provision in lieu of income taxes:

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The net amounts of $2.841 billion and $2.552 billion reported in the balance sheets at December 31, 2025 and 2024, respectively, as liability in lieu of deferred income taxes include amounts previously recorded as net deferred tax liabilities. In connection with the sale of equity interests to Texas Transmission in 2008, we became a partnership for U.S. federal income tax purposes, and the temporary differences that gave rise to the deferred taxes will, over time, become taxable to

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the equity holders. Under a tax sharing agreement among us and our equity holders (see Note 1), we make payments to the equity holders related to income taxes when amounts would have become due to the I.R.S. if Oncor was taxed as a corporation. Accordingly, as the temporary differences become taxable, we will pay the equity holders. In the event such amounts are not paid under the tax sharing agreement, it is probable that this regulatory liability will continue to be included in Oncor’s rate setting processes.



Accounting For Uncertainty in Provision in Lieu of Income Taxes



For federal income tax purposes, the statute of limitations is open for partnership tax returns for the years beginning after December 31, 2021. We filed refund claims for the tax years ending December 31, 2018 through 2021, but no additional tax may be assessed for these tax years. 



Texas margin tax returns are still open for tax years beginning after 2020. We have filed refund claims for the tax year ending December 31, 2018 through 2021 (2019 through 2022 report years), but no additional tax may be assessed for the tax years ending December 31, 2018 through 2020.



We are not a member of another entity’s consolidated tax group and assess our liability for uncertain tax positions in our partnership returns. The following table represents the changes to the uncertain tax positions reported in other noncurrent liabilities in our consolidated balance sheets for the years ended December 31, 2025, 2024 and 2023:



Noncurrent liabilities included $2 million and $1 million of accrued interest related to uncertain tax positions each at December 31, 2025 and 2024. Furthermore, there was $1 million recorded related to interest and penalties in each of the years ended December 31, 2025, 2024 and 2023. The federal income tax benefit on the interest accrued on uncertain tax positions, if any, is recorded as liability in lieu of deferred income taxes.



Tax Impact from OBBBA



The OBBBA was signed into law in July 2025. The OBBBA includes revisions of the Inflation Reduction Act enacted in 2022 and extends or revises key provisions of the TCJA. Included in the OBBBA is the immediate expensing of domestic research and experimental expenditures, including internally developed software expenditures, under Code Section 174A. This change supersedes prior rules requiring a five-year amortization of domestic research and experimental expenditures under the TCJA. In accordance with I.R.S. transitional guidance (Revenue Procedure 2025-28), we plan to elect to accelerate deductions for domestic unamortized software development expenditures incurred in tax years 2022 through 2024, with remaining balances deductible in tax year 2025. As a result, we included  a tax deduction of $377 million (tax effect of $79 million) in the 2025 income tax provision. The deduction does not have a material impact on the consolidated financial statements and has no impact on the effective tax rate. We will continue to monitor guidance issued by the U.S. Department of the Treasury and the I.R.S.



See Note 10 for more information regarding the tax sharing agreement.



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5.    SHORT-TERM BORROWINGS   



The following table reflects our outstanding short-term borrowings and available unused borrowing capacity under the $2B Credit Facility and CP Program at December 31, 2025 and 2024:



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$2B Credit Facility



On February 20, 2025, we entered into an amended and restated unsecured revolving $2B Credit Facility. On February 20, 2026, we entered into an amendment to the $2B Credit Facility to, among other things, extend the maturity date by one year and to remove the SOFR Adjustment. The $2B Credit Facility has a borrowing capacity of $2.0 billion and a maturity date of February 20, 2031. The $2B Credit Facility gives us the option to request an increase in our borrowing capacity of up to $650 million in $100 million minimum increments, subject to certain conditions, including lender approvals. The $2B Credit Facility also provides us with the option to request that each lender extend the term of its commitment for up to two additional one-year periods, subject to certain conditions, including lender approvals. Borrowings under the $2B Credit Facility, if any, are classified as short-term on the balance sheet.



Borrowings under the $2B Credit Facility bear interest at a per annum rate equal to, at our option, (i) term SOFR for the interest period relevant to such borrowing plus an applicable margin of between 0.750% and 1.250%, depending on certain credit ratings assigned to our debt, or (ii) an alternate base rate (equal to the greatest of (1) the prime rate as quoted by The Wall Street Journal on such date, (2) the federal funds effective rate on such date, plus 0.50%, and (3) term SOFR for a one-month interest period on such date plus 1.0%), plus, in the case of clauses (1) through (3), an applicable margin of between 0.00% and 0.25%, depending on certain credit ratings assigned to our debt. The $2B Credit Facility also provides for an alternative rate of interest upon the occurrence of certain events related to the current rate of interest benchmark.



A commitment fee is payable quarterly in arrears and upon termination or reduction of the revolving commitments at a rate per annum equal to between 0.060% and 0.175%, depending on certain credit ratings assigned to our debt, of the unborrowed commitments under the $2B Credit Facility. Letter of credit fees under the $2B Credit Facility are payable quarterly in arrears and upon expiration or if a letter of credit is drawn in full at a rate per annum equal to the applicable margin for term SOFR under the $2B Credit Facility. Fronting fees in an amount as separately agreed by us and any fronting bank that issues a letter of credit are also payable quarterly in arrears and upon termination to each such fronting bank.



The $2B Credit Facility requires that we maintain a maximum consolidated senior debt to consolidated total capitalization ratio of 0.65 to 1.00 and observe certain customary reporting requirements and other customary covenants for facilities of this type.



The $2B Credit Facility also contains customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments, including certain changes in control of Oncor that are not permitted transactions under the $2B Credit Facility and cross-default provisions in the event we or certain of our subsidiaries defaults in the payment of principal or interest due in respect of any indebtedness in a principal amount in excess of $150 million or fails to observe or perform any other term, covenant, condition or agreement contained in any agreement or instrument evidencing such indebtedness if such failure results in acceleration of the maturity of such indebtedness or receives judgments for the payment of money in excess of $150 million that are not discharged or stayed within 60 days.



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CP Program



We have established a CP Program, under which we may issue unsecured CP Notes on a private placement basis with maturity dates not exceeding 397 days from the date of issuance. To the extent any CP Notes are issued with maturity dates of over one year, we anticipate those would be classified as long-term debt and obtain liquidity support under the $1B Credit Facility (See Note 6 for more information regarding the $1B Credit Facility). We anticipate that any CP Notes issued under the CP Program with a maturity date equal to or less than a year would be classified as short-term debt and obtain liquidity support under the $2B Credit Facility. Total CP Notes outstanding at any time may not exceed a maximum amount of $3.0 billion, and we operate the CP Program to ensure that the aggregate amount of CP Notes obtaining liquidity support from the applicable credit facility, when combined with any outstanding borrowings under such credit facility, do not exceed the maximum borrowing capacity of such credit facility.

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6.    LONG-TERM DEBT



At December 31, 2025, our outstanding long-term debt consisted of U.S. dollar-denominated, euro-denominated and Canadian dollar-denominated fixed rate senior secured notes, variable rate secured debt borrowed under the AR Facility, and variable rate unsecured debt borrowed under the $500M Credit Facility and the Term Loan Credit Agreement.



The following table is a summary of our outstanding long-term debt at December 31, 2025 and 2024:



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At December 31, 2025 and 2024, our outstanding U.S. dollar-denominated fixed rate senior secured notes consisted of the following:



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Senior Secured Notes Activities



   Senior Secured Notes Issuances



Issuance of Senior Secured Notes Under Indenture (2029 Notes)



In January 2025, we issued $100 million aggregate principal amount of our 4.65% Senior Secured Notes due 2029 (the 2029 Notes). The 2029 Notes constitute an additional issuance of our 4.65% Senior Secured Notes due 2029, $550 million of which we previously issued on November 13, 2024 and are currently outstanding. The 2029 Notes were issued under one of our existing indentures and are secured pursuant to the Deed of Trust. We used the net proceeds from the sale of the 2029 Notes for general corporate purposes, including to repay a portion of the CP Notes then outstanding.



The 2029 Notes bear interest at a rate of 4.65% per annum and mature on November 1, 2029. Interest on the 2029 Notes accrued from November 13, 2024 and is payable semi-annually on May 1 and November 1 of each year, beginning on May 1, 2025. Prior to October 1, 2029, we may redeem the 2029 Notes at any time, in whole or in part, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. On and after October 1, 2029, we may redeem the 2029 Notes at any time, in whole or in part, at a redemption price equal to 100% of the principal amount of the 2029 Notes, plus accrued and unpaid interest.



Issuance of 2025 NPA Notes



On January 30, 2025, we issued $250 million aggregate principal amount of our 5.15% Senior Secured Notes, Series H, due May 1, 2029 (the Series H Notes). On February 27, 2025, we issued $150 million aggregate principal amount of our 5.59% Senior Secured Notes, Series I, due May 1, 2034 (the Series I Notes). The Series H Notes and the Series I Notes were issued pursuant to the Note Purchase Agreement, dated January 30, 2025, between Oncor and the purchasers named therein (2025 NPA). We used the proceeds from the sale of the Series H Notes and the Series I Notes for general corporate purposes, including to repay a portion of the CP Notes then outstanding.



The Series H Notes bear interest at a rate of 5.15% per annum and mature on May 1, 2029. Interest on the Series H Notes accrued from January 30, 2025 and will be payable semi-annually on May 1 and November 1 of each year, beginning on November 1, 2025. The Series I Notes bear interest at a rate of 5.59% per annum and mature on May 1, 2034. Interest on the Series I Notes accrued from February 27, 2025 and will be payable semi-annually on May 1 and November 1 of each year, beginning on November 1, 2025. Prior to April 1, 2029 in the case of the Series H Notes and April 1, 2034 in the case of the Series I Notes, we may redeem such notes at any time, in whole or in part, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. On and after April 1, 2029 in the case of the Series H Notes and April 1, 2034 in the case of the Series I Notes, we may redeem such notes at any time, in whole or in part, at a redemption price equal to 100% of the principal amount of such notes, plus accrued and unpaid interest.

The 2025 NPA contains customary covenants, restricting, subject to certain exceptions, us from, among other things, entering into mergers and consolidations, and sales of substantial assets. In addition, the 2025 NPA requires that we maintain a consolidated senior debt to consolidated total capitalization ratio of no greater than 0.65 to 1.00.

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The 2025 NPA also contains customary events of default, including the failure to pay principal or interest on the Series H Notes and the Series I Notes when due, among others. If any such event of default occurs and is continuing, among other remedies provided in the 2025 NPA, the outstanding principal of the Series H Notes and the Series I Notes may be declared due and payable.



Issuance of Senior Secured Notes Under Indenture (2027 Notes/2035 Notes/2055 Notes)



On March 20, 2025, we issued (i) $500 million aggregate principal amount of our 4.50% Senior Secured Notes due 2027 (the 2027 Notes), (ii) $650 million aggregate principal amount of our 5.35% Senior Secured Notes due 2035 (the 2035 Notes), and (iii) $650 million aggregate principal amount of our 5.80% Senior Secured Notes due 2055 (the 2055 Notes, and together with the 2027 Notes and the 2035 Notes, the Notes Issued March 2025). The Notes Issued March 2025 were issued under one of our existing indentures and are secured pursuant to the Deed of Trust. We used the net proceeds from the sale of the Notes Issued March 2025 for general corporate purposes, including to repay the full $300 million aggregate principal amount then-outstanding under the AR Facility and to repay then-outstanding CP Notes. We issued the CP Notes to fund working capital, to repay the entire $350 million aggregate principal amount of the 2.95% 2025 Notes that were redeemed in full on March 14, 2025, and to pay amounts deposited with the trustee on March 19, 2025, to extinguish all of our 0.55% 2025 Notes.



The 2027 Notes, the 2035 Notes and the 2055 Notes bear interest at the rate of 4.50%,  5.35% and 5.80% per annum, respectively. Interest on the 2027 Notes accrued from March 20, 2025 and is payable semi-annually in arrears on March 20 and September 20 of each year, and at maturity, beginning on September 20, 2025. Interest on the 2035 Notes and the 2055 Notes accrued from March 20, 2025 and is payable semi-annually in arrears on April 1 and October 1 of each year, and at maturity, beginning on October 1, 2025. The 2027 Notes, the 2035 Notes and the 2055 Notes mature on March 20, 2027, April 1, 2035 and April 1, 2055, respectively. At any time prior to their maturity date of March 20, 2027, in the case of the 2027 Notes, January 1, 2035, in the case of the 2035 Notes and October 1, 2054, in the case of the 2055 Notes, we may redeem such notes in whole or in part, at a redemption price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. At any time on or after January 1, 2035, in the case of the 2035 Notes and October 1, 2054, in the case of the 2055 Notes, we may redeem such Notes, in whole or in part, at 100% of the principal amount being redeemed plus accrued and unpaid interest thereon to but excluding the date fixed for redemption.



Issuance of 2034 Euro Notes Under Indenture



On June 16, 2025, we issued €700 million aggregate principal amount of 2034 Euro Notes. The 2034 Euro Notes were issued under one of our existing indentures and are secured pursuant to the Deed of Trust. Our euro-denominated fixed rate payment obligations under the 2034 Euro Notes were effectively converted to U.S. dollar-denominated fixed rate payment obligations at issuance through concurrently-executed cross-currency swaps, which are expected to mitigate foreign currency exchange risk associated with the interest and principal payments on the 2034 Euro Notes that are due in euros. As a result of the cross-currency swaps, the U.S. dollar principal amount due on the 2034 Euro Notes at maturity will be $805 million, and the all-in U.S. dollar fixed rate coupon on the 2034 Euro Notes is 5.4405%. See Note 10 for more information on our cross-currency swaps activities.



We used the net proceeds from the sale of the 2034 Euro Notes for general corporate purposes, including to repay the full $210 million aggregate principal amount then-outstanding under the AR Facility and to repay then-outstanding CP Notes.



The 2034 Euro Notes bear interest at a rate of 3.625% per annum and mature on June 15, 2034. Interest on the 2034 Euro Notes accrued from June 16, 2025 and will be payable annually on June 15 of each year, and at maturity, beginning on June 15, 2026. At any time prior to March 15, 2034, we may redeem the 2034 Euro Notes in whole or in part, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. At any time on or after March 15, 2034, we may redeem the 2034 Euro Notes in whole or in part, at a redemption price equal to 100% of the principal amount being redeemed plus accrued and unpaid interest thereon to but excluding the date fixed for redemption. We may also redeem the 2034 Euro Notes for cash in whole, but not in part, at the redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if certain tax events occur that would obligate us to pay certain additional amounts.



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Issuance of CAD Notes Under Indenture



On September 26, 2025, we issued C$500 million aggregate principal amount of CAD Notes. The CAD Notes were issued under one of our existing indentures and are secured pursuant to the Deed of Trust. Our Canadian dollar-denominated fixed rate payment obligations under the CAD Notes were effectively converted to U.S. dollar-denominated fixed rate payment obligations at issuance through concurrently-executed cross-currency swaps, which are expected to mitigate foreign currency exchange risk associated with the interest and principal payments on the CAD Notes that are due in Canadian dollars. As a result of the cross-currency swaps, the U.S. dollar principal amount due on the CAD Notes at maturity will be $361 million, and the all-in U.S. dollar fixed rate coupon on the CAD Notes is 5.022%. See Note 10 for more information on our cross-currency swaps activities.



We used the net proceeds from the sale of the CAD Notes for general corporate purposes,  including to repay then-outstanding CP Notes.



The CAD Notes bear interest at a rate of 4.20% per annum and mature on October 1, 2035. Interest on the CAD Notes accrued from September 26, 2025 and will be payable semi-annually on April 1 and October 1 of each year, and at maturity, beginning on April 1, 2026. At any time prior to July 1, 2035, we may redeem the CAD Notes in whole or in part, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. At any time on or after July 1, 2035, we may redeem the CAD Notes in whole or in part, at a redemption price equal to 100% of the principal amount being redeemed plus accrued and unpaid interest thereon to but excluding the date fixed for redemption. We may also redeem the CAD Notes for cash in whole, but not in part, at the redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if certain tax events occur that would obligate us to pay certain additional amounts.



Senior Secured Notes Repayment 



On March 14, 2025, we repaid the entire $350 million aggregate principal amount of the 2.95% 2025 Notes that were redeemed in full. The 2.95% 2025 Notes had a maturity date of April 1, 2025. With the redemption of the 2.95% 2025 Notes, none of the 2.95% 2025 Notes remain outstanding. 



On December 3, 2025, we repaid in full at maturity the $174 million aggregate principal amount of our Series A Notes.



On January 14, 2026, we repaid in full at maturity the $38 million aggregate principal amount of our Series B Notes.



Senior Secured Notes Extinguishment



On March 19, 2025, we extinguished all of the 0.55% 2025 Notes, of which $450 million aggregate principal amount was outstanding. The 0.55% 2025 Notes matured on October 1, 2025. Pursuant to the terms of the indenture and officer’s certificate governing the 0.55% 2025 Notes, we irrevocably deposited with the trustee cash and U.S. Treasury Notes in an amount sufficient for defeasance of the 0.55% 2025 Notes, whereby our indebtedness in respect of the 0.55% 2025 Notes was satisfied and discharged. The trustee paid the holders of the 0.55% 2025 Notes in full on October 1, 2025. We recognized a $9 million unamortized gain on extinguishment as a regulatory liability due to the pricing of the U.S. Treasury Notes deposited with the trustee. See Note 2 for more details.



Deed of Trust



Our long-term senior secured notes are secured equally and ratably by a first priority lien on all property acquired or constructed by us for use in our electricity transmission and distribution business, subject to certain exceptions. The property is mortgaged under the Deed of Trust. The Deed of Trust permits us to secure indebtedness with the lien of the Deed of Trust up to the aggregate of (i) the amount of available bond credits, and (ii) 85% of the lower of the fair value or cost of certain property additions that could be certified to the Deed of Trust collateral agent.



Long-Term Revolving Facilities 



Our long-term revolving borrowing capacity includes the borrowing capacities under the AR Facility, the $500M

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Credit Facility and the $1B Credit Facility. The following table reflects available long-term borrowing capacities under the AR Facility, the $500M Credit Facility and the $1B Credit Facility at December 31, 2025 and 2024:





AR Facility

  

In April 2023, we and our bankruptcy-remote special purpose entity Receivables LLC, a wholly owned subsidiary of Oncor, established the AR Facility, a revolving accounts receivable securitization facility. Under the terms of the AR Facility, Oncor sells or contributes all of its existing and future accounts receivable from REPs and certain related rights to Receivables LLC as contemplated by the terms of the AR Facility. Receivables LLC then pledges those REP receivables and related rights to the lenders under the AR Facility as collateral for borrowings. Oncor serves as servicer of the AR Facility and receives a fee from Receivables LLC equal to 1.00% per annum of the aggregate unpaid balance of receivables as of the last day of each settlement period.

 

Receivables LLC’s sole business consists of the purchase or acceptance through capital contributions of the receivables and related rights from Oncor and the subsequent retransfer of or granting of a security interest in such receivables and related rights to the administrative agent for the benefit of the lenders pursuant to the receivables financing agreement. Receivables LLC is a separate legal entity with its own separate creditors who will be entitled, upon its liquidation, to have amounts owed to them be satisfied out of Receivables LLC’s assets prior to any assets or value in Receivables LLC becoming available to Receivables LLC’s equity holder. The assets of Receivables LLC are not available to pay creditors of Oncor or any affiliate thereof.



Receivables LLC is considered a VIE. See Note 13 for more information related to our consolidated VIE.



Oncor has access to the AR Facility, under which Receivables LLC may borrow at any one time an amount equal to the borrowing base. The borrowing base is defined under the receivables financing agreement as an amount equal to the lesser of (i) the facility limit of $500 million or (ii) the amount calculated based on the outstanding balance of eligible receivables held as collateral at a particular time, subject to certain reserves, concentration limits, and other limitations. Borrowings under the AR Facility bear interest at the daily cost of asset-backed commercial paper issued by the conduit lenders to fund the loans, plus related dealer commissions and note issuance costs, or, if funded by the committed lenders, a rate per annum equal to SOFR calculated based on term SOFR for a one-month interest period, plus the SOFR Adjustment. Receivables LLC also pays a used and unused fee in connection with the AR Facility.



The agreements relating to the AR Facility contain customary representations and warranties and affirmative and negative covenants. The agreements relating to the AR Facility also contain customary events of default for a facility of this type, the occurrence of which provides for the acceleration of all outstanding loans made under the AR Facility, including Receivables LLC’s failure to pay interest or other amounts due, Receivables LLC becoming insolvent or subject to bankruptcy proceedings or certain judicial judgments or breaches of certain representations and warranties and covenants.



In May 2025, the scheduled termination date of the AR Facility was extended by one year from April 28, 2027 to April 28, 2028. The AR Facility will terminate at the earlier of (i) the scheduled termination date of April 28, 2028, (ii) the date on which the termination date is declared or deemed to have occurred upon the exercise of remedies by the administrative agent, or (iii) the date that is 30 days after notice of termination is provided by Receivables LLC. Subject to the consent of the administrative agent and the lenders, Receivables LLC may, 30 days prior to each anniversary date of the receivables financing agreement, extend the AR Facility in one-year increments subject to lender approvals.



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The following table summarizes the activity under the AR Facility in 2025:







At December 31, 2025, the borrowing base for the AR Facility was $500 million and $325 million aggregate principal amount of borrowings were outstanding under the AR Facility.  



On January 29, 2026, we borrowed an additional $150 million under the AR Facility.



$500M Credit Facility



In February 2024, we entered into an unsecured revolving $500M Credit Facility. The $500M Credit Facility has a borrowing capacity of $500 million and a maturity date of February 21, 2027. The $500M Credit Facility gives us the option to request an increase in our borrowing capacity of up to $500 million in $100 million minimum increments, subject to certain conditions, including lender approvals. The $500M Credit Facility also provides us with the option to request that each lender extend the term of its commitment for up to two additional one-year periods, subject to certain conditions, including lender approvals.



Borrowings under the $500M Credit Facility bear interest at a per annum rate equal to, at our option, (i) term SOFR for the interest period relevant to such borrowing, plus the SOFR Adjustment, plus an applicable margin of between 0.875% and 1.500%, depending on certain credit ratings assigned to our debt, or (ii) an alternate base rate (equal to the greatest of (1) the prime rate publicly announced from time to time by the administrative agent as its prime rate, (2) the federal funds effective rate, plus 0.50%, and (3) term SOFR for a one-month interest period on such date, plus the SOFR Adjustment, plus 1.0%), plus, in the case of clauses (1) through (3), an applicable margin of between 0.00% and 0.50%, depending on certain credit ratings assigned to our debt. The $500M Credit Facility also provides for an alternative rate of interest upon the occurrence of certain events related to the current rate of interest benchmark.



A commitment fee is payable quarterly in arrears and upon termination or the reduction of the revolving commitments at a rate per annum equal to between 0.075% and 0.625% of the unborrowed commitments under the $500M Credit Facility, depending on certain credit ratings assigned to our debt and the utilization percentage. The utilization percentage is determined by dividing the aggregate principal amount of loans outstanding under the $500M Credit Facility by the total commitments.



The $500M Credit Facility requires that we maintain a maximum consolidated senior debt to consolidated total capitalization ratio of 0.65 to 1.00 and observe certain customary reporting requirements and other customary covenants for facilities of this type.



The $500M Credit Facility also contains customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments, including certain changes in control of Oncor that are not permitted transactions under the $500M Credit Facility and cross-default provisions in the event we or any of our subsidiaries default on indebtedness in a principal amount in excess of $100 million or receive judgments for the payment of money in excess of $100 million that are not discharged or stayed within 60 days.



There were $480 million in aggregate borrowings outstanding under the $500M Credit Facility at December 31, 2025. The remaining borrowing capacity was $20 million at December 31, 2025. 



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$1B Credit Facility



On February 20, 2025, we entered into an unsecured revolving $1B Credit Facility. On February 20, 2026, we entered into an amendment to the $1B Credit Facility to, among other things, extend the maturity date by one year and to remove the SOFR Adjustment. The $1B Credit Facility has a borrowing capacity of $1.0 billion and a maturity date of February 20, 2029. The $1B Credit Facility gives us the option to request an increase in our borrowing capacity of up to $350 million in $100 million minimum increments, subject to certain conditions, including lender approvals. The $1B Credit Facility also provides us with the option to request that each lender extend the term of its commitment for up to two additional one-year periods, subject to certain conditions, including lender approvals.



Borrowings under the $1B Credit Facility bear interest at a per annum rate equal to, at our option, (i) term SOFR for the interest period relevant to such borrowing plus an applicable margin of between 0.750% and 1.250%, depending on certain credit ratings assigned to our debt, or (ii) an alternate base rate (equal to the greatest of (1) the prime rate as quoted by The Wall Street Journal on such date, (2) the federal funds effective rate on such date, plus 0.50%, and (3) term SOFR for a one-month interest period on such date plus 1.0%), plus, in the case of clauses (1) through (3), an applicable margin of between 0.00% and 0.25%, depending on certain credit ratings assigned to our debt. The $1B Credit Facility also provides for an alternative rate of interest upon the occurrence of certain events related to the current rate of interest benchmark.



A commitment fee is payable quarterly in arrears and upon termination or reduction of the revolving commitments at a rate per annum equal to between 0.040% and 0.150%, depending on certain credit ratings assigned to our debt, of the unborrowed commitments under the $1B Credit Facility.



The $1B Credit Facility requires that we maintain a maximum consolidated senior debt to consolidated total capitalization ratio of 0.65 to 1.00 and observe certain customary reporting requirements and other customary covenants for facilities of this type.



The $1B Credit Facility also contains customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments, including certain changes in control of Oncor that are not permitted transactions under the $1B Credit Facility and cross-default provisions in the event we or certain of our subsidiaries defaults in the payment of principal or interest due in respect of any indebtedness in a principal amount in excess of $150 million or fails to observe or perform any other term, covenant, condition or agreement contained in any agreement or instrument evidencing such indebtedness if such failure results in acceleration of the maturity of such indebtedness or receives judgments for the payment of money in excess of $150 million that are not discharged or stayed within 60 days.



At December 31, 2025, there were no borrowings under the $1B Credit Facility.



Term Loan Credit Agreement



On December 23, 2025, we entered into an unsecured $1.4 billion Term Loan Credit Agreement that matures on March 1, 2027. On December 26, 2025, we borrowed $925 million aggregate principal amount. The proceeds from this borrowing were used for general corporate purposes, including to repay then-outstanding CP Notes. Such repaid CP Notes were issued by us for general corporate purposes, including to repay in full the Series A Notes plus accrued and unpaid interest. On January 29, 2026, we borrowed $475 million aggregate principal amount. The proceeds from this borrowing were used for general corporate purposes, including to repay then-outstanding CP Notes. Following the borrowing in January 2026, no additional amounts remain available for borrowing under the Term Loan Credit Agreement.



Borrowings under the Term Loan Credit Agreement bear interest at a per annum rate equal to, at our option, (i) term SOFR for the interest period relevant to such borrowing plus an applicable margin of 0.875%, or (ii) an alternate base rate (equal to the greatest of (1) the prime rate as quoted by The Wall Street Journal on such date, (2) the federal funds effective rate on such date, plus 0.50%, and (3) term SOFR for a one-month interest period on such date plus 1.0%). The Term Loan Credit Agreement also provides for a commitment fee at a rate per annum of 0.05% on the daily average available

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commitment during the funding availability period and an alternative rate of interest upon the occurrence of certain events related to the current rate of interest benchmark.



The Term Loan Credit Agreement requires that we maintain a maximum consolidated senior debt to consolidated total capitalization ratio of 0.65 to 1.00 and observe certain customary reporting requirements and other customary covenants for facilities of this type.



The Term Loan Credit Agreement also contains customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments, including certain changes in control of Oncor that are not permitted transactions under the Term Loan Credit Agreement and cross-default provisions in the event we or certain of our subsidiaries defaults in the payment of principal or interest due in respect of any indebtedness in a principal amount in excess of $150 million or fails to observe or perform any other term, covenant, condition or agreement contained in any agreement or instrument evidencing such indebtedness if such failure results in acceleration of the maturity of such indebtedness or receives judgments for the payment of money in excess of $150 million that are not discharged or stayed within 60 days.



Maturities



Long-term debt maturities at December 31, 2025, are as follows:





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Fair Value of Long-Term Debt



At December 31, 2025 and 2024, the estimated fair value of our long-term debt (net of unamortized discount, premium and debt issuance costs) totaled $18.176 billion and $13.446 billion, respectively, and the carrying amount totaled $19.043 billion and $15.234 billion, respectively. The fair value is estimated using observable market data, representing Level 2 valuations under accounting standards related to the determination of fair value.



7.COMMITMENTS AND CONTINGENCIES



Leases



General



A lease exists when a contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. As lessee, our leased assets primarily consist of our vehicle fleet and real estate leased for company offices and service centers. Our leases are accounted for as operating leases for GAAP purposes. At both December 31, 2025 and 2024, we had $3 million in GAAP operating leases for temporary emergency electric energy facilities that are treated as finance leases solely for rate-making purposes as required by PURA. Operating lease costs that are not capitalized are generally recognized as operating expenses on a straight-line basis over the lease term. We are not a lessor to any material lease contracts.

 

As of the lease commencement date, we recognize a lease liability for our obligation to make lease payments, which we initially measure at present value using our incremental borrowing rate at the date of lease commencement, unless the rate implicit in the lease is readily determinable. We determine our incremental borrowing rate based on the rate of interest

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that we would have to pay to borrow an amount equal to the lease payments on a collateralized basis over a similar term in a similar economic environment. We also record a ROU asset for our right to use the underlying asset, which is initially equal to the lease liability and adjusted for any lease payments made at or before lease commencement, lease incentives and any initial direct costs.



Some of our lease agreements contain nonlease components, which represent items or activities that transfer a good or service. We separate lease components from nonlease components, if any, for our fleet vehicle and real estate leases for purposes of calculating the related lease liability and ROU asset.



Certain of our leases include options to extend the lease terms for up to 20 years, while others include options to terminate early. Our lease liabilities and ROU assets are based on lease terms that may include such options to extend or terminate the lease when it is reasonably certain that we will exercise that option.



Short-term Leases



Some of our contracts are short-term leases, which have a lease term of 12 months or less at lease commencement. As allowed by GAAP, we do not recognize a lease liability or ROU asset arising from short-term leases for all existing classes of underlying assets. We recognize short-term lease costs on a straight-line basis over the lease term.



Lease Obligations, Lease Costs and Other Supplemental Data



The following table presents GAAP operating lease related balance sheet information:





The following table presents costs related to lease activities:





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The following table presents lease related cash flows and other information:





The following table presents the maturity analysis of our operating lease liabilities and reconciliation to the present value of lease liabilities:









Sales and Use Tax Audits



We are subject to sales and use tax audits in the normal course of business. As of December 31, 2025, the Texas State Comptroller’s office was conducting one sales and use tax audit for audit periods covering January 2018 through December 2022. While the outcome of these ongoing audits is uncertain, based on our analysis, we do not expect the ultimate resolutions of these ongoing audits will have a material adverse effect on our financial position, results of operations, or cash flows.



In December 2025, we reached a final settlement agreement with the Texas State Comptroller’s office for the sales and use tax audit for the July 2013 through December 2017 audit period that resulted in a net $36 million refund. The effects of the net settlement recorded in December 2025 reflect a $26 million reduction in property, plant and equipment in the Consolidated Balance Sheets related to sales tax previously capitalized, and a $7 million reduction in operation and maintenance expense and $3 million credited to other (income) and deductions – net in the Statements of Consolidated Income related to sales tax previously expensed and associated interest income.



Energy Efficiency Spending



We are required to annually invest in programs designed to improve customer electricity demand and consumption efficiencies to satisfy ongoing regulatory requirements. The requirement for the year 2026 is $64 million, which is recoverable through EECRF rates.



Legal/Regulatory Proceedings  



See Note 2 above for additional information regarding certain regulatory proceedings. We are also involved in other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect upon our financial position, results of operations, or cash flows.



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Labor Contracts



At December 31, 2025, approximately 15% of our full-time employees were represented by a labor union and covered by a collective bargaining agreement that expires in October 2026.



Contractual Purchase Obligations



At December 31, 2025, we had contractual purchase obligations in the amount of $185 million under outsourcing agreements over the five-year period 2026 through 2030.



Environmental Contingencies



We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We are in compliance with all current laws and regulations. The impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable. The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:





We have not identified any significant potential environmental liabilities at this time. 



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8.    MEMBERSHIP INTERESTS



Capital Contributions



On February 12, 2026, we received cash capital contributions from our members totaling $1.091  billion. During 2025, we received the following cash capital contributions from our members:    



Distributions



The Sempra Order and our LLC Agreement set forth various restrictions on distributions to our members. Among those restrictions is the commitment that we will make no distributions (other than contractual tax payments) to our members that would cause us to exceed our debt-to-equity ratio authorized by the PUCT. The distribution restrictions also include the ability of a majority of our Disinterested Directors, or either of the two member directors designated by Texas Transmission, to limit distributions to the extent each determines it is necessary to meet expected future requirements of Oncor (including continuing compliance with the PUCT debt-to-equity ratio commitment). In addition, the distribution restrictions also require us to suspend dividends and other distributions (except for contractual tax payments) if the credit rating on our senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), unless otherwise allowed by the PUCT.



Our current authorized regulatory capital structure is 57.5% debt to 42.5% equity. The PUCT has the authority to determine what types of debt and equity are included in a utility’s regulatory debt-to-equity ratio. For purposes of this ratio, debt is calculated as long-term debt including any finance leases plus unamortized gains on reacquired debt less unamortized issuance expenses, discounts, premiums and losses on reacquired debt. Equity is calculated as membership interests determined in accordance with GAAP, excluding accumulated other comprehensive loss and the effects of acquisition accounting from a 2007 transaction. At December 31, 2025, our regulatory capitalization was 56.3% debt to 43.7% equity and as a result we had $717 million available to distribute to our members without exceeding our authorized regulatory debt-to-equity ratio.



On February 11, 2026, our board of directors declared, and we paid, a cash distribution of $286 million. During 2025, our board of directors declared, and we paid, the following cash distributions to our members:



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AOCI



The following table presents the changes to AOCI for the years ended December 31, 2025, 2024 and 2023 net of tax:



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9.    EMPLOYEE BENEFIT PLANS



Regulatory Recovery of Pension and OPEB Costs



PURA provides for our recovery of certain pension and OPEB costs related to the regulated utility service of our employees (and their eligible dependents) and the regulated utility service of certain employees (and their eligible dependents) of our former affiliated companies for periods prior to the deregulation and disaggregation of the Texas electric market in 2002 (recoverable service). Accordingly, in 2005, we entered into an agreement with a former affiliate of us whereby we assumed responsibility for applicable pension and OPEB costs related to those personnel’s recoverable service. We subsequently entered into an agreement with a Vistra affiliate regarding provision of these benefits. Pursuant to that agreement, we currently sponsor an OPEB plan that provides certain retirement healthcare and life insurance benefits to eligible former employees of Oncor and Vistra (or their predecessors or affiliates) for whom both Oncor and Vistra bear a portion of the benefit responsibility. See “OPEB Plans” below for more information. 



We are authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings related to recoverable service. Amounts deferred are ultimately subject to regulatory approval. At December 31, 2025 and 2024, we had recorded net regulatory assets totaling $247 million and $242 million, respectively, related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.



We have also assumed primary responsibility for pension benefits of a closed group of retired and terminated vested plan participants not related to our regulated utility business (non-recoverable service) in a 2012 transaction. Any retirement costs associated with non-recoverable service are not recoverable through rates. 



Pension Plans



We sponsor the Oncor Retirement Plan and also have liabilities related to the Vistra Retirement Plan, both of which are qualified pension plans under Section 401(a) of the Code, and are subject to the provisions of ERISA. Employees do not contribute to either plan. These pension plans provide benefits to participants under one of two formulas: (i) a Cash

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Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. The weighted-average interest crediting rate assumption for the Cash Balance Formula was 3.75% for 2025. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.



All eligible employees hired after January 1, 2001 participate under the Cash Balance Formula. Certain employees, who, prior to January 1, 2002, participated under the Traditional Retirement Plan Formula, continue their participation under that formula. It is Oncor’s policy to fund its plans on a current basis to the extent required under existing federal tax and ERISA regulations.



We also maintain the Supplemental Retirement Plan for certain employees whose retirement benefits cannot be fully earned under the qualified retirement plan. Supplemental Retirement Plan amounts are included in the reported pension amounts below.



At December 31, 2025, the pension plans’ projected benefit obligation included a net actuarial loss of $86 million attributable primarily to a decrease in discount rates due to changes in the corporate bond markets, actuarial assumption updates to reflect recent demographic experience and current market conditions and plan experience different than expected.



OPEB Plans



We currently sponsor two OPEB Plans. One plan covers our eligible current and future retirees whose services are 100% attributed to the regulated business. Effective January 1, 2018, we established a second plan to cover eligible retirees of Oncor and Vistra (or their predecessors or affiliates) whose employment services were assigned to both Oncor (or a predecessor regulated utility business) and the non-regulated business of Vistra. Vistra is solely responsible for its portion of the liability for retiree benefits related to those retirees.



Oncor’s contribution policy for the OPEB Plans is to place in irrevocable external trusts dedicated to the payment of OPEB expenses an amount at least equal to the OPEB expense recovered in rates.



At December 31, 2025, the OPEB Plans’ projected benefit obligation included a net actuarial gain of $2 million attributable primarily to updates to health care assumptions, partially offset by losses attributable to a decrease in discount rates due to changes in the corporate bond markets and plan experience different than expected.



Pension and OPEB Costs Recognized as Expense



Pension and OPEB amounts provided herein include amounts related only to our obligations with respect to the various plans based on actuarial computations and reflect our employee and retiree demographics as described above.



The calculated value method is used to determine the market-related value of the assets held in the trust for purposes of calculating our pension costs. Realized and unrealized gains or losses in the market-related value of assets are included over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.



The fair value method is used to determine the market-related value of the assets held in the trust for purposes of calculating OPEB cost.

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Detailed Information Regarding Pension and OPEB Benefits



The following pension plans and OPEB Plans information is based on December 31, 2025, 2024 and 2023 measurement dates:

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The following table provides information regarding the assumed health care cost trend rates.



The following table provides information regarding pension plans with PBO and ABO in excess of the fair value of plan assets.



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The following table provides information regarding OPEB Plans with APBO in excess of the fair value of plan assets.



Pension Plans and OPEB Plans Investment Strategy and Asset Allocations



Our investment objective for the retirement plans is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity, real assets, credit strategies (high yield bonds, emerging market debt and bank loans), hedge fund, private equity and private credit are used to further diversify the equity portfolio. International equity securities may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, U.S. Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high-grade portfolio of securities, which assists us in managing the volatility and magnitude of plan contributions and expense while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses.



The Oncor Retirement Plan’s investments are managed in two pools: one pool associated with the regulated utility service portion of plan obligations related to Oncor’s regulated utility business, and a second pool associated with the service portion of plan obligations not related to Oncor’s regulated utility business. Each pool is invested in a broadly diversified portfolio as shown below. The second pool represents 27% of total investments at December 31, 2025.



The target asset allocation ranges of the pension plans’ investments by asset category are as follows:



Our investment objective for the OPEB Plans primarily follows the objectives of the pension plans discussed above, while maintaining sufficient cash and short-term investments to pay near-term benefits and expenses. The actual amounts at December 31, 2025 provided below are consistent with the asset allocation targets.



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Fair Value Measurement of Pension Plans’ Assets



At December 31, 2025 and 2024, pension plans’ assets measured at fair value on a recurring basis consisted of the following:



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Fair Value Measurement of OPEB Plans’ Assets



At December 31, 2025 and 2024, the OPEB Plans’ assets measured at fair value on a recurring basis consisted of the following:

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Expected Long-Term Rate of Return on Assets Assumption



The retirement plans’ strategic asset allocation is determined in conjunction with the plans’ advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The modeling incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.







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Significant Concentrations of Risk



The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to participating employers. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.



Assumed Discount Rate



For the Oncor Retirement Plan at December 31, 2025, we selected the assumed discount rate using the Aon AA-AAA Bond Universe yield curve, which is based on corporate bond yields and at December 31, 2025 consisted of 1,343 corporate bonds with an average rating of AA and AAA using Moody’s, S&P and Fitch ratings. For Oncor’s obligations with respect to the Vistra Retirement Plan and the OPEB Plans at December 31, 2025, we selected the assumed discount rate using the Aon AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2025 consisted of 542 corporate bonds with an average rating of AA using Moody’s, S&P and Fitch ratings.



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Future Pension Plans and OPEB Plans Cash Contributions



Based on applicable minimum funding requirements and the latest actuarial projections, our future funding for the pension plans and the OPEB Plans, is expected to total $101 million and $21 million, respectively, in 2026 and approximately $489 million and $160 million, respectively, in the five-year period 2026 to 2030. We may also elect to make additional discretionary contributions based on market and/or business conditions.



Future Benefit Payments



Estimated future benefit payments to participants are as follows:



Thrift Plan



Our employees are eligible to participate in a qualified savings plan, the Oncor Thrift Plan, which is a participant-directed defined contribution plan subject to the provisions of ERISA and intended to qualify under Section 401(a) of the Code, and to meet the requirements of Code Sections 401(k) and 401(m). Under the plan, employees may contribute, through pre-tax salary deferrals and/or after-tax applicable payroll deductions, a portion of their regular salary or wages as permitted under law. Employer matching contributions are made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Oncor Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Oncor Retirement Plan. Employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Our contributions to the Oncor Thrift Plan totaled $36 million, $32 million and $29 million for the years ended December 31, 2025, 2024 and 2023, respectively.



10.   RELATED-PARTY TRANSACTIONS



The following represents our significant related-party transactions and related matters. 





Amounts payable to (receivable from) members related to income taxes under the tax sharing agreement and reported on our balance sheet consisted of the following:





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Cash payments made to our members related to income taxes consisted of the following:



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See Notes 1, 4, and 8 for information regarding the tax sharing agreement and distributions to members.



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11.   DERIVATIVES AND HEDGING



We are exposed to changes in interest rates and foreign currency exchange rates primarily as a result of our current and expected future debt financings. We use derivative instruments typically designated as cash flow or fair value hedges to help mitigate our exposure related to those risks.



Interest Rate Derivatives



We use interest rate swaps, in part, to hedge our interest payments related to our expected future debt financings. The future fixed rate debt issuances underlying these cash flow hedge relationships are largely dependent on market demand and liquidity in the debt market. At December 31, 2025, we believe our forecasted issuances of fixed rate debt in the related cash flow hedge relationships are probable. However, unexpected changes in market conditions in future periods could impact our ability to issue such fixed rate debt, or the timing of any such issuance. If our assumptions regarding the nature and timing of forecasted fixed rate debt issuances were to be inaccurate, we could be required to cease the application of hedge accounting to the related interest rate swaps, which could result in immediate reclassification of all the related gains or losses in AOCI to other (income) and deductions.  



We may designate an interest rate swap as a cash flow hedge if it effectively converts anticipated cash flows associated with interest payments to a fixed dollar amount. Designating interest rate swaps as cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of interest payments may vary, and other criteria.



In accounting for cash flow hedges, derivative assets and liabilities are recorded on the balance sheet at fair value with an offset to other comprehensive (loss) income. Amounts remain in AOCI and are reclassified into net income as the interest expense on the related debt affects net income.



The fair value of an interest rate derivative instrument is recognized on the balance sheet as a derivative asset or liability and changes in the fair value are recognized in net income if the criteria for cash flow hedge accounting are not met or if the instrument is not designated as a cash flow hedge.



Interest Rate Hedge Transactions



In the first quarter of 2025, we entered into interest rate swap transactions hedging the variability of benchmark bond rates used to determine the interest rates on 10-year and 30-year senior secured notes. The hedges were terminated in March 2025 upon the issuance of our 2035 Notes and 2055 Notes and a $15 million ($12 million net of tax) net fair value loss was realized and recorded in OCI. The AOCI will be reclassified into net income as an increase in interest expense over the life of the 2035 Notes and 2055 Notes, respectively.



In April 2025, we began entering into interest rate swap transactions hedging the variability of benchmark bond rates in anticipation of future debt financings through 2028. As of December 31, 2025, all such derivative instruments remained outstanding in 2025, we recorded a $5 million ($4 million net of tax) net unrealized fair value gain on the interest rate swaps in OCI.



There were approximately $6 million in net losses recorded in AOCI at December 31, 2025 related to the interest rate swaps to be reclassified into net income as an increase to interest expense within the next 12 months.



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Foreign Currency Derivatives



We are exposed to foreign currency exchange rate risk as a result of the use of foreign currency denominated financing instruments, such as the Euro Notes and CAD Notes. We have and may continue to utilize cross-currency swaps to help mitigate the exposure related to foreign currency denominated debt that we have issued or may issue in the future. Our existing cross-currency swaps exchange our euro-denominated and Canadian dollar-denominated principal payments due at maturity under the Euro Notes and CAD Notes, into U.S. dollar-denominated notional amounts and swap euro-denominated and Canadian dollar-denominated fixed interest rates for U.S. dollar-denominated fixed interest rates, respectively. We currently designate our cross-currency swaps as fair value hedges. In accounting for fair value hedges, the derivative contract is recorded on the balance sheet at fair value. We have elected to exclude the cross-currency basis spread from the assessment of effectiveness in the fair value hedges of our foreign currency risk and record any difference between the change in the fair value of the excluded components and the amounts recognized in earnings as a component of OCI. The fair value loss/gain on cross-currency swaps attributable to foreign currency exchange rates are recognized in the income statement to offset the remeasurement gain/loss on the foreign currency denominated debt attributable to foreign currency exchange rates, resulting in no impact on earnings attributable to changes in the foreign currency exchange rate.



Foreign Currency Exchange Rate Hedge Transactions



In May 2024 and June 2025, we entered into multiple cross-currency swaps, designated as fair value hedges, that effectively converted our euro-denominated fixed rate payment obligations under our Euro Notes with respect to principal and interest payments to U.S. dollar-denominated fixed rate payment obligations.  



In September 2025, we entered into multiple cross-currency swaps, also designated as fair value hedges, that effectively converted our Canadian dollar-denominated fixed rate payment obligations under our CAD Notes with respect to principal and interest payments to U.S. dollar-denominated fixed rate payment obligations.



In 2025, we recorded a $31 million net fair value loss of the cross-currency swaps. The amount attributable to excluded components was a $58 million ($46 million net of tax) loss and was recorded in OCI at December 31, 2025.



At December 31, 2025, the following foreign currency derivative contracts designated as fair value hedges of the Euro Notes and CAD Notes were outstanding:

___________





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Financial Statement Presentation



Derivative Contract Fair Values and Income Statement Impacts



The table below provides a balance sheet overview of our outstanding derivative assets and liabilities as of December 31, 2025 and 2024:





The table below provides the related income statement impacts of derivative contracts at December 31, 2025, 2024 and 2023:





____________



Fair Value Measurements



The fair value of our interest rate swap and cross-currency swap derivative instruments is measured using inputs that are considered a Level 2 measurement, as they are not actively traded and are valued using pricing models that use observable market quotations. Additionally, the fair values of derivatives designated in hedging relationships include valuation adjustments to appropriately incorporate nonperformance risk for us and/or the respective counterparties. At December 31, 2025, the fair values of derivatives designated in hedging relationships include net $4 million credit valuation adjustments.





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12.   SEGMENT REPORTING



We are managed as an integrated business that provides regulated electricity transmission and distribution services. As a result, we have one operating segment of electricity transmission and distribution; consequently, there is only one reportable segment. The segment of electricity transmission and distribution services derives revenues from tariffs approved by the PUCT and the majority of revenues are related to providing electric delivery service to end-use consumers. 



Our chief executive has been determined to be the CODM. Oncor’s CODM views net income as the measure of profit or loss in assessing financial performance. In addition, for resource allocation determinations, Oncor’s CODM considers the capital expenditures plan progress, safety and reliability performance, customer satisfaction and affordability, and regulatory requirements.



The measure of segment assets is reported on the balance sheet as total assets. The following table presents information of the reported segment’s net income, including significant expenses, for the reporting periods.





__

_________





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13.   SUPPLEMENTARY FINANCIAL INFORMATION



Other (Income) and Deductions – Net



Interest Expense and Related Charges



Accounts Receivable – Net



Accounts receivable reported on our balance sheet consisted of the following:



The accounts receivable balance from REP subsidiaries of our two largest customers, collectively represented 23% and 19%, respectively, of our accounts receivable balance at December 31, 2025 and 22% and 19%, respectively, of our accounts receivable balance at December 31, 2024. No other customer represented 10% or more of the total accounts receivable at such dates.



Under a PUCT rule relating to the Certification of Retail Electric Providers, write-offs of uncollectible amounts owed by REPs are deferred as a regulatory asset. 



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Prepayments and Other Current Assets



Prepayments and other current assets reported on our balance sheet consisted of the following:







Investments and Other Property



Investments and other property reported on our balance sheet consisted of the following:

____________



Consolidated VIE



Receivables LLC is considered a VIE under ASC 810. We are the primary beneficiary of this VIE because we have the power to direct borrowing and repayment activities of the AR Facility for the VIE, the obligation to absorb losses and the right to receive benefits that could be significant to the VIE. See Note 6 for more information on the AR Facility. As a result, we consolidate Receivables LLC. Receivables LLC’s assets and liabilities on the balance sheets consisted of the following:



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Property, Plant and Equipment – Net



Property, plant and equipment – net reported on our balance sheet consisted of the following:



_________

(a)Includes intangible capitalized software and general property, plant and equipment.



Depreciation expense as a percent of average depreciable property approximated 2.6% for each of the years ended December 31, 2025 and 2024.



Intangible Assets



Intangible assets (other than goodwill) reported on our balance sheet as part of property, plant and equipment consisted of the following:



Aggregate amortization expense for intangible assets totaled $137 million, $114 million and $97 million for the years ended December 31, 2025, 2024 and 2023, respectively. At December 31, 2025, the weighted average remaining useful lives of capitalized land easements and software were 85 years and 7 years, respectively. The estimated aggregate amortization expense for each of the next five fiscal years is as follows:



Goodwill totaling $4.740 billion was reported on our balance sheet at both December 31, 2025 and 2024. See Note 1 regarding goodwill impairment assessment and testing.

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Other Noncurrent Assets



Other noncurrent assets reported on our balance sheet consisted of the following:





Other Noncurrent Obligations



Other noncurrent obligations reported on our balance sheet consisted of the following:



Supplemental Cash Flow Information 

_______________

(a)    See Note 10 for income tax related detail.

(b)   Represents end-of-period accruals.   





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Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE



None.



Item 9A.CONTROLS AND PROCEDURES



Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, of the effectiveness of the design and operation of the disclosure controls and procedures in effect as of December 31, 2025, the end of the period covered by this Annual Report on Form 10-K. Based on the evaluation performed, our management, including the principal executive officer and principal financial officer, concluded that the disclosure controls and procedures were effective.  



 

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ONCOR ELECTRIC DELIVERY COMPANY LLC

MANAGEMENT’S ANNUAL REPORT ON

INTERNAL CONTROL OVER FINANCIAL REPORTING



The management of Oncor Electric Delivery Company LLC is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) for the company. Oncor Electric Delivery Company LLC’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.



The management of Oncor Electric Delivery Company LLC performed an evaluation as of December 31, 2025 of the effectiveness of the company’s internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission’s (COSO’s) Internal Control - Integrated Framework (2013). Based on the review performed, management believes that as of December 31, 2025, Oncor Electric Delivery Company LLC’s internal control over financial reporting was effective.



The independent registered public accounting firm of Deloitte & Touche LLP as auditors of the consolidated financial statements of Oncor Electric Delivery Company LLC has issued an attestation report on Oncor Electric Delivery Company LLC’s internal control over financial reporting.





February 26, 2026



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Members of Oncor Electric Delivery Company LLC 



Opinion on Internal Control over Financial Reporting



We have audited the internal control over financial reporting of Oncor Electric Delivery Company LLC and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. 



We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report, dated February 26, 2026, expressed an unqualified opinion on those financial statements.



Basis for Opinion



The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.



We conducted our audit in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.



Definition and Limitations of Internal Control over Financial Reporting



A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.



Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.





/s/ Deloitte & Touche LLP



Dallas, Texas



February 26, 2026

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Item 9B.OTHER INFORMATION





On February 20, 2026, we entered into an amendment to the $2B Credit Facility to, among other things, extend the maturity date by one year and to remove the SOFR Adjustment. The $2B Credit Facility has a borrowing capacity of $2.0 billion and a maturity date of February 20, 2031. For more information regarding the terms of the $2B Credit Facility, see Note 5 to Financial Statements. The foregoing description of the amendment to the $2B Credit Facility is qualified in its entirety by reference to the complete terms of the amendment, which is attached hereto as Exhibit 10(l) and incorporated by reference herein.

Amendment to $1B Credit Facility

On February 20, 2026, we entered into an amendment to the $1B Credit Facility to, among other things, extend the maturity date by one year and to remove the SOFR Adjustment. The $1B Credit Facility has a borrowing capacity of $2.0 billion and a maturity date of February 20, 2029. For more information regarding the terms of the $1B Credit Facility, see Note 6 to Financial Statements. The foregoing description of the amendment to the $1B Credit Facility is qualified in its entirety by reference to the complete terms of the amendment, which is attached hereto as Exhibit 10(o) and incorporated by reference herein.

Contract for Services

Effective February 23, 2026, we entered into a Contract for Services with James A. Greer, who retired as our Executive Vice President and Chief Operating Officer, a position he held through December 31, 2025. Pursuant to the agreement, Mr. Greer will serve as an independent consultant and advisor to Oncor’s executive management team. As compensation for his services, Mr. Greer will receive a quarterly retainer of $50,000, payable following each calendar quarter during the term of the agreement. The agreement expires on December 31, 2026, unless otherwise terminated in accordance with the terms of the agreement or extended by mutual agreement of the parties. Either party may terminate the agreement upon five business days written notice to the other party, except in the event of certain terminations of the agreement by us that result in the termination being effective on the day of such notice.

Long-Term Incentive Plan Awards Amendments

Upon recommendation of our Organization and Compensation Committee (O&C Committee) and approval by our board of directors, we previously adopted an Amended and Restated Oncor Long-Term Incentive Plan (the Long-Term Incentive Plan), which is described in greater detail in “Item 11. Executive Compensation—Compensation Elements—Long-Term Incentive Plan.” Participants in this plan include our executive officers as well as other key employees.

Pursuant to the terms of the Long-Term Incentive Plan, the O&C Committee, as the plan administrator, has the authority to amend any outstanding award granted under the plan in whole or in part, provided, however, that no such amendment may, without the consent of the applicable participants, adversely affect any material right or material obligation under such outstanding award.

In February 2026, subject to receipt of the consent from each of our executive officers in the case of their outstanding awards, the O&C Committee approved changes to outstanding awards for performance periods 2024-2026 and 2025-2027, as well as new awards for each performance period beginning on or after January 1, 2026. The amendments include (a) increasing the maximum positive adjusted net income growth adder from 21.0% to 36.0%, (b) lowering the maximum negative adjusted net income growth adder from -18.0% to -33.0%, (c) and increasing the final funding percentage limit from 200% to 250%. The amendments were effective as of February 24, 2026, upon the receipt of all consents from our executive officers, including our named executive officers. Other than as described herein, the material terms of the Long-Term Incentive Plan and the awards under such plan remain the same as disclosed in “Item 11. Executive Compensation—Compensation Elements—Long-Term Incentive Plan.”





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Item 9C.DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS



Not applicable.





PART III



Item 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE



Directors



The names, ages, and information about our current directors (as of February 26, 2026), as furnished by the directors themselves, are set forth below:

 





Director Appointments



Pursuant to our LLC Agreement and the Sempra Order, the board of directors of Oncor is required to consist of 13 members, constituted as follows:



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Mr. Martin and Mr. Bird were each designated to serve on our board of directors by Sempra (through Oncor Holdings) and Ms. Newell and Mr. Zucchet were each designated to serve on our board of directors by Texas Transmission. Directors designated by Sempra and Texas Transmission are referred to as member directors. Oncor Holdings, at the direction of STIH, has the right, pursuant to the terms of our LLC Agreement, to nominate each Oncor Officer Director, subject to approval of any such nomination by a majority of the Oncor board of directors. Mr. Shapard and Mr. Nye each serve as an Oncor Officer Director. 



Our LLC Agreement provides that seven of our directors will be Disinterested Directors under the standards set forth in our LLC Agreement. See “Item 13. Certain Relationships and Related Transactions, and Director Independence—Director Independence” for a discussion of our Disinterested Director definition. We have determined that Messrs. Berg, Mack, Saenz and Walker and Mses. Johnson, Keliher and Rodriguez are Disinterested Directors. Disinterested Directors are designated at the direction of the nominating committee of Oncor Holdings’ board of directors subject to the approval by a majority of the Disinterested Directors of Oncor Holdings’ board of directors. The nominating committee of Oncor Holdings is required to consist solely of Disinterested Directors. The Sempra Order and our LLC Agreement provide that the Disinterested Directors of Oncor at the time of Sempra’s indirect acquisition of Oncor Holdings, who are referred to as initial Disinterested Directors, would serve, if willing and able, for a term of three years (subject to continuing to meet the Disinterested Director requirements). Beginning in March 2021, two of our initial Disinterested Directors were required to roll off our board of directors. This process of having two initial Disinterested Directors roll off our board of directors continued in March 2023 and March 2025, with the final remaining initial Disinterested Director (Mr. Mack) slated to roll off our board of directors in March 2027.



Our LLC Agreement provides that each Disinterested Director, other than the initial Disinterested Directors, will be appointed for a four-year term, which is able to be renewed for only one additional term of four years, and will be appointed consistent with a mandatory retirement age of 75. In connection with the requirements of our LLC Agreement, each of Ms. Keliher’s and Mr. Saenz’s initial four-year term expires in March 2027 and each of Ms. Johnson’s and Mr. Berg’s initial four-year term expires in March 2029. Additionally, each of Ms. Rodriguez’s and Mr. Walker’s second four-year term expires in March 2029. To the extent any Disinterested Director is removed, retires or is otherwise unable to or unwilling to serve, a replacement new Disinterested Director will be chosen by the nominating committee of Oncor Holdings subject to approval by a majority vote of the Disinterested Directors of Oncor Holdings’ board of directors. Any change to the size, composition, structure or rights of our board of directors must first be approved by the PUCT.



Our LLC Agreement provides that until March 9, 2028, in order for a current or former officer of Oncor to be eligible to serve as an Oncor Officer Director, the officer cannot have worked for Sempra or any of its subsidiaries or affiliated entities (excluding Oncor Holdings and Oncor) or any other entity with a direct or indirect ownership interest in Oncor or Oncor Holdings in the ten-year period prior to the date on which the officer first became employed by Oncor. Oncor Holdings, at the direction of STIH, has the right to nominate Oncor Officer Directors as well as seek the removal of the Oncor Officer Directors, subject to approval of any such nomination or removal by a majority of the Oncor board of directors.



Audit Committee



The Audit Committee is a separately-designated standing audit committee, established in accordance with section 3(a)(58)(A) of the Securities Exchange Act of 1934, as amended. Our Audit Committee is composed of Messrs. Berg, Bird, and Mack, and Mses. Keliher and Newell. Our board of directors has determined that Ms. Keliher is an “audit committee financial expert” as defined in Item 407(d)(5) of Regulation S-K, and that Messrs. Berg and Mack and Ms. Keliher are Disinterested Directors under the standards set forth in our LLC Agreement and independent directors for purposes of

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NYSE independence standards. Ms. Newell is a member director designated by Texas Transmission. Mr. Bird is a member director designated by Sempra (through Oncor Holdings).



Executive Officers



The names, ages, and information about our current executive officers (as of February 26, 2026), as furnished by the executive officers themselves, are set forth below:





There is no family relationship between any of our executive officers, between any of our directors, or between any executive officer and any director.



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Code of Conduct



We maintain certain corporate governance documents on our website at www.oncor.com. Our Code of Conduct can be accessed by selecting “Corporate Governance” in the “Investor Relations” section of the website. Our Code of Conduct applies to all of our employees and officers, including our Chief Executive, Chief Financial Officer and Controller, and it also applies to our directors, except for provisions pertinent only to employees. Any amendments to, or waivers from, our Code of Conduct that apply to our officers will be posted under “Corporate Governance” in the “Investor Relations” section of our website promptly. Printed copies of the corporate governance documents that are posted on our website are available to any person without charge upon written request to the Corporate Secretary of Oncor Electric Delivery Company LLC at 1616 Woodall Rodgers Freeway, Suite 7E-002, Dallas, Texas 75202-1234. 



Insider Trading Arrangement and Policies



We have adopted insider trading policies and procedures that govern the purchase, sale, and/or other dispositions of Oncor’s securities by our directors, officers, employees and certain other representatives (such as consultants and contractors), including certain relatives of such persons as well as certain entities controlled by such persons, or Oncor itself, that are reasonably designed to promote compliance with insider trading laws and rules and regulations. Our insider trading policy has been filed as Exhibit 19 to this Annual Report on Form 10-K.

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Item 11.EXECUTIVE COMPENSATION



Compensation Discussion and Analysis



Overview



In this Compensation Discussion and Analysis, we describe our executive compensation philosophy and the elements of our executive compensation program. We also discuss how the executive officers named in the Summary Compensation Table (our Named Executive Officers) were compensated in 2025. In 2025, our Named Executive Officers, as well as their titles as of December 31, 2025, were:





________



Role of the Organization and Compensation Committee



Our board of directors has designated an Organization and Compensation Committee of the board of directors (O&C Committee) to establish, administer, and assess our executive compensation policies, which include participation in various employee benefit programs. The O&C Committee met five times in 2025.



The responsibilities of the O&C Committee include:





At least annually, the O&C Committee conducts reviews of the level of individual compensation elements as well as total direct compensation (base salary, annual incentives and long-term incentives) for our executive officers. The O&C Committee conducted such compensation reviews in the fourth quarter of 2025. In determining the total direct compensation of our executive officers, the O&C Committee considers the performance and responsibilities of the executives and the competitive market analysis of executive compensation provided by a compensation consultant engaged by the O&C Committee. The O&C Committee evaluates the CEO’s performance and obtains the input of the CEO on the performance of executive officers other than the CEO. The CEO assesses the performance of each executive in light of the executive’s business unit and function and presents a performance evaluation and total direct compensation recommendation for each of these individuals to the O&C Committee. The CEO also reviews and considers the competitive market analysis in making his recommendations to the O&C Committee. The O&C Committee then determines the total direct compensation, including base salary, annual incentive awards and long-term incentive awards, for each of our executive officers as it deems appropriate.



In the first quarter of each fiscal year, the O&C Committee (1) approves corporate goals and objectives under our annual and long-term incentive programs for our executive officers for awards for the current fiscal year, and (2) certifies the performance results for incentive payments for the periods that ended on December 31 of the previous fiscal year. In connection with the annual determination of the incentive awards to be paid to our CEO, the O&C Committee annually evaluates the CEO’s performance in light of the goals and objectives set by the O&C Committee for the CEO for the

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previous fiscal year. The CEO also annually conducts a performance review of each executive officer and evaluates each executive’s performance for the recently completed fiscal year relative to the corporate goals and objectives for such fiscal year set by the O&C Committee. The CEO then makes recommendations to the O&C Committee with respect to these individuals regarding whether an individual performance modifier should be applied to such executive officer’s annual incentive compensation. After considering the O&C Committee’s evaluation of the CEO, as well as the CEO’s recommendations with respect to the other executive officers, the O&C Committee determines any individual performance modifiers to be applied to the annual incentive award payout for each executive officer.



Compensation Philosophy



Our compensation philosophy, principles and practices are intended to compensate our executives appropriately for their contribution to the attainment of key strategic objectives and to strongly align the interests of our executives, owners, and customers through both short-term and long-term performance goals. We believe that:





Objectives of Compensation Philosophy



Our compensation philosophy is designed to meet the following objectives:





Elements of Compensation



In an effort to achieve our compensation objectives, we have established a compensation program for our executives that principally consists of:





For more information about the incentive and other benefit plans available to our executives see “—Compensation

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Elements” below and the compensation tables and the accompanying narratives immediately following this “Compensation Discussion and Analysis.”



Compensation Consultant



The O&C Committee engaged Meridian Compensation Partners, LLC (Meridian) as its compensation consultant beginning in August 2023 to advise and report on executive compensation and compensation with respect to our Disinterested Directors and non-executive Chairman of the board of directors, including providing an analysis of competitive market survey data and a peer group comparison to the O&C Committee, as discussed in more detail under “—Compensation Benchmarking and Market Data” below. Meridian also provides consulting services to Oncor related to non-executive officer compensation.



Compensation Benchmarking and Market Data



While we try to ensure that the greater part of an executive officer’s compensation is directly linked to the executive’s individual performance and Oncor’s operational performance, we also seek to set our executive compensation program in a manner that is competitive with the competitive market analysis prepared for the O&C Committee by the O&C Committee’s compensation consultant in order to promote retention of key personnel and to attract high-performing executives from outside our company. As a result, the O&C Committee annually conducts a compensation benchmarking review of our executive officers.



October 2024 Competitive Market Analysis



In the fourth quarter of 2024, the O&C Committee assessed total direct compensation of our executives using a competitive market analysis prepared by Meridian. The 2024 competitive market analysis included (i) a review of publicly-available market data from a custom group of peer utilities (2024 peer group comparison), (ii) a review of 2024 survey data from a nationally recognized data provider based on a group of 27 regulated utilities with median revenues of $5.6 billion, (iii) for executives other than Messrs. Nye, Clevenger, Greer, and Henry, a review of 2024 survey data from the same nationally recognized data provider based on organizations from all industries with annual revenues between $3 billion and $10 billion, and (iv) to the extent available for each, a review of each of our executives’ total direct compensation against similarly situated executives within the 2024 peer group comparison and each survey group.



Meridian’s process to identify potential peers for Oncor’s peer group included evaluating companies based on: (i) company type and company structure, (ii) companies similar to Oncor based on revenues, assets, operating income, complexity of operations, and number of employees, (iii) industry type (specifically electric, gas, or multi-utilities), and (iv) other operational considerations, including the mix of regulated versus unregulated operations, number of customers, number of states serviced and capital expenditures. Meridian concluded that the 2023 peer group remained balanced in providing a size-appropriate and regulated utility industry perspective and no changes to the peer group were necessary for 2024. Oncor’s size, based on trailing 12-month revenues at the time, was in the 51st percentile of the 2024 peer group. Meridian provided information on base salary, target annual incentives, target total cash compensation, long-term incentives and target total direct compensation at each of the 2024 peer group companies (to the extent such data was available). The peer group remained at 17 companies for 2024:







The Meridian 2024 competitive market analysis compared the compensation elements for each of our executives to the 25th, 50th and 75th percentiles of the 2024 peer group comparison and the 2024 survey data, to the extent available, with respect to base salary, target annual incentives, target total cash compensation (base salary and target annual incentives), long-term incentives and target total direct compensation (base salary, target annual incentives and long-term incentives). The Meridian 2024 competitive market analysis also compared Oncor’s compensation that is considered “at-risk” (annual incentives and long-term incentives) to market data provided by Meridian.



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The O&C Committee reviewed and considered the 2024 competitive market analysis, along with individual performance and responsibilities, when determining total direct compensation, as well as each element of total direct compensation. For each executive, the O&C Committee considered total direct compensation, including target payouts under annual and long-term incentive awards, at the 25th, 50th and 75th percentiles of the 2024 survey data and the 2024 peer group comparison, to the extent available, for that executive’s position. The 2024 peer group comparison was the primary source considered by the O&C Committee in its review of compensation for Messrs. Nye, Clevenger and Henry, and the 2024 survey data was the primary source considered by the O&C Committee in its review of compensation for Ms. Dennis and Mr. Greer due to the small sample size of reported data for chief operating officer and chief human resource officer roles by our 2024 peer group.



After consideration of the Meridian studies and each executive’s individual performance and responsibilities, in October 2024 the O&C Committee increased the base salaries of all Named Executive Officers effective November 25, 2024.



October 2025 Competitive Market Analysis



In the fourth quarter of 2025, the O&C Committee assessed total direct compensation of our executives using a competitive market analysis prepared by Meridian. The 2025 competitive market analysis included (i) a review of publicly-available market data from a custom group of peer utilities (2025 peer group comparison), (ii) a review of 2025 survey data from a nationally recognized data provider based on a group of 25 publicly-traded and primarily regulated utilities with median revenues of $8.0 billion, (iii) for executives other than Messrs. Nye, Clevenger, Greer, and Henry, a review of 2025 survey data from the same nationally recognized data provider based on organizations from all industries with annual revenues between $3 billion and $10 billion, and (iv) to the extent available for each, a review of each of our executives’ total direct compensation against similarly situated executives within the 2025 peer group comparison and each survey group.



Meridian’s process to identify potential peers for Oncor’s peer group included evaluating companies based on: (i) company type and company structure, (ii) companies similar to Oncor based on revenues, assets, operating income, complexity of operations, and number of employees, (iii) industry type (specifically electric, gas, or multi-utilities), and (iv) other operational considerations, including the mix of regulated versus unregulated operations, number of customers, number of states serviced and capital expenditures. Meridian recommended removing three companies (Avangrid, Inc., IdaCorp, Inc., and ITC Holdings Corp.) that were included in our 2024 peer group from the 2025 peer group. In addition, Meridian recommended adding three additional companies to the 2025 peer group (DTE Energy Company, Edison International, and PSEG Incorporated). Meridian made these recommendations with the intention of re-balancing the 2025 peer group to reflect our projected 2025 size and in anticipation of our future growth. Oncor’s size, based on projected 2025 revenues, was in the 47th percentile of the 2025 peer group. Meridian provided information on base salary, target annual incentives, target total cash compensation, long-term incentives and target total direct compensation at each of the 2025 peer group companies (to the extent such data was available). Following such changes, the peer group remained at 17 companies for 2025:







The Meridian 2025 competitive market analysis compared the compensation elements for each of our executives to the 25th, 50th and 75th percentiles of the 2025 peer group comparison and the 2025 survey data, to the extent available, with respect to base salary, target annual incentives, target total cash compensation (base salary and target annual incentives), long-term incentives and target total direct compensation (base salary, target annual incentives and long-term incentives). The Meridian 2025 competitive market analysis also compared Oncor’s compensation that is considered “at-risk” (annual incentives and long-term incentives) to market data provided by Meridian.



The O&C Committee reviewed and considered the 2025 competitive market analysis, along with individual performance and responsibilities, when determining total direct compensation, as well as each element of total direct compensation. For each executive, the O&C Committee considered total direct compensation, including target payouts

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under annual and long-term incentive awards, at the 25th, 50th and 75th percentiles of the 2025 survey data and the 2025 peer group comparison, to the extent available, for that executive’s position. The 2025 peer group comparison was the primary source considered by the O&C Committee in its review of compensation for Messrs. Nye, Clevenger and Henry, and the 2025 survey data was the primary source considered by the O&C Committee in its review of compensation for Ms. Dennis and Mr. Greer due to the small sample size of reported data for chief operating officer and chief human resource officer roles by our 2025 peer group.



After consideration of the Meridian studies and each executive’s individual performance and responsibilities, in October 2025 the O&C Committee increased (i) the base salaries of Ms. Dennis and Messrs. Nye, Clevenger and Henry effective November 24, 2025, (ii) the annual award target incentive percentage of Mr. Nye for periods beginning on or after January 1, 2026, and (iii) the long-term award target incentive percentages of Ms. Dennis and Messrs. Nye, Clevenger and Henry for new awards granted on or after January 1, 2026. The target incentive changes did not impact awards previously granted or awards earned in 2025, including awards payable in 2026.  The O&C Committee did not make any changes to the total direct compensation of Mr. Greer as a result of his announcement of his intent to retire.



Compensation Elements



A significant portion of each executive officer’s compensation is variable, at-risk and directly linked to achieving company performance objectives set by the O&C Committee, which is intended to strongly align the interests of our executives, owners, and customers (both our direct customers and the communities we serve) in order to promote the long-term success of our company. Other factors impacting compensation include individual performance, scope of responsibilities, retention risk, and market compensation data. None of these other factors are assigned individual weights, but are considered together. The company has no policies or formula for allocating compensation among the various elements. The following is a description of the principal compensation components provided to our executives.



Base Salary



We believe that base salary should be commensurate with the scope and complexity of each executive’s position, the level of responsibility required, and demonstrated performance. We also believe that a competitive level of base salary is required to attract and retain qualified talent.



As part of its review of total direct compensation for our executive officers, the O&C Committee annually reviews and determines executive officers’ base salaries as it deems appropriate. The review includes the O&C Committee’s review of the most recent competitive market analysis conducted by the O&C Committee’s compensation consultant. Our CEO also reviews this analysis, along with the performance and level of responsibility of each executive officer, and makes recommendations to the O&C Committee regarding any salary changes for those individuals. The O&C Committee may also approve salary increases as a result of an executive’s performance, promotion or a significant change in an executive’s responsibilities.



The 2025 competitive market analysis prepared by Meridian indicated that the base salaries of Ms. Dennis and Messrs. Nye, Greer and Clevenger were near the 50th percentile of the 2025 peer group comparison and/or the 2025 survey data. The 2025 competitive market analysis indicated that Mr. Henry’s base salary was near the 75th percentile of the peer group comparison. However, the O&C Committee recognized Mr. Henry’s position as general counsel includes responsibilities in addition to the traditional duties associated with the general counsel role, including oversight of regulatory, external affairs, risk, sustainability, and corporate security matters. After considering the results of the 2025 competitive market analysis and individual performance and responsibilities, the O&C Committee increased the base salary of Ms. Dennis and Messrs. Nye, Clevenger and Henry, effective November 24, 2025, as described below.



Annual Base Salary for Named Executive Officers



The annual base salaries of our Named Executive Officers at December 31, 2025 were as follows:





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Executive Annual Incentive Plan



The Executive Annual Incentive Plan is a cash bonus plan intended to provide a performance-based annual award for the successful attainment of certain annual performance metrics and business objectives that are established by the O&C Committee. The O&C Committee, our CEO, and the other members of our senior leadership team are responsible for administering the Executive Annual Incentive Plan. The principal purposes of the Executive Annual Incentive Plan are to attract, motivate, and retain key employees; to align the interest of participants and Oncor by rewarding performance that satisfies established performance goals; to motivate participant behaviors that drive successful results at Oncor and individual levels; and to support collaboration across essential organizational interfaces. Officers of Oncor and other specified key employees are eligible to participate in the Executive Annual Incentive Plan subject to the terms of the plan.



For each award year, the O&C Committee will establish (i) the operational or other metrics (the EAIP operational metrics) and the applicable threshold, target, superior, aspirational, and/or other achievement levels for such EAIP operational metrics, (ii) the relative weighting of each EAIP operational metric to be used in calculating the final funding percentage applicable to annual awards (the EAIP final funding percentage), and (iii) the target award amount for each executive officer under the Executive Annual Incentive Plan. The EAIP operational metrics and the applicable achievement levels under the Executive Annual Incentive Plan are established on a company-wide basis and the O&C Committee seeks to set these metrics and achievement levels at performance challenging levels. The level of achievement of each operational metric results in a funding percentage for that specific operational metric, and the funding percentages of all operational metrics are aggregated to determine the EAIP final funding percentage.



To calculate an executive officer’s actual award amount, the executive officer’s target award, which is set as a percentage of the executive officer’s annualized base salary, is multiplied by the EAIP final funding percentage and any individual performance modifier the O&C Committee elects to apply to an executive. The EAIP final funding percentage is calculated by taking the sum of each weighted EAIP operational metric funding percentage. The product of the funding percentage for each EAIP operational metric multiplied by the relative weighting of each metric and adjusted by any such metric’s modifier results in the weighted EAIP operational metric funding percentage for such metric. An individual performance modifier is based on reviews and evaluations of the executive officer’s performance by the CEO and the O&C Committee (or solely the O&C Committee in the case of our CEO) and may adjust an award upward or downward. The individual performance modifier is determined on a subjective basis. Factors used in determining individual performance modifiers may include, among others, new or unexpected responsibilities, company achievement of operational or other measures, company objectives, individual management and other goals, specific job objectives and competencies, the demonstration of team building and support attributes and general demeanor and behavior. The CEO and the O&C Committee (or solely the O&C Committee in the case of our CEO) do not assign these factors individual weights, but consider them together. Each executive officer’s individual performance modifier is set by the O&C Committee in its discretion. In February 2026, the O&C Committee approved individual performance modifiers for Messrs. Nye, Clevenger and Henry of 120%, 150%, and 158%, respectively, in recognition of each individual’s performance during 2025. The EAIP final funding percentage for awards under the plan cannot exceed 200%, subject to the application of any individual performance modifiers or as otherwise approved at the discretion of the O&C Committee consistent with the terms of the plan. 



Under the Executive Annual Incentive Plan, if an executive is employed by us through the last day of the award year but his or her employment terminates for any reason other than by us for cause prior to the payment of the award for such year, the participant will be entitled to receive payment of the award. In the event an executive is terminated by us for cause, the executive will forfeit any unpaid Executive Annual Incentive Plan award. In the event an executive’s employment terminates for any reason other than death, disability, or retirement prior to the end of the award year, such participant will forfeit any right to receive an award for such award year in which such resignation or termination took place. Upon a termination due to death, disability or retirement, during an award year and after having attained at least 90 days of employment in such award year, an executive (or his or her beneficiary in the case of death) may be eligible to receive (at the sole discretion of the O&C Committee), on the same date as awards are paid to other participants, a partial award, prorated for the number of days that the individual was participating during the award year in which such death, disability, or retirement took place. Upon a transfer of employment to one of our affiliates and after having attained at least 90 days of employment with us in such award year, and if such executive continues to be employed by an affiliate of ours

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through the remainder of the award year, such executive may be eligible to receive (at the discretion of the O&C Committee), on the same date as awards are paid to other participants, a partial award prorated on the basis of the number of days such participant was employed by us during the award year. The definition of “cause,” is substantially consistent with the same definition in the Change of Control Policy, see “—Potential Payments upon Termination or Change in Control—Change in Control Policy.”



Executive Annual Incentives in 2025 (Payable in 2026)



The O&C Committee determines annual target award percentages for executives based on executive responsibilities and performance goals, an evaluation of the most recent competitive market analysis conducted by the O&C Committee’s compensation consultant, and, with respect to executives other than our CEO, recommendations from our CEO. In making his recommendations to the O&C Committee regarding target award percentages, our CEO assesses the performance of each executive against the goals of the executive’s business unit and function and reviews the most recent competitive market analysis. Executive Annual Incentive Plan target awards are set as a percentage of a participant’s annualized base salary, which target award is based on an EAIP final funding percentage of 100%. The annual incentive target award for each executive for 2025 plan year awards was based on the O&C Committee’s review of the executive’s responsibilities and consideration of the 50th percentile of the target total direct compensation of executives with similar responsibilities from the 2024 competitive market analysis. After consideration of the 2024 competitive market analysis and the executive’s responsibilities, no changes were made to the target annual incentives of our Named Executive Officers under the Executive Annual Incentive Plan for 2025 plan year awards.



For 2025, the O&C Committee established four EAIP operational metrics. The EAIP operational metrics the O&C Committee established for 2025 reflect its belief that annual incentives should be based on achievement of metrics that emphasize the safety of our employees, benefit our customers through providing a high degree of reliability, maintain efficiency in costs for the benefit of customer rates, ensure timely expansion and maintenance of our infrastructure, and are strategic to the company. The table below sets forth these EAIP operational metrics in further detail.







Safety and reliability metrics are measured based on company performance as compared generally to certain utility industry operating companies. Operational efficiency is measured based on operating within the annual O&M and SG&A budgets set by our board of directors, including approval by a majority of our Disinterested Directors, subject to all adjustments made by the O&C Committee and/or our board of directors. Infrastructure readiness is measured based on capital expenditure spend per three-year average kW peak in accordance with the annual capital expenditure budget approved by our board of directors, including approval by a majority of our Disinterested Directors, subject to all adjustments made by the O&C Committee and/or our board of directors. The O&C Committee set the safety and reliability achievement levels of threshold and superior as amounts to be calculated based on industry performance in order to better accomplish Oncor’s goal of being an industry leader in these areas, with a discretionary aspirational safety achievement level set to reflect a DART rate goal of zero that management would like the company to strive to achieve.



The attainment of certain threshold, target, and superior achievement levels, where applicable, results in a funding percentage for a specific EAIP operational metric ranging from 0% to 200%. Actual results at the target achievement level results in a funding percentage of 125% for the O&M and SG&A per customer metric and 100% for the capital expenditures per three-year average kW peak metric. The target achievement level is not applicable for the safety or reliability metric. If Oncor’s safety results meet an aspirational achievement level of a zero DART rate, then the O&C Committee, in its discretion, may increase the funding percentage for the safety metric up to a maximum of 225%. Calculating the funding percentage for a specific EAIP operational metric is determined by Oncor’s actual results for such metric. If the actual results are equal to or worse than the threshold achievement level, then the funding percentage for that EAIP operational metric will equal 0%. If the actual results are equal to or better than the superior achievement level, then the funding percentage for that EAIP operational metric will equal 200%, subject to the O&C Committee’s discretionary ability to increase the funding percentage to 225% for an aspirational achievement level of the safety metric, as described above. If the actual results for an EAIP operational metric are between two achievement levels, then the funding

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percentage for that specific EAIP operational metric will be determined by linear interpolation between the two specified achievement levels on a straight-line basis.  



For 2025, the EAIP operational metric weighting, actual results and weighted EAIP operational metric funding percentages under the Executive Annual Incentive Plan were as follows:





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The following table provides a summary of the 2025 targets and actual awards for each Named Executive Officer. All awards under the Executive Annual Incentive Plan are made in the form of lump sum cash payments to participants by March 15 of the year following the plan year to which the award relates.



2025 Annual Incentives (Payable in 2026) for Named Executive Officers



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Long-Term Incentive Plan



The Long-Term Incentive Plan is a cash bonus plan and was developed to reflect our belief that the opportunity to benefit from the positive long-term performance of the company motivates our management to work towards the long-term success of our business and align management’s interests with those of our customers and owners. The O&C Committee is responsible for administering the Long-Term Incentive Plan. The principal purposes of the Long-Term Incentive Plan are to promote the long-term interests and growth of Oncor, attract and retain management and other key personnel, and to enable us to be competitive in our compensation practices. Our executive officers and any other key employees of the company or its subsidiaries designated by the O&C Committee are eligible to participate. The Long-Term Incentive Plan provides for cash awards to be paid after completion of a specified period of time based on achievement of one or more specific performance or other metrics designated by the O&C Committee in its discretion in accordance with the plan (the LTIP metrics). A period established by the O&C Committee over which attainment is measured in relation to the LTIP metrics under the Long-Term Incentive Plan is a 36-month period beginning each January 1, unless otherwise determined by the O&C Committee in its sole discretion. Unless otherwise specified in the plan documents, participants must be continuously employed by us through the last day of the period in order to receive a long-term incentive award for that period. We believe that these multi-year periods encourage retention and also encourage participants to strive for the long-term, sustained success of the company.



The O&C Committee establishes the specific LTIP metrics that will be used to determine a participant’s entitlement to a long-term incentive award for a particular period within a reasonable time after the commencement date of such period, but in no event later than six months after such period’s commencement date. The O&C Committee aims to establish LTIP metrics on a company-wide basis, and the O&C Committee seeks to set these targets at performance challenging levels. The O&C Committee will also establish (i) the manner in which attainment of each LTIP metric will be determined, which may include the setting of threshold, target, superior, and/or other achievement levels for each LTIP metric, (ii) the relative weighting of each LTIP metric to be used in calculating the final funding percentage applicable to a long-term incentive award (the LTIP final funding percentage) and (iii) the target award amount for an individual participant in the Long-Term Incentive Plan. The Long-Term Incentive Plan also gives the O&C Committee the discretion upon the occurrence of certain events to make adjustments to any or all of the previously established metrics to prevent unintended dilution or enlargement of any awards. The Long-Term Incentive Plan does not contain a restriction on the maximum LTIP final funding percentage, although the O&C Committee in its discretion can limit the LTIP final funding percentage as part of its methodology for calculating long-term incentive awards.



Under the Long-Term Incentive Plan, if a participant is employed by us through the last day of the award period but his or her employment terminates for any reason other than by us for cause prior to the payment of the award for that period, the participant will be entitled to receive payment of the award. In the event a participant is terminated by us for cause, the participant will forfeit any unpaid Long-Term Incentive Plan award. If a participant’s employment is terminated for reasons other than death, disability, retirement or following a change in control prior to the last day of the award period, all of such participant’s outstanding and unpaid Long-Term Incentive Plan awards will be cancelled. Upon a termination due to death, disability or retirement, for each outstanding and Long-Term Incentive Plan unpaid award, the participant (or his or her beneficiary in the case of death) will be entitled to receive, on the same date as awards are paid for that period to other participants, an award equal to the product of (i) a fraction, the numerator of which is the number of days in the period up to and including the date of the separation of service and the denominator of which is the number of days in the entire period, and (ii) the Long-Term Incentive Plan award for such period based on the extent to which the LTIP metrics were actually attained during the period. In the event of a separation from service within two years following a change in control that is initiated by the Surviving Entity for any reason other than for cause, or initiated by the participant for good reason, the participant will be entitled to receive an award equal to the product of (i) a fraction, the numerator of which is the number of days in the period up to and including the date of the separation of service and the denominator of which is the number of days in the entire period, and (ii) the Long-Term Incentive Plan award for such period, which amount will be paid at the same time as paid to current participants, unless the applicable change in control meets certain change in ownership or control provisions of Section 409A(a)(2)(A)(v) of the Code, in which case the amounts will be payable within 60 days following the participant’s separation from service. The definitions of “cause,” “change in control,” and “good reason” are substantially consistent with the same definitions in the Change of Control Policy, see “—Potential

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Payments upon Termination or Change in Control—Change in Control Policy.” In the event of a change in control, the O&C Committee may, in its discretion, terminate the plan and cancel all outstanding and unpaid awards, except that in the event of a termination of the plan in connection with a change in control, participants will be entitled to receive the payout as described above. Payments under the Long-Term Incentive Plan are separate from, and would be in addition to, any payments available under the Change in Control Policy or Severance Plan.



Long-Term Incentive Awards Granted in 2025 with a 2025 – 2027 Period (Payable in 2028)



The O&C Committee determines annual target long-term incentive awards for executives based on executive responsibilities and an evaluation of the most recent competitive market analysis conducted by the O&C Committee’s compensation consultant, and, with respect to executives other than our CEO, recommendations from our CEO. In making his recommendations to the O&C Committee regarding annual target long-term incentive awards, our CEO assesses the performance of each executive against the goals of the executive’s business unit and function and reviews the most recent competitive market analysis. Target long-term incentive awards are determined by the O&C Committee. An executive officer’s target long-term incentive award is used in calculating such officer’s actual long-term incentive award for the period based on the extent to which the LTIP metrics for that period were actually attained. The long-term incentive target payout for each executive for awards granted in 2025 was set with the goal that the target total direct compensation was near the 50th percentile of the target total direct compensation for executives with similar responsibilities among the 2024 competitive market analysis group. After consideration of the 2024 competitive market analysis and the executive’s responsibilities, no changes were made to the long-term incentive target percentages of our Named Executive Officers for awards granted in 2025.



For the period beginning January 1, 2025 and ending December 31, 2027, the O&C Committee set LTIP metrics consisting of: (i) a time-based metric measured using our weighted average cost of capital (WACC) set by the PUCT and in effect as of January 1 of each year in the period, (ii) a safety metric measured using a DART rate with a modifier for fatalities resulting from a safety violation, (iii) a reliability metric measured using non-storm SAIDI, (iv) an adjusted net income metric that measures our net income adjusted as approved by the O&C Committee, including for normal weather, the exclusion of non-cash actuarial items and items outside of the ordinary course of business, as well as any future board or O&C Committee adjustments (Adjusted Net Income) for each completed calendar year in the period against an Adjusted Net Income target for such year calculated using the net income projection in the most recent financial plan approved by the board for such year (such target being “Plan”), and (v) an Adjusted Net Income growth adder, which measures the growth rate of Adjusted Net Income for each year in the period and can potentially increase or decrease the LTIP final funding percentage based on that growth rate. Except as otherwise determined by the O&C Committee, to the extent the actual level of attainment for any LTIP metric is at a point between two achievement levels, the award amount attributable to such metric will be determined by linear interpolation between the two specified achievement levels on a straight-line basis.



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Those metrics and their respective weighting are set forth in the following table:



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Actual results of each of the time-based metric, safety metric and reliability metric will be calculated against the achievement levels to determine the funding percentage for that metric. Each such metric’s funding percentage will then be multiplied by the weighting to determine its weighted funding percentage.



Actual results of the Adjusted Net Income metric will be calculated for each year in the period to determine a funding percentage for that year, which will then be multiplied by the weighting for that year to determine its weighted funding

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percentage for that year. The sum of the weighted funding percentages for each of the three years will determine the Adjusted Net Income metric weighted funding percentage for the period.

 

The Adjusted Net Income growth rate for each year in the period will be determined by dividing the actual Adjusted Net Income for that year against the Adjusted Net Income for the immediately prior year. That growth rate will then be used to determine an adder for each year in accordance with the following table, and the Adjusted Net Income growth adder percentage for the period will be calculated as ((1 + 2025 adder) x (1 + 2026 adder) x (1 + 2027 adder)) – 1. The chart and discussion below reflect the Adjusted Net Income growth adder as amended by the O&C Committee in February 2026 and applies to awards outstanding for the 2024-2026 performance period and the 2025-2027 performance period.





The weighted funding percentages for each of the time-based, safety, reliability and Adjusted Net Income metrics as well as the actual percentage determined for the Adjusted Net Income growth adder will then be aggregated to determine an LTIP final funding percentage, provided that the O&C Committee has stipulated that (i) the LTIP final funding percentage cannot exceed 250% (which maximum percentage was increased from 200% to 250% in connection with the February 2026 amendments and applies to awards outstanding for the 2024-2026 performance period and the 2025-2027 performance period) and (ii) a negative Adjusted Net Income growth adder cannot reduce the LTIP final funding percentage to an amount below the time-based metric weighted funding percentage. The LTIP final funding percentage will then be multiplied by a participant’s target long-term incentive award to determine a final award amount.



The following table provides a summary of the target awards granted to each Named Executive Officer in the first quarter of 2025. All awards under the Long-Term Incentive Plan are to be made in the form of lump sum cash payments to participants on or before April 1 of the year following the last year of the period over which attainment is measured in relation to the applicable metrics. For target awards granted in 2025, awards are payable on or before April 1, 2028.



2025 Target Long-Term Incentive Award Grants (Payable in 2028) for Named Executive Officers





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Long-Term Incentive Awards Granted in 2023 with a 2023 – 2025 Period (Payable in 2026)



The O&C Committee determined that the LTIP metrics used for the Long-Term Incentive Plan awards granted in 2023 for the period beginning on January 1, 2023 and ending on December 31, 2025 consist of: (1) the aggregate weighted operational LTIP metric percentage consisting of (a) a safety metric based on the number of employee injuries using a DART rate with a modifier for fatalities as a result of a safety violation, and (b) a reliability metric measured by non-storm SAIDI, added to (2) an adjusted net income growth metric measuring the actual percentage of net income growth (weather normalized and excluding non-cash actuarial items and items outside of the ordinary course of business as approved by the O&C Committee) during the period, using the adjusted net income for the 2022 fiscal year as the baseline value and the adjusted net income for the 2025 fiscal year as the ending value.



In February 2026, the O&C Committee certified the LTIP metric amounts and the level of attainment of each LTIP metric established for long-term incentive awards granted in 2023 with a period that ended on December 31, 2025 as follows:



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2023 - 2025 Period Long-Term Incentive Awards (Payable in 2026) for Named Executive Officers in Office at December 31, 2025







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In accordance with the terms of the plan, these amounts will be paid to the Named Executive Officers prior to April 1, 2026.



Deferred Compensation and Retirement Plans



Our executive compensation package includes the ability to participate in the Oncor Salary Deferral Program, Oncor’s Thrift Plan, the Oncor Retirement Plan and the Supplemental Retirement Plan, and, for executives hired before January 1, 2002, subsidized retiree health care coverage. We believe that these programs, which are common among companies in the utility industry, are important to attract and retain qualified executives.



Oncor Salary Deferral Program



Oncor executive officers are eligible to participate in the Oncor Salary Deferral Program that allows employees to defer a portion of their salary and annual incentive award and to receive a matching award based on their salary deferrals. Executives can currently defer up to 50% of their base salary and up to 85% of any annual incentive award. At the executive officer’s option, the deferral period can be set for seven years, until retirement or a combination of both. Oncor generally matches 100% of deferrals up to 8% of base salary deferred under the program. Oncor does not match deferred annual incentive awards. Matching contributions vest at the earliest of seven years after the deferral date, termination without cause, retirement at the age of 62 or later, death, disability or termination for good reason following a change in control of Oncor (as defined in the Oncor Salary Deferral Program). The program encourages employee retention as, generally, participants who terminate their employment with us prior to the seven-year vesting period forfeit our matching contribution to the program.



Additionally, Oncor, at the direction of the O&C Committee, can make additional discretionary contributions into an Oncor Salary Deferral Program participant’s account. Discretionary contributions made into an Oncor Salary Deferral Program participant’s account by Oncor vest as determined by the O&C Committee.



Refer to the narrative that follows the Nonqualified Deferred Compensation – 2025 table below for a more detailed description of the Oncor Salary Deferral Program.



Oncor Thrift Plan



All eligible employees of Oncor may contribute a portion of their regular salary or wages to the Oncor Thrift Plan and Oncor matches a portion of an employee’s contributions. This matching contribution is 75% of the employee’s contribution up to 6% of the employee’s base salary for employees covered under the traditional defined benefit component of the Oncor Retirement Plan, and 100% of the employee’s contribution up to 6% of the employee’s base salary for employees covered under the cash balance component of the Oncor Retirement Plan. All matching contributions are invested in Oncor Thrift Plan investments as directed by the participant and are immediately vested. For a more detailed description of the Oncor Thrift Plan, see Note 9 to Financial Statements.



Retirement Plan

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All Oncor employees are eligible to participate in the Oncor Retirement Plan, which is qualified under applicable provisions of the Code. The Oncor Retirement Plan contains both a traditional defined benefit component and a cash balance component. Effective January 1, 2002, the defined benefit plan changed from a traditional final average pay design to a cash balance design. This change was made to better align the retirement program with competitive practices. All participants were extended an opportunity to remain in the traditional program component or transition to the cash balance component. Ms. Dennis and Mr. Greer elected to remain in the traditional program. All employees employed after January 1, 2002 who have completed one year of service with the company are eligible to participate only in the cash balance component. As a result, Messrs. Nye, Clevenger, and Henry participate under the cash balance component. For a more detailed description of the Oncor Retirement Plan, refer to the narrative that follows the Pension Benefits table below and Note 9 to Financial Statements.



Supplemental Retirement Plan



Oncor executives participate in the Supplemental Retirement Plan. The Supplemental Retirement Plan provides for the payment of retirement benefits that:





For a more detailed description of the Supplemental Retirement Plan, refer to the narrative that follows the Pension Benefits table below.



Retiree Health Care



Employees hired by Oncor (or a predecessor) prior to January 1, 2002 who were at least age 35 and had at least 10 years of service as of January 1, 2002 are generally entitled to receive an employer-paid subsidy for retiree health care coverage upon their retirement from Oncor. As such, Mr. Greer is receiving as a result of his retirement from Oncor, and Ms. Dennis will be entitled to receive upon her retirement from Oncor, a subsidy from Oncor for retiree health care coverage. Messrs. Nye, Clevenger, and Henry were hired after January 1, 2002 and are not eligible for the employer subsidy.



Perquisites and Other Benefits



Perquisites provided to our executive officers are intended to serve as part of a competitive total compensation program and to enhance our executives’ ability to conduct company business. Perquisites do not include personal use of company property or services for which we are reimbursed for the incremental cost to the company of personal use. In addition, Oncor offers its executive officers the ability to participate in benefit plans for medical, dental and vision insurance, group term life insurance and accidental death and disability insurance, as well as certain other health and welfare benefits, which are generally made available to all employees at the company. We also provide automatic medical contributions of up to $500 for any employee who participates in an Oncor medical plan option, as well as wellness incentives for employees and their spouses completing certain health and wellness-related activities and challenges, up to an aggregate amount of $2,300 in 2025. These contributions and wellness incentives are made available to all employees at the company and as a result are not included in the Summary Compensation Table. 



The following is a summary of benefits offered to our executive officers that are not available to all employees. For a description of the total incremental cost to the company of perquisites for each of our Named Executive Officers, refer to Footnote 3 in the Summary Compensation Table below.



Executive Financial Planning: All executive officers are eligible to receive executive financial planning services. These services are intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executives. Furthermore, these services help ensure greater accuracy and compliance with individual tax regulations.



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Executive Physical Health Exam: All executive officers are also eligible to receive an annual physical examination. We recognize the importance of the health of our senior management team and the vital leadership role they play in directing and operating the company. Our executive officers are important assets of the company and this benefit is designed to help ensure their health and long-term ability to serve the company.



Country Club/Luncheon Club Membership: Certain executive officers are entitled to reimbursement of club memberships if the company determines that a business need exists for the executive’s memberships, as such clubs provide those officers with a setting for cultivating business relationships and interacting with key community leaders and officials.



Security: We prioritize the safety and security of our executive team and continuity of leadership. We take actions to analyze and mitigate security risks that our leadership team may face, including by providing certain corporate and personal security to our executive leadership team as deemed necessary based on internal and external security assessments. In addition to security assessments, we periodically provide cyber and digital protection, internal and external security personnel, and residential security upgrades. Additionally, we have a company car and a security personnel driver for use by our executive team for business related transportation needs. To the extent there is personal use of the transportation services, we may pay the incremental costs associated with such use. We believe that these costs are appropriate and necessary in light of the current threats and safety concerns and challenges affecting our leadership team.



Travel: We may pay personal travel expenses for executives when we believe necessary for the health, safety and welfare of the executive. These expenses could include non-commercial aircraft flights when we deem there to be a heightened safety or security risk and/or to enhance an executive’s ability to conduct Oncor business. The incremental cost to Oncor of non-commercial flights consists of actual invoiced incremental costs for each flight pursuant to Oncor’s contracts with non-commercial aircraft providers minus any amounts reimbursed or reimbursable by the executive or a third party. From time to time an executive’s spouse and/or children may accompany the executive on a business trip. To the extent the spouse’s travel results in an incremental cost to the company, we may pay the incremental costs for the executive’s spouse to travel with the executive, if their presence contributes to the business purpose. However, any incremental costs incurred by Oncor with respect to expenses for an executive’s children to accompany the executive must be fully reimbursed by the executive.

 

Event Tickets and Recreational Activities: We lease a suite at a sports arena and purchase sponsorships and season and other tickets to sporting, entertainment, and cultural events for business purposes. From time to time, employees, including our executive officers, may have personal use of the suite and/or these tickets, and in most instances such personal use results in no incremental cost to Oncor. In limited instances we may pay the incremental costs associated with personal use of additional tickets or other costs associated with sporting, entertainment and cultural events outside of our existing suite lease, sponsorship, or season ticket arrangements. In limited situations we may also reimburse certain executives for personal recreational activities.



Compensatory Agreements and Discretionary Bonuses



The O&C Committee has from time-to-time approved retention and performance bonus agreements for certain executives. No such agreements were in effect during 2025. In addition to the Executive Annual Incentive Plan and the Long-Term Incentive Plan, the O&C Committee also has the ability to award discretionary bonuses to executives in its discretion to recognize individual achievements. No such discretionary bonuses were awarded to our Named Executive Officers with respect to performance for the year ended December 31, 2025.

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Individual Named Executive Officer Compensation



CEO Compensation



E. Allen Nye, Jr.



The following is a summary of Mr. Nye’s individual compensation for 2025. Mr. Nye is our CEO.



Base Salary: Mr. Nye’s base salary was increased effective November 24, 2025 from $1,244,100 to $1,293,900 as a result of the O&C Committee’s annual review of executive compensation discussed above under “—Overview—Compensation Benchmarking and Market Data—October 2025 Competitive Market Analysis.” 



Annual Incentives: The O&C Committee awarded Mr. Nye $2,488,499 pursuant to the Executive Annual Incentive Plan for the plan year ending December 31, 2025, reflecting the result of Oncor’s overall performance as well as Mr. Nye’s individual performance for the year 2025. Mr. Nye’s annual incentive also reflects an individual performance modifier of 120%. The O&C Committee evaluated his overall leadership of the company, particularly his oversight of the company during a period of extreme growth. For more detailed information on the calculation of Executive Annual Incentive Awards, see “—Compensation Elements—Executive Annual Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below.  



Long-Term Incentives: In 2025, Mr. Nye was granted a Long-Term Incentive Plan target award of $5,287,425 for the period of January 1, 2025 through December 31, 2027. Actual awards will be based on the Company’s achievement of approved LTIP metrics and are payable on or before April 1, 2028. In February 2026, the O&C Committee certified the results of LTIP metrics for Long-Term Incentive Plan awards granted in 2023 for the period from January 1, 2023 – December 31, 2025. Mr. Nye’s Long-Term Incentive Plan award for the 2023-2025 period is $6,183,000 and will be paid on or before April 1, 2026. See “—Compensation Elements—Long-Term Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below for additional information on the Long-Term Incentive Plan and target awards.



Compensation of Other Named Executive Officers



Don J. Clevenger



The following is a summary of Mr. Clevenger’s individual compensation for 2025. Effective as of January 1, 2026, Mr. Clevenger is our Executive Vice President and Chief Financial Officer.



Base Salary: Mr. Clevenger’s base salary was increased effective November 24, 2025 from $712,400 to $740,900 as a result of the O&C Committee’s annual review of executive compensation discussed above under “—Overview—Compensation Benchmarking and Market Data— October 2025 Competitive Market Analysis.”



Annual Incentive: The O&C Committee awarded Mr. Clevenger $1,239,104 pursuant to the Executive Annual Incentive Plan for the plan year ending December 31, 2025, reflecting the result of Oncor’s overall performance as well as Mr. Clevenger’s individual performance for the year 2025. Mr. Clevenger’s annual incentive also reflects an individual performance modifier of 150%. The O&C Committee and our CEO evaluated his leadership overseeing the overall financial performance and financial strategy of the company. For more detailed information on the calculation of Executive Annual Incentive Awards, see “—Compensation Elements—Executive Annual Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below.



Long-Term Incentives: In 2025, Mr. Clevenger was granted a Long-Term Incentive Plan target award of $1,424,800 for the period of January 1, 2025 through December 31, 2027. Actual awards will be based on the Company’s achievement of approved LTIP metrics and are payable on or before April 1, 2028. In February 2026, the O&C Committee certified the results of LTIP metrics for Long-Term Incentive Plan awards granted in 2023 for the period from January 1, 2023 – December 31, 2025. Mr. Clevenger’s Long-Term Incentive Plan award for the 2023-2025 period is $1,809,300 and will be paid on or before April 1, 2026. See “—Compensation Elements—Long-Term Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below for additional information on the Long-Term Incentive Plan and target awards.

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Deborah L. Dennis



The following is a summary of Ms. Dennis’ individual compensation for 2025. Ms. Dennis is our Senior Vice President, Chief Customer Officer and Chief HR Officer.



Base Salary: Ms. Dennis’ base salary was increased effective November 24, 2025 from $526,800 to $547,900 as a result of the O&C Committee’s annual review of executive compensation discussed above under “—Overview—Compensation Benchmarking and Market Data— October 2025 Competitive Market Analysis.”



Annual Incentive: The O&C Committee awarded Ms. Dennis $534,500 pursuant to the Executive Annual Incentive Plan for the plan year ending December 31, 2025, reflecting the result of Oncor’s overall performance as well as Ms. Dennis’ individual performance for the year 2025. The O&C Committee and our CEO evaluated her performance in overseeing the company’s employee and labor matters and her oversight of the company’s stakeholder communications. For more detailed information on the calculation of Executive Annual Incentive Awards, see “—Compensation Elements—Executive Annual Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below.



Long-Term Incentives: In 2025, Ms. Dennis was granted a Long-Term Incentive Plan target award of $579,480 for the period of January 1, 2025 through December 31, 2027. Actual awards will be based on the Company’s achievement of approved LTIP metrics and are payable on or before April 1, 2028. In February 2026, the O&C Committee certified the results of LTIP metrics for Long-Term Incentive Plan awards granted in 2023 for the period from January 1, 2023 – December 31, 2025. Ms. Dennis’ Long-Term Incentive Plan award for the 2023-2025 period is $742,560 and will be paid on or before April 1, 2026. See “—Compensation Elements—Long-Term Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below for additional information on the Long-Term Incentive Plan and target awards.



James A. Greer



The following is a summary of Mr. Greer’s individual compensation for 2025. Mr. Greer retired as our Executive Vice President and Chief Operating Officer, with his last date of employment being December 31, 2025.



Base Salary: Mr. Greer’s base salary was $724,870 for the 2025 fiscal year.



Annual Incentive: The O&C Committee awarded Mr. Greer $837,950 pursuant to the Executive Annual Incentive Plan for the plan year ending December 31, 2025, reflecting the result of Oncor’s overall performance as well as Mr. Greer’s individual performance for the year 2025. The O&C Committee and our CEO evaluated his leadership overseeing the complex operations of Oncor’s entire transmission and distribution system. For more detailed information on the calculation of Executive Annual Incentive Awards, see “—Compensation Elements—Executive Annual Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below.



Long-Term Incentives: In 2025, Mr. Greer was granted a Long-Term Incentive Plan target award of $1,449,740 for the period of January 1, 2025 through December 31, 2027. Actual awards will be based on the company’s achievement of approved LTIP metrics and are payable on or before April 1, 2028. As a result of Mr. Greer’s retirement, in 2028 he will be entitled to receive a prorated amount based on the number of days he was an employee for the 2025-2027 performance period. In February 2026, the O&C Committee certified the results of LTIP metrics for Long-Term Incentive Plan awards granted in 2023 for the period from January 1, 2023 – December 31, 2025. Mr. Greer’s Long-Term Incentive Plan award for the 2023-2025 period is $1,842,600 and will be paid on or before April 1, 2026.  See “—Compensation Elements—Long-Term Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below for additional information on the Long-Term Incentive Plan and target awards.



Matthew C. Henry



The following is a summary of Mr. Henry’s individual compensation for 2025. Mr. Henry is our Senior Vice President, General Counsel and Secretary.



Base Salary: Mr. Henry’s base salary was increased effective November 24, 2025 from $707,950 to $736,300 as a result of the O&C Committee’s annual review of executive compensation discussed above under “—Overview—Compensation Benchmarking and Market Data— October 2025 Competitive Market Analysis.”

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Annual Incentive: The O&C Committee awarded Mr. Henry $1,134,909 pursuant to the Executive Annual Incentive Plan for the plan year ending December 31, 2025, reflecting the result of Oncor’s overall performance as well as Mr. Henry’s individual performance for the year 2025. Mr. Henry’s annual incentive also reflects an individual performance modifier of 158%. The O&C Committee and our CEO evaluated his management of the company’s legal, regulatory, external affairs, and corporate security matters. For more detailed information on the calculation of Executive Annual Incentive Awards, see “—Compensation Elements—Executive Annual Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below.



Long-Term Incentives: In 2025, Mr. Henry was granted a Long-Term Incentive Plan target award of $1,238,913 for the period of January 1, 2025 through December 31, 2027. Actual awards will be based on Oncor’s achievement of approved LTIP metrics and are payable on or before April 1, 2028. In February 2026, the O&C Committee certified the results of LTIP metrics for Long-Term Incentive Plan awards granted in 2023 for the period from January 1, 2023 – December 31, 2025. Mr. Henry’s Long-Term Incentive Plan award for the 2023-2025 period is $1,437,408 and will be paid on or before April 1, 2026. See “—Compensation Elements—Long-Term Incentive Plan” above and the Grants of Plan-Based Awards – 2025 table below for additional information on the Long-Term Incentive Plan and target awards.



Contingent Payments



Change in Control Policy



Oncor maintains an Amended and Restated Executive Change in Control Policy, as amended from time to time (Change in Control Policy).



The Change in Control Policy provides for the payment of transition benefits to eligible executives if the executive is terminated without cause or resigns for good reason within 24 months following a change in control.



Refer to “—Potential Payments upon Termination or Change in Control—Change in Control Policy” for the definition of the terms “change in control,” “without cause” and “good reason” as used in the Change in Control Policy.



We believe these payments, to be triggered upon meeting the criteria above, provide incentive for executives to fully consider potential changes that are in the best interest of Oncor and our owners, even if those changes would result in the executives’ termination. We also believe it is important to have a competitive change in control program to attract and retain the caliber of executives that our business requires and to foster an environment of relative security within which we believe our executives will be able to focus on achieving company goals.



Refer to “—Potential Payments upon Termination or Change in Control—Change in Control Policy” for detailed information about payments and benefits that our executive officers are eligible to receive under the Change in Control Policy.



Severance Plan



Oncor also makes available a Severance Plan (Severance Plan) to provide certain benefits to eligible executives. The purpose of the Severance Plan is to provide benefits to eligible executives who are not eligible for severance pursuant to another plan or agreement (including an employment agreement) and whose employment is involuntarily terminated for reasons other than:





We believe it is important to have a severance plan in place to attract and retain the caliber of executives that our business requires and to foster an environment of relative security within which we believe our executives will be able to focus on achieving company goals. Refer to “—Potential Payments upon Termination or Change in Control” for detailed information about payments and benefits that our executive officers are eligible to receive under the Severance Plan.



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Tax/Accounting Considerations



The O&C Committee administers our executive compensation programs with the good faith intention of complying with the Code, including Section 409A, as well as other applicable regulations and accounting rules.



Organization and Compensation Committee Report



The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on such review and discussions, the O&C Committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this Form 10-K.



Organization and Compensation Committee



Timothy A. Mack, Chair

Jeffrey W. Martin

Luis J. Saenz

W. Kelvin Walker

Steven J. Zucchet



The information contained herein under the heading “Organization and Compensation Committee Report” is not to be deemed to be “soliciting material” or “filed” with the SEC pursuant to Section 407(e)(5) of SEC Regulation S-K.



Compensation Committee Interlocks and Insider Participation



Messrs. Mack, Martin, Saenz, Walker and Zucchet each served as members of our O&C Committee during 2025. Two of our O&C Committee members, Mr. Martin and Mr. Zucchet, are not classified as Disinterested Directors under the standards set forth in the LLC Agreement. Mr. Martin is the chairman, chief executive officer and president of Sempra, and was designated to serve on our board of directors by Sempra (through Oncor Holdings). Mr. Zucchet is employed by OMERS Infrastructure Management Inc., an affiliate of Texas Transmission, and serves as an officer and director of Texas Transmission’s parent company. Mr. Zucchet was designated to serve on our board of directors by Texas Transmission. No member of the O&C Committee is or has ever been one of our officers or employees.



Mr. Walker is the chief executive officer of the Dallas Citizens Council, a 501(c)(6) non-profit organization made up of over 150 chief executive officers and other top business leaders in North Texas that focuses on advancing public policy issues impacting the Dallas area. Oncor is a dues paying member and has served as a corporate sponsor of the annual meeting of the Dallas Citizens Council and Mr. Nye, our CEO, serves on the board of directors of the Dallas Citizens Council.

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COMPENSATION TABLES



Summary Compensation Table



The following table provides information regarding the aggregate compensation paid to our Named Executive Officers for the fiscal years ended December 31, 2025, 2024 and 2023 in which they served as a Named Executive Officer.





______________ 



          ______________

2025 All Other Compensation Components for Named Executive Officers



          ______________



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Grants of Plan-Based Awards – 2025



The following table sets forth information regarding grants of plan-based awards to Named Executive Officers under our Executive Annual Incentive Plan and Long-Term Incentive Plan during the fiscal year ended December 31, 2025. For a narrative description of material factors necessary for an understanding of the information disclosed in the table and the accompanying footnotes, see “—Compensation Elements—Executive Annual Incentive Plan” and “—Compensation Elements—Long-Term Incentive Plan.”





________________



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Pension Benefits



The following table sets forth information regarding Oncor’s participation in the retirement plans that provide for benefits in connection with, or following, the retirement of our Named Executive Officers for the fiscal year ended December 31, 2025:







_____________



The Oncor Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. All new employees hired after January 1, 2002 participate in the cash balance component. In addition, the cash balance component covers employees previously participating in the traditional defined benefit component who elected to convert the actuarial equivalent of their accrued traditional defined benefit to the cash balance component during a special one-time election opportunity effective in 2002. The employees that participate in the traditional defined benefit component do not participate in the cash balance component.



Annual retirement benefits under the traditional defined benefit component, which applied during 2025 to Ms. Dennis and Mr. Greer, are computed as follows: for each year of accredited service up to a total of 40 years, a participant receives 1.3% of the first $7,800, plus 1.5% of the excess over $7,800, of the participant’s average annual earnings (base salary) during his or her three years of highest earnings. Under the cash balance component, which covers Messrs. Nye, Clevenger, and Henry, a hypothetical account is established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), plus interest credits based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year. Benefits paid under the traditional defined benefit component of the Oncor Retirement Plan are not subject to any reduction for Social Security payments but are limited by provisions of the Code. 



The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Oncor Retirement Plan, including any retirement compensation required to be paid pursuant to contractual arrangements. Under the Supplemental Retirement Plan, retirement benefits are calculated in accordance with the same formula used under the Oncor Retirement Plan, except that, with respect to calculating the portion of the Supplemental Retirement Plan benefit attributable to service under the traditional defined benefit component of the Oncor Retirement Plan, earnings also include Executive Annual Incentive Plan awards. The amount of earnings attributable to the Executive Annual Incentive Plan awards is reported under the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.



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The table set forth above illustrates the present value on December 31, 2025 of each Named Executive Officer’s Oncor Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on his or her years of service and remuneration through December 31, 2025. Benefits accrued under the Supplemental Retirement Plan after December 31, 2004 are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been and may continue to be modified to address the applicable requirements under Section 409A of the Code and related guidance.



The present value of accumulated benefits for the traditional defined benefit component of the Oncor Retirement Plan and the Supplemental Retirement Plan was calculated based on the executive’s annuity payable at the earliest age that unreduced benefits are available under either plan (generally age 62). Unmarried executives are assumed to elect a single life annuity. For married executives, it is assumed that 55% will elect a 100% joint and survivor annuity and 45% will elect a single life annuity. Post-retirement mortality was based on the Pri-2012 amounts weighted mortality table projected generationally from 2012 with scale MP-2021. A discount rate of 5.30% was applied and no pre-retirement mortality or turnover was reflected.



The present value of accumulated benefits for the cash balance component of the Oncor Retirement Plan and the Supplemental Retirement Plan was calculated as the value of the executive’s cash balance account projected to age 65 at an assumed growth rate of 4.50% and then discounted back to December 31, 2025, at 5.30%. For married executives, it is assumed that 90% will elect a lump sum, 5% will elect a joint and survivor annuity and 5% will elect a single life annuity. Post-retirement mortality for annuity recipients was based on the Pri-2012 amounts-weighted mortality table projected generationally from 2012 with scale MP-2021. No pre-retirement mortality or turnover assumptions were applied.



The present values of accumulated benefits for the Supplemental Retirement Plan as of December 31, 2025 for Messrs. Nye, Clevenger and Henry were offset by permissible distributions made on December 30, 2025 to taxing authorities to satisfy FICA taxes.



Early retirement benefits under the Oncor Retirement Plan are available to our employees covered in the traditional defined benefit component upon their attainment of age 55 and achievement of 15 years of accredited service. Early retirement results in a retirement benefit payment reduction of 4% for each full year (and 0.333% for each additional full calendar month) between the date the participant retires and the date the participant would reach age 62. Mr. Greer was eligible for normal retirement and full benefits upon his retirement from Oncor. As Ms. Dennis has achieved age 65, she is eligible for normal retirement and full retirement benefits. Participants in the cash balance component of the Oncor Retirement Plan can receive their benefit upon retirement or upon separation of service with the company.



Benefits under the Supplemental Retirement Plan are tied to a participant’s coverage under the Oncor Retirement Plan. For participants in the cash balance program of the Oncor Retirement Plan, Supplemental Retirement Plan benefits are generally payable upon the later of (i) a fully vested participant’s separation from service or (ii) the date a fully vested participant would have achieved ten years of accredited service if the participant had remained in continuous employment and not experienced a separation of service. For participants in the traditional defined benefit component of the Oncor Retirement Plan, Supplemental Retirement Plan benefits are generally payable in an annuity on the later of (i) the first day of the second month after a participant’s separation from service or (ii) the earliest date the participant would be eligible to commence benefits under the Oncor Retirement Plan. However, for either traditional defined benefit component or cash balance component participants, Supplemental Retirement Plan benefits are payable as soon as reasonably practical and within 90 days following a separation of service if the lump sum present value of the participant’s total vested benefit amount is less than the dollar amount under the applicable provision of the Code ($23,500 in 2025). Benefits under the Supplemental Retirement Plan are only available to our executive officers and other specified key employees.



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Nonqualified Deferred Compensation – 2025



The following table sets forth information regarding the deferral of components of our Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2025:





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Oncor Salary Deferral Program



Under the Oncor Salary Deferral Program, each employee of Oncor, who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Oncor Salary Deferral Program ($161,820 for the program year beginning January 1, 2025) may elect to defer up to 50% of annual base salary and/or up to 85% of any bonus or incentive award. This deferral (including any vested matching contributions, as described below) may be made for a period of seven years, for a period ending with the retirement of such employee, or for a combination thereof, at the election of the employee. Oncor makes a matching award, subject to forfeiture under certain circumstances, equal to 100% of up to the first 8% of base salary deferred under the Oncor Salary Deferral Program. Oncor does not match deferred bonus or incentive awards. Matching contributions vest at the earliest of seven years after the deferral date, termination without cause, retirement at the age of 62 or later, death, disability or termination for good reason following a change in control of Oncor. The definitions of “cause,” “change in control,” and “good reason” are substantially consistent with the same definitions in the Change in Control Policy, see “—Potential Payments upon Termination or Change in Control—Change in Control Policy.” Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Oncor Salary Deferral Program selected by each participant.



Additionally, Oncor, at the direction of the O&C Committee, can make additional discretionary contributions into an Oncor Salary Deferral Program participant’s account. Discretionary contributions made into an Oncor Salary Deferral Program participant’s account by Oncor vest as determined by the O&C Committee.



At the end of the applicable account maturity period (seven years or retirement, as elected by the participant or, in the case of company discretionary contributions, as determined by the O&C Committee) the trustee for the Oncor Salary Deferral Program distributes the deferrals and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. Oncor is financing the retirement option of the Oncor Salary Deferral Program through the purchase of corporate-owned life insurance on lives of some participants. The proceeds from such insurance are expected to allow us to fully recover the cost of the retirement option.



Potential Payments upon Termination or Change in Control



The tables and narrative below provide information for payments to Oncor’s Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of termination of employment including, as applicable, due

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to retirement, voluntary, for cause, death, disability, without cause, or termination after a change in control of Oncor for good reason or without cause. The amounts shown below for our current Named Executive Officers, other than Mr. Greer, assume that such a termination of employment and/or change in control occurred on December 31, 2025. As Mr. Greer retired from Oncor with his last date of employment being December 31, 2025, his table reflects amounts paid or payable to him with respect to his retirement.



In 2025, all of our executive officers were eligible to receive benefits under the terms of the Change in Control Policy and the Severance Plan, as more fully described following the tables below. In addition to the provisions of those plans, the Oncor Salary Deferral Program provides that all company-matching awards will become automatically vested in the event of a termination without cause, death, disability, retirement at the age of 62 or later, or termination for good reason following a change in control. The amounts listed in the tables below regarding the Oncor Salary Deferral Program only represent the immediate vesting of company matching contributions resulting from termination without cause, death, disability, retirement at the age of 62 or later or a termination for good reason following the occurrence of a change in control. Contributions made to such plan by each Named Executive Officer are disclosed in the Nonqualified Deferred Compensation – 2025 table above. For a more detailed discussion of the Oncor Salary Deferral Program, see the Nonqualified Deferred Compensation – 2025 table and the narrative following such table.



Messrs. Nye, Clevenger and Henry participate in the cash balance component of the Oncor Retirement Plan and as a result can elect to receive their Oncor Retirement Plan benefits as a lump sum upon separation of service with the company. In addition, since Messrs. Nye and Clevenger are fully vested and achieved ten years of accredited service, each would receive their Supplemental Retirement Plan benefits as a lump sum upon such separation of service. Ms. Dennis and Mr. Greer participate in the traditional defined benefit component of the Oncor Retirement Plan. Mr. Greer’s retirement benefits will not be subject to any payment reduction as he was eligible to retire at his retirement date as a result of meeting the age and service requirements. Ms. Dennis is eligible to retire upon termination of employment as a result of meeting the age and service requirements without her retirement benefits being subject to any payment reduction.



No additional potential payments will be triggered by any termination of employment or change in control, and as a result no amounts are reported in the tables below for such retirement plans. For a more detailed discussion of the terms of the Oncor Retirement Plan and Supplemental Retirement Plan, see the Pension Benefits table above and the narrative following the Pension Benefits table.



All our Named Executive Officers participate in benefit plans for group term life insurance and accidental death and disability. Any benefits received under these policies are paid to the beneficiary by a third-party provider.

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1.  Mr. Nye



Potential Payments to Mr. Nye Upon Termination ($)



________________

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2.  Mr. Clevenger



Potential Payments to Mr. Clevenger Upon Termination ($)



_________________



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3.  Ms. Dennis



Potential Payments to Ms. Dennis Upon Termination ($)





_________________



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4.  Mr. Greer



Potential Payments to Mr. Greer Upon Termination ($)

(Reflects Amounts Paid or Payable with Respect to his Retirement)



_________________



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5.  Mr. Henry



Potential Payments to Mr. Henry Upon Termination ($)



_________________

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Change in Control Policy



Oncor maintains the Change in Control Policy for our senior leadership team, which consists of our executive officers.



The Change in Control Policy provides for the payment of transition benefits to eligible executives if the executive is terminated without cause or resigns for good reason within 24 months following a change in control.



The Change in Control Policy provides that cause has the definition assigned to such term in any employment agreement or change-in-control agreement in effect between the executive and Oncor or any other surviving entity in any change in control transaction or any affiliate thereof which employs the executive at the time of and/or following the change in control (Surviving Company) at the time of termination of employment. If no such agreement exists, cause is defined as (i) the executive engaging in conduct in carrying out his or her employment duties to the Surviving Company that constitutes (a) a breach of fiduciary duty to the Surviving Company or its equity holders, (b) gross neglect, or (c) gross misconduct resulting in material and objectively determinable damage to the business of the Surviving Company, or (ii) the indictment of the executive for, or the executive’s plea of nolo contendere to, a felony or misdemeanor involving moral turpitude. In addition, the Change in Control Policy provides that a termination shall not constitute a termination for cause unless the executive has received written notice specifying the alleged misconduct constituting cause, the executive has been given an opportunity to be heard by the board of directors of the Surviving Company, as applicable, and following such hearing, the applicable board of directors determines in good faith and by at least a two-thirds vote that the termination for cause is appropriate under the circumstances.



The Change in Control Policy defines good reason to mean any of the following events or actions taken without the express, voluntary consent of the executive: (i) a material reduction in the executive’s base salary or incentive compensation opportunity, other than a broad-based reduction of base salaries or incentive compensation of all similarly situated executives of the Surviving Company, unless such broad-based reduction only applies to former executives of Oncor; (ii) a material reduction in the aggregate type, level or value of benefits for which the executive is eligible, immediately prior to the change in control, other than a broad-based reduction applicable to all similarly situated executives of the Surviving Company, unless such reduction only applies to former executives of Oncor; (iii) a material reduction in the executive’s authority, duties or responsibilities, including an adverse change in (a) the executive’s title, reporting level, reporting line or structure, scope of responsibilities, or management authority, or (b) the scope or size of the business, entity, or budget for which the executive had responsibility, in each case as in effect immediately prior to the effective time of the change in control; (iv) the executive’s primary work location is relocated, resulting in an increase in the executive’s work commute in excess of thirty-five miles more than the executive’s work commute immediately prior to the change in control; (v) a material breach by the Surviving Company of the terms of any employment agreement with the executive; (vi) the failure of Oncor to obtain an agreement by the Surviving Company, if such entity is not Oncor, to fully assume and perform the provisions of the Change in Control Policy; or (vii) the executive is asked or required to resign in connection with a change in control and does so resign. In order to constitute a resignation with good reason, however, (x) the executive must provide written notice to the Surviving Company describing the event or condition constituting good reason within a period of not more than 90 days from the initial occurrence of such event or circumstance, (y) if the applicable event or circumstance is capable of being cured, the Surviving Company fails or refuses to fully remedy such event or circumstance within a 30-day cure period following the receipt of such notice, and (z) the executive terminates their employment within two years following the initial existence of one or more of the preceding events or actions.



The Change in Control Policy defines a change in control as any one or more of the following events: (i) the acquisition, in one transaction or a series of transactions, of direct or indirect ownership of the equity of Oncor or Sempra that, together with the equity held by such person or group, constitutes more than 50% of the total fair market value, total direct or indirect voting power, or the direct or indirect beneficial ownership of Oncor or Sempra, other than any acquisition of Oncor’s equity by a wholly-owned subsidiary of Sempra; (ii) the acquisition, during any 12-month period, by any person or group, in one transaction or a series of transactions, of direct or indirect equity of Oncor or Sempra that constitutes 30% or more of the total fair market value, the total direct or indirect voting power, or the direct or indirect beneficial ownership of Oncor or Sempra, other than any acquisition of Oncor equity by a wholly-owned subsidiary of Sempra; (iii) any sale, lease, exchange or other transfer (in one transaction or in a series of transactions) of all, or substantially all, of Oncor’s assets, other than to a wholly-owned subsidiary of Sempra; (iv) the consummation of a transaction for which the PUCT approved a transfer or change of control (operational or otherwise) of Oncor; or (v) a material change to the terms of the Approved Ring Fence (as defined in the LLC Agreement).



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Our executive officers are eligible to receive the following under the Change in Control Policy:





The Change in Control Policy attaches a form of an agreement and release that each executive is required to sign prior to receipt of benefits under the Change in Control Policy, and such form of agreement and release contains a one-year non-solicitation period and provisions regarding confidentiality and non-disparagement. For a period of one year after a termination contemplated by the policy, a participant may not recruit, solicit, induce, encourage or in any way cause any employee, consultant or contractor engaged by Oncor or any affiliate to terminate his or her relationship with Oncor. The Change in Control Policy may be amended by our board of directors or a duly authorized committee of our board of directors at any time, except that any amendments that adversely affect the benefits available to eligible participants cannot be made within 24 months of a change in control or while the company is in the process of negotiating a potential transaction or event which, if consummated, would constitute a change in control.



Severance Plan



We maintain the Severance Plan for our executive team, which consists of our executive officers and certain non-executive vice presidents. The purpose of the Severance Plan is to provide benefits to eligible executives who are not eligible for severance pursuant to another plan or agreement (including an employment agreement) and whose employment is involuntarily terminated for reasons other than:



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Our executive officers are eligible to receive the following under the Severance Plan:





In order to receive benefits under the plan, a participant must enter into an agreement and release within 45 days of being notified by us of such participant’s eligibility to receive benefits under the plan. The Severance Plan also provides that for a period of one year after a termination contemplated by the plan, a participant may not recruit, solicit, induce or in any way cause any employee, consultant or contractor engaged by Oncor to terminate his or her relationship with Oncor. The Severance Plan also contains provisions relating to confidentiality and non-disparagement.



Executive Annual Incentive Plan



For information concerning change of control and termination payouts for awards granted under the Executive Annual Incentive Plan, see the narrative included in “—Compensation Elements—Executive Annual Incentive Plan.”



Long-Term Incentive Plan



For information concerning change of control and termination payouts for awards granted under the Long-Term Incentive Plan, see the narrative included in “—Compensation Elements—Long-Term Incentive Plan.”



Oncor Salary Deferral Program



For information concerning vesting upon a change of control and termination for good reason, see the narrative that follows the Nonqualified Deferred Compensation – 2025 table.





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CEO Pay Ratio for Fiscal Year 2025



Pay Ratio



Our CEO to median employee pay ratio has been calculated in accordance with the rules under the Dodd-Frank Wall Street Reform and Consumer Protection Act and is calculated in a manner consistent with Item 402(u) of Regulation S-K. Mr. Nye’s annual total compensation for 2025, as shown in the Summary Compensation Table above, was $10,470,935.  



The median Oncor employee’s annual total compensation in 2025 (other than Mr. Nye) was $203,593, calculated using the same methodology as used in the calculation of Mr. Nye’s annual total compensation in the Summary Compensation Table, consisting of base salary, bonus, non-equity incentive plan compensation, change in pension value and non-qualified deferred compensation earnings, and all other compensation (for the median employee, all other compensation consisted of the Oncor Thrift Plan company match). As a result, the ratio of Mr. Nye’s annual total compensation in 2025 to the median annual total compensation of all Oncor employees (other than Mr. Nye) in 2025 was 51:1, when calculated in a manner consistent with Item 402(u) of Regulation S-K.



Identification of Median Employee



We identified a median employee in 2024. For purposes of determining the median Oncor employee, we evaluated all employees, other than Mr. Nye, employed by Oncor as of November 1, 2024 and calculated each such employee’s total cash compensation through November 1, 2024 using each employee’s (i) base pay received through November 1, 2024 and (ii) cash compensation received through November 1, 2024 in the form of incentive compensation, bonuses, and any other cash payments (including, without limitation, any overtime adjustments, overtime meals, taxable reimbursable expenses, holiday pay, and salary deferral program payouts). We did not make any material assumptions, adjustments, or estimates with respect to total cash compensation. The total compensation of each employee other than Mr. Nye was then ranked lowest to highest to determine the median employee. As a result of having an even-numbered employee population we used reasonable judgment to select the median employee that was best suited to serve as the median employee. We do not reasonably believe that there has been a change in the median employee’s compensation arrangement since the time the median employee was identified that would significantly affect the pay ratio disclosure and as such we are using the same median employee identified in 2024.



Annual Total Compensation



After identifying the median employee based on total cash compensation, as described above, we calculated annual total compensation for such employee using the same methodology we use for our Named Executive Officers as set forth in the Summary Compensation Table above.



Risk Assessment of Compensation Policies and Practices



The O&C Committee reviews the compensation policies and practices applicable to Oncor’s employees (both executive and non-executive) annually during the first quarter of the year in order to determine whether such compensation policies and practices create risks that are reasonably likely to have a material adverse effect on Oncor. In February 2026, the O&C Committee concluded that current compensatory policies and practices do not create risks that are reasonably likely to have a material adverse effect on Oncor. In arriving at this conclusion, the O&C Committee discussed with management the various compensation policies and practices of the company and the compensation payable pursuant to each, and evaluated whether the compensation payable under each plan or policy could result in (i) incenting employees to take risks that could result in a material adverse effect to Oncor, or (ii) payments by the company significant enough to cause a material adverse effect to Oncor.



We believe that the following factors in our employee compensation program limit risks that could be reasonably likely to have a material adverse effect on the company:



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Director Compensation



The O&C Committee determines compensation for members of our board of directors. Directors who are current officers of Oncor and the member directors designated by each of Sempra (through Oncor Holdings) and Texas Transmission to serve on our board of directors do not receive any fees for their service as a director. See “Item 10. Directors, Executive Officers and Corporate Governance—Director Appointments” for information regarding the designation of member directors. Oncor reimburses all directors for reasonable expenses incurred in connection with their services as directors.



The table below sets forth information regarding the aggregate compensation paid to the members of our board of directors during the fiscal year ended December 31, 2025, other than E. Allen Nye, Jr., whose compensation from Oncor is discussed in “—Compensation Discussion and Analysis” and “—Compensation Tables.” Mr. Nye did not receive any compensation for his service on our board of directors.





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The O&C Committee determines director compensation for the Disinterested Directors on our board of directors and our non-executive Chairman of the board of directors. All director fees are paid quarterly, in arrears. Each Disinterested Director and our non-executive Chairman receive a fee for serving on our board of directors. For the first three quarters of 2025 in which they served on our board of directors, each Disinterested Director and our non-executive Chairman (Mr. Shapard) received a fee of $68,750, of which amount $4,125 for each of the directors who also served on the board of directors of Oncor Holdings during one or more of such first three quarters was attributable, based on the quarters served, to each such director’s service as a member of the board of directors of Oncor Holdings and was paid by Oncor but reimbursed to Oncor by Oncor Holdings. For the last quarter of 2025 in which they served on our board of directors, each Disinterested Director and our non-executive Chairman (Mr. Shapard) received a fee of $72,500, of which amount $4,350 for each of the directors who also served on the board of directors of Oncor Holdings in the last quarter of 2025 was attributable to each such director’s service as a member of the board of directors of Oncor Holdings and was paid by Oncor but reimbursed to Oncor by Oncor Holdings. In addition, the chair of the Audit Committee (Mr. Estrada for the first quarter and Ms. Keliher for the second, third, and fourth quarters) received an additional $5,000 quarterly fee, the chair of the Governance & Sustainability Committee (Mr. Gary for the first quarter and Ms. Rodriquez for the second, third, and fourth quarters) received an additional $5,000 quarterly fee, and the chair of the O&C Committee (Mr. Mack) received an additional $5,000 quarterly fee in 2025 for the extra responsibilities associated with each such positions. The chair of the Finance Committee (Mr. Shapard) did not receive an additional quarterly fee for such position in 2025. For the first three quarters of 2025, our non-executive Chairman (Mr. Shapard) received an additional $25,000 quarterly fee for the additional duties associated with that position (of which amount $1,500 was attributable each quarter to his service as non-executive Chairman of the board of directors of Oncor Holdings and was paid by Oncor but reimbursed to Oncor by Oncor Holdings). For the last quarter of 2025 our non-executive chairman (Mr. Shapard) received an additional $37,500 quarterly fee for the additional duties associated with that position (of which amount $2,250 was attributable to his service as non-executive Chairman of the board of directors of Oncor Holdings and was paid by Oncor but reimbursed to Oncor by Oncor Holdings).



In October 2025, the O&C Committee reviewed Meridian’s competitive market analysis of the fees received by our Disinterested Directors, our non-executive Chairman, and our committee chairs using the same peer group used in the October 2025 analysis of executive compensation. See “—Overview—Compensation Benchmarking and Market Data—

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October 2025 Competitive Market Analysis” for a description of this peer group. As a result of this review, the O&C Committee increased (i) the fee to be paid to the Disinterested Directors and our non-executive Chairman to $72,500 per quarter and (ii) the fee to be paid to our non-executive Chairman to $37,500 per quarter, each effective as of the quarter beginning October 1, 2025.



Our LLC Agreement provides that each of Sempra and Texas Transmission has the right to designate two member directors to serve on our board of directors. None of those four member director positions receives compensation from us for service as a director. Mr. Nye, our CEO, does not receive compensation for his service as a director. For a description of the independence standards applicable to our Disinterested Directors, see “Item 13. Certain Relationships and Related Transactions, and Director Independence.”







      

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Item 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS



Equity Compensation Plan Information



As of December 31, 2025, Oncor had no compensation plans in place that authorized the issuance of equity securities of Oncor.



Security Ownership of Equity Interests of Oncor by Certain Beneficial Owners and Management



The following table lists the number of limited liability company membership interests (LLC Units) of Oncor beneficially owned at February 26, 2026 by the holders of more than 5% of our LLC Units (based on information made available to Oncor), our current directors and the Named Executive Officers listed in “Item 11. Executive Compensation—Summary Compensation Table.” See also “Items 1. and 2. Business and Properties—Ownership Structure and Ring-Fencing Measures” and Note 1 to Financial Statements for a discussion of the various ring-fencing measures that have been taken to enhance the separateness between us and entities with direct or indirect ownership interests in us. As a result of these measures, holders of our LLC Units do not control us, and the ring-fencing measures limit their ability to direct our management, policies and operations.



The amounts and percentages of LLC Units beneficially owned are reported on the basis of SEC regulations governing the determination of beneficial ownership of securities. Under SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares voting power or investment power, which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Securities that can be so acquired are deemed to be outstanding for purposes of computing such person’s ownership percentage, but not for purposes of computing any other person’s percentage. Under these rules, more than one person may be deemed to be a beneficial owner of the same securities and a person may be deemed to be a beneficial owner of securities as to which such person has no economic interest.

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Item 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Our board of directors has adopted a written policy regarding related person transactions as part of our corporate governance guidelines. Under this policy, a related person transaction shall be consummated or shall continue only if:

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For purposes of this policy, the term “related person” means any related person pursuant to Item 404 of Regulation S-K of the Securities Act, except for transactions with Sempra and its affiliates (other than the Oncor Ring-Fenced Entities), which transactions are subject to restrictions set forth in our LLC Agreement.

A “related person transaction” is a transaction between us and a related person (including any transactions requiring disclosure under Item 404 of Regulation S-K under the Securities Act, if applicable), other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee:



Our board of directors has determined that it is appropriate for its Audit Committee to review and approve or ratify related person transactions. In unusual circumstances, we may enter into related person transactions in advance of receiving approval, provided that such related person transactions are reviewed and ratified as soon as reasonably practicable by the Audit Committee of the board of directors. If the Audit Committee determines not to ratify such transactions, we shall make all reasonable efforts to cancel or otherwise terminate such transactions.

The related person transactions policy described above also does not apply to Sempra and its subsidiaries and affiliates (other than the Oncor Ring-Fenced Entities), which are subject to restrictions set forth in our LLC Agreement. Our LLC Agreement requires that we maintain an arm’s-length relationship with the Sempra and its affiliates (other than the Oncor Ring-Fenced Entities) or any other direct or indirect equity holders of Oncor or Oncor Holdings, consistent with the PUCT’s rules applicable to Oncor, and only enter into transactions with Sempra and its affiliates (other than the Oncor Ring-Fenced Entities) that are both (i) on a commercially reasonable basis, and (ii) if such transaction is material, approved

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by (a) a majority of the members of our board of directors, and (b) prior to a Trigger Event (as defined in our LLC Agreement), the directors appointed by Texas Transmission, at least one of whom must be present and voting in order to approve the transaction.

Related Party Transactions



Operation Agreement With Sharyland



Pursuant to the PUCT order in Docket No. 48929 relating to Oncor’s 2019 acquisition of InfraREIT, Inc., we entered into an operation agreement with Sharyland pursuant to which we provide certain operation services to them at cost with no markup or profit. We provided Sharyland with approximately $771,000 worth of services pursuant to this agreement in 2025. Sempra holds an indirect 50% interest in Sharyland Holdings, L.P., the parent of Sharyland.



Our LLC Agreement requires that any material transactions with Sempra and its subsidiaries and affiliates (other than the Oncor Ring-Fenced Entities) be approved by a majority of our board of directors and the directors appointed by Texas Transmission present and voting, provided that at least one director appointed by Texas Transmission must be present and voting. The operation agreement was approved by our board of directors, including the directors appointed by Texas Transmission, who were both present and voting. 



Tax Sharing Arrangements



We are not a member of another entity’s consolidated tax group, but our owners’ federal income tax returns include their portion of our results. Under the terms of a tax sharing agreement among us, Oncor Holdings, Texas Transmission, and STH, we are generally obligated to make payments to our owners, pro rata in accordance with their respective membership interests, in an aggregate amount that is substantially equal to the amount of federal income taxes that we would have been required to pay if we were filing our own corporate income tax return. STH will file a combined Texas margin tax return which includes our results and our share of Texas margin tax payments, which are accounted for as income taxes and calculated as if we were filing our own return. See discussion in Note 1 to Financial Statements under “Provision in Lieu of Income Taxes.” Under the “in lieu of” tax concept, all in lieu of tax assets and tax liabilities represent amounts that will eventually be settled with our members. In the unlikely event such amounts are not paid under the tax sharing agreement, it is probable that they would be reimbursed to rate payers. 



At December 31, 2025, we had $17 million net receivable from members under the agreement. It consisted of a current federal income taxes receivable totaling $48 million ($38 million receivable from Sempra and $10 million receivable from Texas Transmission), partially offset by Texas margin tax payable to Sempra totaling $31 million. 



We made in lieu of income tax payments of $31 million in Texas margin tax-related payments to Sempra in the year ended December 31, 2025.



LLC Agreement of Oncor



In March 2018, in connection with Sempra’s indirect acquisition of Oncor Holdings, Oncor’s LLC Agreement was amended and restated in its entirety as set forth in the LLC Agreement. The LLC Agreement of Oncor among other things, sets out the members’ respective governance rights in respect of their ownership interests in Oncor. Among other things, the LLC Agreement provides for the management of Oncor by a board of directors consisting of 13 members, including seven Disinterested Directors, two directors designated by Texas Transmission (subject to certain conditions), two directors designated indirectly by Sempra and two directors that are current or former officers of Oncor. Texas Transmission also has the right to designate one non-voting observer to the board of directors, who is entitled to attend all meetings of the board of directors (subject to certain exceptions) and receive copies of all notices and materials provided to the board of directors.



The LLC Agreement prohibits Oncor and its subsidiaries from taking certain material actions outside the ordinary course of business without prior approvals by the members, some or all of the Disinterested Directors and/or the directors designated by one or more of the members. The LLC Agreement also sets forth certain separateness undertakings to ensure Oncor’s legal and financial separateness from Sempra and its direct and indirect subsidiaries (other than the Oncor Ring-Fenced Entities). Additionally, the LLC Agreement contains provisions regulating capital accounts of members, allocations of profits and losses and tax allocation and withholding.

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The LLC Agreement describes Oncor’s procedures and limitations on declaring and paying distributions to members. Pursuant to the LLC Agreement, we cannot make any distributions to members (other than contractual tax payments) that would cause us to exceed the PUCT’s authorized debt-to-equity ratio. The distribution restrictions also include the ability of a majority of the Disinterested Directors, or either of the two member directors designated to serve on our board of directors by Texas Transmission, to limit distributions (other than contractual tax payments) to the extent each determines it is necessary to meet expected future requirements of Oncor (including continuing compliance with the PUCT debt-to-equity ratio commitment). In addition, the LLC Agreement provides that if Oncor’s senior secured debt credit rating by any one of S&P, Moody’s or Fitch falls below BBB (Baa2) we must suspend distributions (other than contractual tax payments) until otherwise permitted to do so by the PUCT, and requires that Oncor notify the PUCT if either the credit rating of either Sempra or Oncor falls below its then current level. Distributions also cannot be made to the extent they would violate any applicable laws or regulations. Our LLC Agreement requires that any changes to such procedures and limitations be approved by Oncor Holdings and Texas Transmission and a majority of our board of directors present and voting, which must include (i) a majority of the Disinterested Directors, (ii) both directors appointed to serve on our board of directors by Sempra (through Oncor Holdings), (iii) both directors that are current or former officers of Oncor, and (iv) the directors designated to serve on our board of directors by Texas Transmission who are present and voting, provided that at least one such director must be present and voting in order to approve such matter.



In addition, any annual or multi-year budget with an aggregate amount of capital or operating and maintenance expenditures that are greater than or less than 10% of the capital or operating and maintenance expenditures in the annual budget for the immediately prior fiscal year or multi-year period, as applicable, must be approved by (i) a majority of the Disinterested Directors and (ii) the Texas Transmission director(s) present and voting, provided that at least one Texas Transmission director must be present and voting in order to approve such action. Also, any acquisition of or investment in any third party which involves the purchase of or investment in assets located outside the State of Texas for consideration in an amount greater than $1.5 billion must be approved by (a) a majority of the Disinterested Directors and (b) the Texas Transmission director(s) present and voting, provided that at least one Texas Transmission director must be present and voting in order to approve such action.



Contract for Services with James A. Greer



Effective February 23, 2026, we entered into a Contract for Services with James A. Greer, who retired as our Executive Vice President and Chief Operating Officer, a position he held through December 31, 2025. For additional information regarding the Contract for Services, see “Item 9B. Other Information.”



Registration Rights Agreement



In November 2008, we entered into a registration rights agreement (Registration Rights Agreement) by and among us, Oncor Holdings, Texas Transmission and STH. The Registration Rights Agreement grants customary registration rights to certain of our members. Subject to certain limitations set forth in the Registration Rights Agreement, these rights include the following: (i) the right of Oncor Holdings and Texas Transmission to demand that we register a specified amount of membership interests in accordance with the Securities Act; (ii) the right of both Oncor Holdings and Texas Transmission to demand registration of a specified amount of membership interests following an initial public offering; and (iii) the right of all members that are parties to the Registration Rights Agreement to have their membership interests registered if we propose to file a registration statement relating to an offering of membership interests (with certain exceptions).



Subject to certain exceptions, whenever we are required to effect the registration of any membership interests pursuant to the Registration Rights Agreement, we have agreed to use our best efforts to cause the applicable registration statement to become effective, and to keep each such registration statement effective until the earlier of (a) at least 180 days (or two years for a shelf registration statement) or (b) the time at which all securities registered under such registration statement have been sold.



Investor Rights Agreement



The investor rights agreement dated as of November 5, 2008, by and among Oncor, Oncor Holdings, Texas Transmission, STH and any other persons that subsequently become a party thereto (Investor Rights Agreement) governs certain rights of certain members of Oncor and STH arising out of their direct or indirect ownership of Oncor membership interests, including, without limitation, transfers of Oncor membership interests and restrictions thereon. Texas

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Transmission may transfer its Oncor membership interests under a registration statement or pursuant to applicable securities laws. The Investor Rights Agreement also grants Texas Transmission certain “tag-along” rights in relation to certain sales of Oncor membership interests by Oncor Holdings. Subject to certain conditions, these “tag-along” rights allow Texas Transmission to sell a pro-rata portion of its Oncor membership interests in the event of a sale of Oncor membership interests by Oncor Holdings on the same terms as Oncor Holdings would receive for its Oncor membership interests. The agreement further provides that under certain offerings of equity securities occurring before an initial public offering of Oncor, Texas Transmission and Oncor Holdings will receive preemptive rights to purchase their pro-rata share of the equity securities to be sold pursuant to such offerings. The Investor Rights Agreement also provides STH and Sempra with a right of first refusal to purchase any Oncor membership interests to be sold in a permitted sale by Texas Transmission or its permitted transferees.



Additionally, STH, Sempra, certain of Sempra’s subsidiaries and Oncor Holdings have certain “drag-along” rights in relation to offers from third-parties to purchase their directly or indirectly owned membership interests in Oncor, where the resulting sale would constitute a change of control of Oncor. These “drag-along” rights compel Texas Transmission and all other members of Oncor to sell or otherwise transfer their membership interests in Oncor on substantially the same terms as STH, Sempra or Oncor Holdings (as applicable). Pursuant to the Investor Rights Agreement, all members of Oncor that have entered into such agreement must cooperate with Oncor in connection with an initial public offering of Oncor.



Transactions with Affiliates and Portfolio Companies of Certain of our Beneficial Owners



The beneficial owners of Texas Transmission include various entities and funds who make equity investments in various companies (Portfolio Companies) in the ordinary course of their business. We have in the past entered into, and may continue to enter into, transactions with Portfolio Companies or their affiliates in the ordinary course of business on an arm’s-length basis, which may indirectly result in revenues to beneficial owners of Texas Transmission. 

Director Independence

Our LLC Agreement provides that seven members of our board of directors must be Disinterested Directors. For a director to be deemed a Disinterested Director, our board of directors must affirmatively determine that (i) such director has not had within the previous ten years, nor currently has, a material relationship with Sempra or its subsidiaries or affiliated entities or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings and (ii) that such director meets the independence standards in Section 303A of the NYSE Listed Company Manual in all material respects in relation to Sempra or its subsidiaries and affiliated entities or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings.



Our board of directors considers which of its members qualify as Disinterested Directors annually, in part by reviewing relevant relationships with organizations with which our directors are affiliated. Our board of directors has determined that each of Messrs. Berg, Mack, Saenz and Walker and Mses. Johnson, Keliher and Rodriguez qualify as both independent directors under the NYSE independence standards and as Disinterested Directors under the standards in our LLC Agreement.  



In connection with its review and determination of independence under the NYSE independence standards, our board of directors considered what it viewed as certain non-material relationships and transactions involving our directors, including that Oncor is a dues paying member and has served as a corporate sponsor of the annual meeting of the Dallas Citizens Council, a 501(c)(6) nonprofit organization where Mr. Walker serves as the chief executive officer and Oncor’s chief executive serves on its board of directors.



Mr. Shapard is our Chairman of our board of directors and presides at all meetings of our board of directors. He was appointed non-executive Chairman of our board of directors effective upon Sempra’s March 2018 indirect acquisition of Oncor Holdings. Prior to that time, Mr. Shapard served as our Chief Executive. 



Our board of directors has designated an Audit Committee, Finance Committee, Governance and Sustainability Committee and O&C Committee to exercise certain powers and authorities of the board of the directors. Members of these committees are not required by our LLC Agreement or board of directors to meet any independence standards. Mr. Shapard, who serves on our board of directors as an Oncor Officer Director, has served as chair of the Finance Committee since its inception in February 2025. Mr. Zucchet, who was designated to serve on our board of directors by Texas Transmission in November 2008, has served on the O&C Committee since May 2010, the Governance and Sustainability

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Committee since February 2011, and the Finance Committee since February 2025. Ms. Newell, who was designated to serve on our board of directors by Texas Transmission in July 2019, has served on the Audit Committee since such date and the Finance Committee since February 2025. Mr. Martin, who was designated to serve on our board of directors by Sempra (through Oncor Holdings) in March 2018, has served on the O&C Committee since April 2020. Mr. Bird, who was designated to serve on our board of directors by Sempra (through Oncor Holdings) in January 2024, has served on the Audit Committee and the Governance and Sustainability Committee since January 2024 and the Finance Committee since February 2025. None of Messrs. Bird, Martin, Shapard or Zucchet or Ms. Newell qualifies as independent under the NYSE independence standards or as a Disinterested Director for purposes of our LLC Agreement.



For information on the structure of our board of directors, see “Item 10. Directors, Executive Officers and Corporate Governance—Director Appointments.”

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Item 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES



Deloitte & Touche LLP (PCAOB ID No. 34) is our independent registered public accounting firm.



Our Audit Committee has adopted a policy governing the engagement of our independent registered public accounting firm. The policy provides that in addition to the audit of the financial statements, related quarterly reviews and other audit services, and providing services necessary to complete SEC filings, our independent auditor may be engaged to provide non-audit services as described herein. Prior to engagement, all services to be rendered by the independent auditor must be authorized by our Audit Committee in accordance with pre-approval procedures which are defined in the policy. The pre-approval procedures require:







Our Audit Committee may also approve certain ongoing non-audit services not previously approved in the limited circumstances provided for in the SEC rules. All services performed in 2025 by Deloitte & Touche LLP, the member firms of Deloitte & Touche Tohmatsu and their respective affiliates (Deloitte & Touche) were pre-approved by our Audit Committee.



The policy defines those non-audit services which our independent auditor may also be engaged to provide as follows:









The policy prohibits us from engaging our independent auditor to provide:





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In addition, the policy prohibits our independent auditor from providing tax or financial planning advice to any of our officers.



The policy also contains the following standard of conduct for our independent auditor related to staffing and conducting its annual audit:





Compliance with our Audit Committee’s policy relating to the engagement of Deloitte & Touche is monitored on behalf of our Audit Committee by our chief internal audit executive. Reports from Deloitte & Touche and the chief internal audit executive describing the services provided by Deloitte & Touche and fees for such services are provided to our Audit Committee no less often than quarterly.





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PART IV



Item 15.EXHIBIT AND FINANCIAL STATEMENT SCHEDULES



The consolidated financial statement schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.



(a)Exhibits:























































*    Incorporated herein by reference.

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SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Oncor Electric Delivery Company LLC has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.





Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Oncor Electric Delivery Company LLC and in the capacities and on the date indicated.







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Supplemental Information to be Furnished with Reports Filed

Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered

Securities Pursuant to Section 12 of the Act



No annual report, proxy statement, form of proxy or other proxy soliciting material has been sent to security holders of Oncor Electric Delivery Company LLC during the period covered by this Annual Report on Form 10-K for the fiscal year ended December 31, 2025. 







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