Filed pursuant to Rule 424(b)(3)
Registration No. 333-292610

PROSPECTUS

ONCOR ELECTRIC DELIVERY COMPANY LLC

Offers to Exchange the Exchange Notes Set Forth Below

Registered Under the Securities Act of 1933, as amended,

for

Any and All Outstanding Notes

Set Forth Opposite the Corresponding Exchange Notes

 

EXCHANGE NOTES		OUTSTANDING NOTES
$500,000,000 aggregate principal amount of its 4.50% Senior Secured Notes due 2027		$500,000,000 aggregate principal amount of its 4.50% Senior Secured Notes due 2027
$100,000,000 aggregate principal amount of its 4.65% Senior Secured Notes due 2029		$100,000,000 aggregate principal amount of its 4.65% Senior Secured Notes due 2029
$650,000,000 aggregate principal amount of its 5.35% Senior Secured Notes due 2035		$650,000,000 aggregate principal amount of its 5.35% Senior Secured Notes due 2035
$650,000,000 aggregate principal amount of its 5.80% Senior Secured Notes due 2055		$650,000,000 aggregate principal amount of its 5.80% Senior Secured Notes due 2055

We are offering to exchange (such transactions, the exchange offers) (i) $500,000,000 aggregate principal amount of our 4.50% Senior Secured Notes due 2027 (2027 exchange notes) that have been registered under the Securities Act of 1933, as amended (Securities Act), for any and all of our existing 4.50% Senior Secured Notes due 2027 issued in a private offering on March 20, 2025 (outstanding 2027 notes), (ii) $100,000,000 aggregate principal amount of our 4.65% Senior Secured Notes due 2029 (2029 exchange notes) that have been registered under the Securities Act, for any and all of our existing 4.65% Senior Secured Notes due 2029 issued in a private offering on January 14, 2025 (outstanding 2029 notes), (iii) $650,000,000 aggregate principal amount of our 5.35% Senior Secured Notes due 2035 (2035 exchange notes) that have been registered under the Securities Act, for any and all of our existing 5.35% Senior Secured Notes due 2035 issued in a private offering on March 20, 2025 (outstanding 2035 notes), and (iv) $650,000,000 aggregate principal amount of our 5.80% Senior Secured Notes due 2055 (2055 exchange notes, and together with the 2027 exchange notes, the 2029 exchange notes, and the 2035 exchange notes, the exchange notes) that have been registered under the Securities Act, for any and all of our existing 5.80% Senior Secured Notes due 2055 issued in a private offering on March 20, 2025 (outstanding 2055 notes, and together with the outstanding 2027 notes, the outstanding 2029 notes, and the outstanding 2035 notes, the outstanding notes). The outstanding 2029 notes were an additional issuance of our 4.65% Senior Secured Notes due 2029, $550,000,000 of which we previously issued on November 13, 2024 and are currently outstanding (initial 2029 notes). The 2029 exchange notes will have substantially the same terms, including, without limitation, the same maturity date and interest payment dates, as the initial 2029 notes, and will be part of the same series as the initial 2029 notes. The 2029 exchange notes are expected to be designated by the same CUSIP number as, and be fungible with, the initial 2029 notes that were previously exchanged on January 27, 2025 in an offering registered under the Securities Act (exchanged initial 2029 notes).

The Exchange Offers

 

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We will exchange all unregistered outstanding notes that are validly tendered and not validly withdrawn for an equal principal amount of exchange notes of the respective series that are registered under the Securities Act.

 

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You may withdraw tenders of outstanding notes at any time prior to the expiration of the exchange offers.

 

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The exchange offers expire at 5:00 p.m., New York City time, on March 2, 2026, unless extended. We do not currently intend to extend the expiration date.

 

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The exchange of outstanding notes for exchange notes in the exchange offers will not be a taxable event for U.S. federal income tax purposes.

 

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The exchange notes to be issued in the exchange offers will have terms identical in all material respects to the respective series of outstanding notes, except that the exchange notes will be registered under the Securities Act and do not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement applicable to such outstanding notes.

Results of the Exchange Offers

 

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Except as prohibited by applicable law, the exchange notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods. The exchange notes are a new issue of securities for which there is no established public market. There is only a limited market for the exchanged initial 2029 notes. We do not intend to list the exchange notes on a national securities exchange or market.

 

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We will not receive any proceeds from the exchange offers.

All untendered outstanding notes will remain outstanding and continue to be subject to the restrictions on transfer set forth in the outstanding notes and in the indenture governing the outstanding notes. In general, the outstanding notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offers, we do not currently anticipate that we will register the outstanding notes under the Securities Act.

Each broker-dealer that receives exchange notes for its own account in the exchange offers must acknowledge that it will deliver a prospectus in connection with any resale of those exchange notes. The letter of transmittal states that by so acknowledging and delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where the broker-dealer acquired such outstanding notes as a result of market-making or other trading activities.

We have agreed to keep effective the registration statement of which this prospectus is a part until the earlier of 90 days after the completion of the exchange offers or such time as broker-dealers no longer own any notes. See “Plan of Distribution.”

 

 

See “Risk Factors” beginning on page 11 for a discussion of certain risks that you should consider before participating in the exchange offers.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of the exchange notes to be distributed in the exchange offers or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is January 20, 2026.

You should rely only on the information included in this prospectus. We have not authorized anyone to provide you with additional or different information. The prospectus may be used only for the purposes for which it has been published, and no person has been authorized to give any information not contained herein. If anyone else provides you with additional, different or inconsistent information, you should not rely on it. You should assume that the information contained in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business profile, financial condition, results of operations or prospects may have changed since that date. The representations and warranties contained in any agreement that we have filed as an exhibit to the registration statement of which this prospectus is a part or that we may publicly file in the future may contain representations and warranties made by and to the parties thereto as of specific dates. While we are responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in the registration statement of which this prospectus is a part not misleading, those 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. No offer of these securities is being made in any jurisdiction where such offer is prohibited.

 

 

TABLE OF CONTENTS

 

SUMMARY			1
RISK FACTORS			11
FORWARD-LOOKING STATEMENTS			29
INDUSTRY AND MARKET INFORMATION			31
USE OF PROCEEDS			32
CONSOLIDATED CAPITALIZATION AND SHORT-TERM DEBT OF ONCOR AND SUBSIDIARIES			33
OUR BUSINESS AND PROPERTIES			34
LEGAL PROCEEDINGS			42
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			43
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			68
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			68
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE			71
EXECUTIVE COMPENSATION			82
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS			119
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE			121
THE EXCHANGE OFFERS			126
DESCRIPTION OF THE NOTES			136
SUMMARY OF MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES			153
SUMMARY OF MATERIAL ERISA CONSIDERATIONS			154
PLAN OF DISTRIBUTION			155
LEGAL MATTERS			155
EXPERTS			155
AVAILABLE INFORMATION			155
GLOSSARY			157
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			F-1

 

 

 

 

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RISK FACTORS

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before deciding to participate in the exchange offers. Any of these risks could materially and adversely affect our business, financial condition, operating results or cash flows; however, these risks are not our only risks. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial also may materially and adversely affect our business, financial condition, results of operations or cash flows. In such a case, the trading price of the exchange notes could decline or we may not be able to make payments of interest and principal on the exchange notes, and you may lose all or part of your original investment.

Summary of Risk Factors

The following is a summary of some of the risks and uncertainties that could materially adversely affect our business, financial condition and results of operations. You should read this summary together with the more detailed description of each risk factor contained below.

Risks Related to Regulatory and Legislative Matters

 

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Our business is subject to ongoing complex governmental regulations and legislation that have impacted, and will continue in the future to impact, us.

 

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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.

 

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Adverse publicity or public perception relating to us, transmission and distribution utilities, ERCOT, or the electricity industry could lead to changes in regulatory policy or legislation that could have a significant impact on our business.

 

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We are subject to various mandatory regulatory standards and requirements and could be subject to additional standards in the future. Efforts to comply with those standards and requirements could subject us to higher costs, and non-compliance with applicable standards or expectations could have a material adverse effect on our business.

Risks Related to Our Business and Operations

 

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

 

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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.

 

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Severe weather, natural disasters and other related phenomena have in the past and could in the future have a material adverse effect on our business, financial condition, results of operations and cash flow, and climate change could make such phenomena more prevalent and unpredictable.

 

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Wildfires could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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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 our results of operations and financial condition.

 

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

 

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

 

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

 

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Our revenues are concentrated in and collected through a small number of customers and a significant delay or default in payment could adversely affect our cash flows, liquidity, financial condition and/or results of operations.

 

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While we require security prior to beginning construction on certain customer-requested projects, there can be no assurance that if any such projects are cancelled, we will be able to recover all of the costs expended by us on those projects through such security or otherwise.

 

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We are dependent upon a limited number of suppliers and service providers for certain of our operations. Disruptions in our supply chain or the availability of our suppliers to perform on expected or acceptable terms, including as a result of competition for materials, the contractor labor market and inflation, could negatively impact us.

 

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

 

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

 

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

 

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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.

 

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

 

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Insufficient electricity generation within the ERCOT market or disruptions at power generation facilities that supply power within the ERCOT market could interrupt and/or negatively impact our transmission and distribution services.

 

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The growth of DER and similar technologies or actions that decrease demand or consumption of electricity we deliver may significantly adversely impact us, including by limiting future infrastructure investments and reducing our ability to timely recover the cost of our investment in, and earn a reasonable return on, our electricity delivery facilities.

 

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

 

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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 this goodwill, which may adversely impact our reported financial condition and results of operations.

Risks Related to Financial and Market Matters

 

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

 

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

 

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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.

 

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In the future, we could have capital needs that could be difficult to satisfy under some circumstances, including existing limitations on our ability to incur indebtedness and uncertain financial market conditions.

Risks Related to the Exchange Offers

 

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There may be adverse consequences if you do not exchange your outstanding notes.

 

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Your ability to transfer the exchange notes may be limited if there is no active trading market, and there is no assurance that any active trading market will develop for the exchange notes.

 

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Certain persons who participate in the exchange offers must deliver a prospectus in connection with resales of the exchange notes.

Risks Related to the Notes

 

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The market price of the notes will fluctuate.

 

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The terms of the notes contain limited covenants and other protections.

 

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The Indenture and the Deed of Trust permit us to incur significant additional debt. Accordingly, the Indenture will not afford the holders of the notes protection in the event we incur significant additional debt.

 

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It may be difficult to realize the value of the Collateral securing the notes.

 

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Bankruptcy laws may limit your ability to realized value from the Collateral.

 

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Any future pledges of Collateral may be avoidable.

 

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The Collateral Agent’s ability to exercise remedies with respect to Collateral is still limited.

 

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Proceeds from any sale of the Collateral upon a foreclosure may be insufficient to repay the notes in full.

 

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Risks Related to Regulatory and Legislative Matters

Our business is subject to ongoing complex governmental regulations and legislation that have impacted, and will continue in the future to impact, 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, the Energy Policy Act of 2005, the Code and ERISA), 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, the I.R.S., the TCEQ, U.S. Fish and Wildlife Service, the EPA, and the SEC). 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 to compliance with existing laws, policies, regulations, rules, guidelines, directives, protocols and administrative actions, and such compliance activities also result in increased costs. In addition, we must continually adapt to new or revised or reinterpreted laws, policies, regulations, rules, guidelines, directives, and protocols and administrative actions, which expose us to increased costs, expenses, and employee time and effort needed to comply, and could have a material and adverse effect on our business, cash flows, liquidity, financial condition, results of operations and/or business prospects. Developing, constructing, operating, and maintaining our transmission and distribution system also requires us to obtain various approvals, licenses, permits, and franchises from regulatory and governmental authorities. Material delays in obtaining, or failures to obtain, necessary approvals, licenses, permits and franchises could significantly impact us.

In addition, if it is determined that we did not comply with applicable laws, statutes, regulations, rules, directives, tariffs or orders, our operations, financial condition, results of operations, cash flows and our reputation could be materially and adversely affected, particularly if we are ordered to pay a material amount in penalties, customer/rate payer refunds, or other amounts. 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. The PUCT has the authority to impose penalties of up to $1 million per violation per day for failure to meet certain weatherization requirements and up to $25,000 per day per violation for other violations.

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. The time between when we incur costs and when we begin to recover those costs in rates is known in the utility industry as “regulatory lag” and cannot be fully eliminated. 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 full recovery of 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 or other increased costs incurred by us after the test year in our most recently decided base rate review.

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. Since 2021, the historical test year in our last completed comprehensive base rate review (PUCT Docket No. 53601), we have experienced rising capital investments as well as increased operating costs and interest expenses, some or all of which may continue in the foreseeable future and could result in more frequent comprehensive base rate proceedings. In June 2025, we filed a request for a base rate review with the PUCT and the cities in our service territory that have retained original jurisdiction over rates, and that proceeding remains pending. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulation and Rates—Regulatory Matters” for a discussion of our current base rate review 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 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

 

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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.

Adverse publicity or public perception relating to us, transmission and distribution utilities, ERCOT, or the electricity industry could lead to changes in regulatory policy or legislation that could have a significant impact on our business.

We provide electricity delivery services to millions of Texans, and failure to meet customer expectations, particularly regarding reliability, communication, and outage restoration times, could significantly impact our reputation. Contributing factors to our public perception could be outside our control, including severe weather, ERCOT mandates such as mandatory load shed events, the amount of electricity produced by generators in ERCOT, economic conditions, actions by other ERCOT market participants, including other transmission and distribution utilities, and other emergency events. Negative public perception of us, our industry, or ERCOT could adversely affect legislative or regulatory processes or outcomes, result in new or changed legislative or regulatory requirements, government/regulatory investigations, administrative actions, fines, penalties, or other sanctions or requirements against us that could have a material adverse effect on us, our financial position, results of operations and cash flows. Addressing any adverse publicity, regulatory scrutiny, enforcement or other legal proceedings would be time consuming and likely also result in increased expenses.

The Texas Legislature operates under a biennial system and meets in regular session in every odd-numbered year and during special sessions called by the Governor of Texas. 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. ERCOT is subject to oversight by the PUCT and the Texas Legislature, and either could impose changes to the ERCOT market that could impact us. Significant changes to the ERCOT market structure or within 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. In recent years, storms have resulted in issues related to reliable electric service in the ERCOT market and prolonged power outages, the PUCT and the Texas Legislature have instituted various changes relating to operations in the ERCOT market. Both the PUCT and the Texas Legislature continue to actively review the operations, as well as the overall design, of the ERCOT market. We cannot predict whether, or to what extent, any future legislation or regulations relating to the ERCOT market will impact our business.

We are subject to various mandatory regulatory standards and requirements and could be subject to additional standards in the future. Efforts to comply with those standards and requirements could subject us to higher costs, and non-compliance with applicable standards or expectations could have a material adverse effect on our business.

As a regulated transmission and distribution utility, our operations are subject to multiple mandatory regulatory standards and requirements. The PUCT has jurisdiction with respect to ensuring the service quality and reliability of the delivery of electricity to retail customers by electric utilities and has established various operational standards, including reliability standards and weatherization requirements, which apply to each utility. The FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by utilities within the ERCOT market. The FERC has designated NERC to establish and enforce reliability standards (including cybersecurity and physical security standards), under the FERC’s oversight, for all owners, operators and users of electric transmission services. The FERC has approved the delegation by NERC of compliance and enforcement authority for reliability in the ERCOT region to Texas RE.

Compliance with mandatory regulatory standards and requirements, such as those relating to service quality, reliability and weatherization of facilities, is subject to regular reporting, reviews and audits. To maintain compliance with such standards and requirements, or to meet our reliability goals, we may be subjected to higher-than-expected costs, including costs related to additional personnel and/or increased capital expenditures to construct and maintain infrastructure in accordance with these standards and requirements to meet anticipated demand. We must report to the PUCT concerning our performance with respect to the applicable reliability standards on an annual basis. We are also required to file declarations twice a year certified by our chief executive addressing our compliance with the PUCT’s weather preparedness measures. In addition, the PUCT requires that ERCOT conduct inspections of our facilities to determine compliance with weather preparation measures. Also, as a NERC registered entity, we are subject to periodic audits by Texas RE of our compliance with operations and critical infrastructure protection standards, including reliability standards. These audits will occur as designated by Texas RE at a minimum of once every three years. While we expect to recover costs and expenditures from customers through regulated rates related to such compliance costs, there can be no assurance that the PUCT will approve full recovery of such costs or the timing of any such recovery. If we were found to be noncompliant with applicable reliability/service quality standards or weatherization requirements, we could be subject to reputational harm, regulatory scrutiny, or sanctions, including monetary penalties. For example, under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1.5 million per day per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the power system against potential disruptions from cyber and physical security breaches. Penalties imposed by the PUCT, Texas RE, the FERC and/or NERC may not be recoverable from customers through regulated rates and could have a material adverse impact on our financial condition, results of operations and cash flows.

 

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Moreover, local, state, or federal legislative or regulatory initiatives may attempt to control or limit the causes of climate change, including greenhouse gas emissions, such as carbon dioxide and methane. Legislation or regulation of emissions, including mandatory reporting requirements, could subject us to increased litigation risks and materially increase costs to our operations as well as to our customers and suppliers. They could also provide a cost advantage to alternative energy sources or result in other costs or requirements, such as costs associated with the adoption of new infrastructure and technology to respond to new mandates. Developing and implementing plans for compliance with voluntary or mandatory climate commitments can also lead to additional capital, personnel and operation and maintenance expenditures. Increased costs related to these compliance activities could adversely affect our business, financial condition, results of operations and cash flows.

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, have an adverse impact on 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, 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 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

 

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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. Additional cybersecurity requirements could also be applied to us in the future. 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 have a material adverse effect on our business, financial condition, results of operations and cash flow, 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 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. 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 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 extreme drought to 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.

 

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Wildfires could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 maintain a wildfire mitigation plan and 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 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.

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 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.

While we maintain excess liability insurance that includes wildfire coverage, 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.

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 our results of operations and financial condition.

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. In 2023, in response to the rise of such incidents, the Texas Legislature passed legislation implementing criminal penalties for certain incidents involving damaging or vandalizing critical electric infrastructure facilities. There is no guarantee that this legislative action will have a deterring effect to physical attacks on our utility assets. A physical attack on our assets could also 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. Further, certain of our employees who work in the field have experienced threats of violence during the performance of their work. Threats of violence, actual violence and other concerns may result in field employees being unable or unwilling to complete critical functions.

A significant number 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

 

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peak efficiency or reliability. A risk of increased maintenance and capital expenditures arises from damage to facilities due to storms and other severe weather events, natural disasters, wildfires, wars, accidents, terrorist or criminal acts, cyber-attacks, and other catastrophic events. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs that may not be recoverable through rates and/or the write-off of our investment in the capital project or improvement.

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, our financial condition, results of operations, or cash flows could be materially affected.

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. We have seen, and expect to continue to see, increased insurance premium costs. In 2024, payments related to our insurance premiums and related costs increased by approximately $50 million compared to 2023, an approximately 240% increase. 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 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 continue adversely affect our results of operations, financial position or cash flows.

Our capital deployment plan may not be executed as planned, which could adversely impact our reputation, reliability, 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 disclosed herein is attributable to expected growth in ERCOT, particularly due to increased demand from large commercial and industrial customers, and material decreases or increases in that growth profile could materially impact our capital expenditure projections. Furthermore, there can be no guarantee that our capital investments will ultimately be recoverable in rates.

While our capital expenditure plans disclosed herein include projects to successfully maintain or replace our aging infrastructure and address the expected growth of electricity demand in our service territory, particularly as a result of increased commercial and industrial demand and electrification goals of customers, 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 disclosed herein 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 by customers 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, 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.

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

 

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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 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. Lawsuits have been filed by approximately 200 plaintiffs 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. While all claims against the transmission and distribution utilities that were party to the proceeding, including Oncor, have been dismissed from the proceeding, that dismissal has been appealed and we cannot predict the outcome of the appeals process relating to the dismissal of those claims 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 could adversely affect our cash flows, liquidity, financial condition and/or results of operations.

Our revenues from each of the transmission and distribution operations of our business are concentrated in a small number of customers. As of September 30, 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 22%, respectively, of our total operating revenues for the nine months ended September 30, 2025, 25% and 23%, respectively, of our total operating revenues for the year ended December 31, 2024 and 25% and 23%, respectively, of our total operating revenues for the year ended December 31, 2023. We collect network transmission revenues from over 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. PUCT rules allow for the recovery of uncollectible amounts due from REPs (but not network transmission customers) through rates. 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.

While we require security prior to beginning construction on certain customer-requested projects, there can be no assurance that if any such projects are cancelled, we will be able to recover all of the costs expended by us on those projects through such security or otherwise.

We require customers who do not meet certain credit quality thresholds to provide security to us before we commence construction on certain customer-requested construction projects for generation interconnection or new/expanded electricity delivery system facilities. 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 and ultimately recoverable in rates due to customer cancellation. At December 31, 2024, we held an aggregate of approximately $1.5 billion in letters of credit, $280 million in parent/affiliate guarantees and $210 million in restricted cash as customer-provided security. Such customer-provided security is subject to return in accordance with PUCT rules, ERCOT requirements or our tariffs. 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. 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 security or rates could have an adverse impact on us, and those amounts could be material.

 

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We are dependent upon a limited number of suppliers and service providers for certain of our operations. Disruptions in our supply chain or the availability of our suppliers to perform on expected or acceptable terms, including as a result of competition for materials, the contractor labor market and inflation, could negatively impact us.

We rely on suppliers and service providers to provide us with certain specialized materials and services, including for construction, maintenance and repair of electricity delivery facilities and power lines, information technology and customer operations. In certain instances, our operations are dependent upon a limited number of suppliers and service providers, and 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, 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 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. International 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. Higher than anticipated costs in the future could have an adverse impact on our business, financial condition, results of operations, liquidity, and cash flows.

Our future success is dependent on our ability to attract and retain sufficient qualified personnel to meet our business needs and to identify and develop talent, 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, 2024, approximately 15% of our employee population is retirement eligible and approximately 25% 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.

 

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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 electricity delivery 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 8 to Interim Financial Statements and Note 9 to Annual 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 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. See Note 8 to Interim Financial Statements, Note 9 to Annual Financial Statements, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Defined Benefit Pension Plans and OPEB Plans” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources—Available Liquidity and Liquidity Needs, Including Capital Expenditures—Pension Plans and OPEB Plans Funding” for further information regarding pension and OPEB funding.

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 September 30, 2025, December 31, 2024 and 2023, we had recorded net regulatory assets (after taking into account related regulatory liabilities) totaling $230 million, $242 million and $291 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 Interim Financial Statements and Note 2 to Annual Financial Statements for further information regarding these regulatory assets.

We regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets. Acquisitions involve various risks, 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.

 

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Insufficient electricity generation within the ERCOT market or disruptions at power generation facilities that supply power within the ERCOT market could interrupt and/or negatively impact our transmission and distribution services.

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. We do not own any generation facilities. The amount of electricity generated and the mix of generation resources within the ERCOT market is not within our control. Electricity demand in ERCOT has increased in recent years and is expected to continue to increase. Projected 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. In December 2024, ERCOT released a study forecasting over 150,000 MW of peak summer demand for 2030, compared to the current record of 85,508 MW set in the summer of 2023, and noted an expected supply deficit to meet this demand under current planning assumptions. 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 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. In addition, 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.

The growth of DER and similar technologies or actions that decrease demand or consumption of electricity we deliver may significantly adversely impact us, including by limiting future infrastructure investments and reducing our ability to timely recover the cost of our investment in, and earn a reasonable return on, our electricity delivery facilities.

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. Research and development activities are ongoing to improve existing and alternative technologies and services to produce and store electricity, and it is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will make these technologies more attractive to customers than relying on traditional sources of electricity. Such changes in technology, as well as public perception of DER and legislation or regulations relating to DER, could also alter the channels through which retail customers buy and receive electricity. For instance, the PUCT has instituted various projects reviewing the regulatory framework regarding DER and other non-traditional technologies, and it has approved the participation of aggregated DERs in the wholesale electric market. Aggregated DERs are customer DERs aggregated by a REP that coordinates the operation of those customers’ individual devices to collectively reduce demand on the grid or export power to the grid under an ERCOT instruction. Aggregated DERs are aggregated by a REP that coordinates the operation of those customers’ individual devices to collectively reduce demand on the grid or export power to the grid under an ERCOT instruction. 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), 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 advances in technology that lower or alter the demand for electricity, governmental actions to require or incentivize reductions in electricity consumption, and other conservation or customer demand management efforts, which, absent regulatory changes related to how Oncor recovers investments in rates, could likewise significantly reduce our ability to timely recover the cost of our investment and earn a

 

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reasonable return on our electricity delivery facilities, lead to more frequent comprehensive base rate reviews to recover costs, and increase the risks related to rate regulation. Effective energy conservation or demand management by our customers could result in significantly reduced electricity demand and usage, or significantly slow the growth in demand and usage. 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.

Legislation, regulation, or customer initiatives to combat climate change could also have an impact on operations and demand in the ERCOT market, which could in turn impact us. For instance, increased electrification in the ERCOT market, particularly through oil and gas producers electrifying their operations and widespread electrification of vehicles, could result in significant increased demand on the ERCOT system. Such increased demand could create operational and reputational risks to meet customer reliability expectations. Increased electric infrastructure spend across the country as a result of climate change initiatives could also impact our supply chain by increasing the costs and/or decreasing the availability of equipment and materials necessary for transmission and distribution operations.

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

We currently use AI in limited contexts and are exploring additional uses of AI, including generative AI, and its ability to enhance our operations. There are significant risks involved in developing and deploying AI, and there can be no assurance that the use of AI will enhance our operations or be beneficial to our business. For example, our AI-related efforts may give rise to risks related to harmful content, accuracy, bias, discrimination, intellectual property 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 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 Annual 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. 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 and the Term Loan Agreement also provide that interest rates charged for borrowings and commitment fees on undrawn amounts may be adjusted based on our credit ratings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources—Credit Rating Provisions and Material Debt Covenants—Material Debt Credit Rating, Financial and Cross-Default Covenants” for more information on material credit rating covenants in the Credit Facilities and the Term Loan Agreement and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulation and Rates—Regulatory Matters—2025 Comprehensive Base Rate Review (PUCT Docket No. 58306)” for more information on our current base rate review.

 

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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.

Because our business is 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 Agreement, our CP Program, or our AR Facility. 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 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 2024, 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. The PUCT-approved cost of debt in our most recently completed base rate review (PUCT Docket No. 53601), which was based on a 2021 test year and is reflected in our current base rates, is lower than our actual average cost of debt for the year 2024. We do not anticipate a change in our PUCT-approved cost of debt prior to the completion of our current base rate review proceeding or a subsequent base rate review proceeding. 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 10 to Interim Financial Statements and Note 11 to Annual Financial Statements for additional information regarding derivative financial instruments.

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

 

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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 Note 1 to Annual Financial Statements and “Our Business and Properties—Ownership Structure and Ring-Fencing Measures” for additional information on our ring-fencing measures.

In the future, we could have capital needs that 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 Agreement, our 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 favorable 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, the Term Loan Agreement and AR Facility, and the pricing and terms we receive in the financial markets, could be adversely impacted by various factors, such as:

 

•

changes in U.S. and foreign financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms;

 

•

perceived risks related to the industry in which we operate;

 

•

additional reforms in regulatory and/or legislative policies impacting the industry in which we operate;

 

•

economic weakness in the ERCOT market;

 

•

changes in interest rates;

 

•

a deterioration of our credit or a reduction in our credit ratings or ratings outlook;

 

•

a deterioration of the credit or insolvency or financial distress of one or more lenders under our Credit Facilities, the Term Loan Agreement or our AR Facility that affects the ability of the lender(s) to make loans to us;

 

•

a deterioration of the credit of Sempra or its affiliates (other than the Oncor Ring-Fenced Entities) or a reduction in the credit ratings or ratings outlook of Sempra or such affiliates that is perceived to potentially have an adverse impact on us despite the ring-fencing of the Oncor Ring-Fenced Entities from Sempra and such affiliates;

 

•

changes that impact accounts receivables from REPs and related rights resulting in a change to eligible receivables under our AR Facility;

 

•

a material breakdown in our risk management procedures; or

 

•

restrictions on our ability to issue CP Notes or access our Credit Facilities, the Term Loan Agreement or our AR Facility.

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 September 30, 2025, our regulatory capital structure was 56.0% debt to 44.0% 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources—Credit Rating Provisions and Material Debt Covenants—Material Debt Credit Rating, Financial and Cross-Default Covenants” for more information on these covenants. Also, because the $2B Credit Facility and $1B Credit Facility provide liquidity support to the CP Program, we treat CP Notes outstanding as a reduction to the available $2B Credit Facility borrowing capacity and the available $1B Credit Facility borrowing capacity, as applicable. See Note 4 to Interim Financial Statements and Note 5 to Annual Financial Statements for further information regarding the $2B Credit Facility, $1B Credit Facility and the CP Program.

Risks Related to the Exchange Offers

There may be adverse consequences if you do not exchange your outstanding notes.

If you do not exchange your outstanding notes for exchange notes in the exchange offers, you will continue to be subject to restrictions on transfer of your outstanding notes as set forth in the applicable Offering Memorandum. In general, the

 

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outstanding notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the applicable registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act. You should refer to “Summary—The Exchange Offers” and “The Exchange Offers” for information about how to tender your outstanding notes.

The tender of outstanding notes under the exchange offers will reduce the outstanding amount of the outstanding notes, which may have an adverse effect upon, and increase the volatility of, the market prices of the outstanding notes due to a reduction in liquidity.

Your ability to transfer the exchange notes may be limited if there is no active trading market, and there is no assurance that any active trading market will develop for the exchange notes.

We are offering the exchange notes to the holders of the outstanding notes. We do not intend to list the exchange notes on a national securities exchange or market. The exchange notes are a new issue of securities for which there is no established public market. There is only a limited market for the exchanged initial 2029 notes. We cannot assure you as to the liquidity of markets that may exist or develop for the exchange notes, your ability to sell the exchange notes or the price at which you would be able to sell the exchange notes. Certain financial institutions have informed us that they intend to make a market in the exchange notes after the exchange offers are completed. However, these financial institutions may cease their market-making efforts at any time without notice. We cannot assure you that an active market for the exchange notes will develop or, if developed, that it will continue. The exchange notes could trade at prices that may be lower than their principal amount or purchase price depending on many factors, including prevailing interest rates, the market for similar notes, our financial and operating performance and other factors. If no active trading market develops, you may not be able to resell the notes at their fair market value or at all.

Certain persons who participate in the exchange offers must deliver a prospectus in connection with resales of the exchange notes.

We have not requested, and do not intend to request, an interpretation by the staff of the SEC as to whether the exchange notes issued pursuant to our exchange offers in exchange for the outstanding notes may be offered for resale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Instead, based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1993), we believe that you may offer for resale, resell or otherwise transfer the exchange notes without compliance with the registration and prospectus delivery requirements of the Securities Act. We cannot guarantee that the SEC would make a similar decision about our exchange offers. If our belief is wrong, or if you cannot truthfully make the representations mentioned in “The Exchange Offers—Resale of Exchange Notes”, and you transfer any exchange note issued to you in the exchange offers without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. Additionally, in some instances described in this prospectus under “Plan of Distribution,” certain holders of exchange notes will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the exchange notes. If such a holder transfers any exchange notes without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, such a holder may incur liability under the Securities Act. We do not and will not assume, or indemnify such a holder against, this liability.

Risks Related to the Notes

The following risks apply to the outstanding notes and will apply equally to the exchange notes.

The market price of the notes will fluctuate.

Any material differences between our actual results and the historical results contained in our annual, quarterly and current reports filed with the SEC could have a significant adverse impact on the market price of the notes, assuming a market for the notes develops, or if developed, will continue. In addition, any adverse action with respect to our credit ratings or ratings outlook could have an adverse impact on the market price of the notes.

The terms of the notes contain limited covenants and other protections.

The Indenture governing the notes contains covenants restricting our ability to take certain actions. However, each of these covenants contains specified exceptions. In addition, these covenants are limited and do not protect holders of the notes from all events that could have a negative effect on the creditworthiness of the notes and the market price of the notes, assuming a market for the notes develops, or if developed, will continue.

 

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The Indenture and the Deed of Trust permit us to incur significant additional debt. Accordingly, the Indenture will not afford the holders of the notes protection in the event we incur significant additional debt.

The notes and the Indenture under which the notes are issued do not place any limitation on the amount of unsecured debt that may be incurred by us. The Indenture and the Deed of Trust also permit us to incur a significant amount of additional secured debt, including debt secured equally and ratably by the Collateral, subject to certain limitations, as described further under “Description of the Notes—Securing Additional Obligations” and “Description of the Notes—Limitation on Secured Debt.” Our incurrence of additional debt may have important consequences for holders of the notes, including making it more difficult for us to satisfy our obligations with respect to the notes, a loss in the trading value of the notes, if any, and a risk that the credit rating of the notes is lowered or withdrawn. The covenants contained in the Indenture and the Deed of Trust will not afford holders of notes protection in the event we incur significant additional debt. In addition, the Notes will be structurally subordinated to all existing and future indebtedness of our subsidiary, Receivables LLC, to the extent of the value of the collateral securing the AR Facility. 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 Oncor. The assets of Receivables LLC are not available to pay creditors of Oncor or any affiliate thereof.

It may be difficult to realize the value of the Collateral securing the notes.

Each of the assets and facilities that will be included in the Collateral is subject to the same kinds of risks as are described under “—Risks Related to Regulatory and Legislative Matters”, “—Risks Related to Our Business and Operations” and “—Risks Related to Financial and Market Matters”. We cannot provide any assurance that any of the necessary permits, certificates or other entitlements to operate those assets and facilities would be transferable to the Collateral Agent or any purchaser from the Collateral Agent in the event of a foreclosure upon that asset or facility. The Collateral Agent’s ability to foreclose on the Collateral on behalf of the holders of the notes may be subject to perfection, the consent of third parties and, with respect to those assets that are subject to the jurisdiction of the PUCT and the FERC, the prior approval by the PUCT and the FERC. The Collateral Agent’s ability to foreclose may also be subject to priority issues and practical problems associated with the realization of the Collateral Agent’s security interest in the Collateral. We cannot assure holders of the notes that the consents of any third parties and approvals by governmental entities will be given when required to implement a foreclosure on such assets, especially if we are not in compliance with the underlying permits at the time. Accordingly, the Collateral Agent may not have the ability to foreclose upon those assets or assume or transfer the right to operate those assets or facilities, and a temporary shutdown of operations may result and the value of the Collateral may significantly decrease. Even if the Collateral Agent assumes the right to operate the assets and facilities, there may also be practical problems associated with the Collateral Agent’s ability to identify a qualified operator to operate and maintain the assets and facilities. In addition, future regulatory developments or other inabilities to obtain or comply with required permits may adversely affect the value of the Collateral.

No appraisals of any Collateral have been prepared in connection with the exchange offers. The value of the Collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the Collateral. By their nature, some or all of the pledged assets may be illiquid and may have no readily ascertainable market value. We cannot assure holders of the notes that the fair market value of the Collateral as of the date of this prospectus exceeds the principal amount of the debt secured thereby. The value of the assets pledged as Collateral for the notes could be impaired in the future as a result of changing economic conditions, our failure to implement our business strategy, competition and other future trends.

Bankruptcy laws may limit your ability to realize value from the Collateral.

The right of the Collateral Agent to repossess and dispose of the Collateral upon the occurrence of an event of default under the Indenture is likely to be significantly impaired by applicable bankruptcy law if a bankruptcy case were to be commenced by or against us prior to the Collateral Agent having repossessed and disposed of, or otherwise exercised remedies in respect of, the Collateral. Under the U.S. bankruptcy code, a secured creditor is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of a security repossessed from such debtor, without bankruptcy court approval. Moreover, the U.S. bankruptcy code permits the debtor to continue to retain and to use collateral even though the debtor is in default under the applicable debt instrument, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security, if and at such times as the court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the bankruptcy case. In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary powers of a bankruptcy court, it is impossible to predict (1) how long payments under the notes could be delayed following the commencement of a bankruptcy case,

 

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(2) whether or when the Collateral Agent could repossess or dispose of the Collateral and (3) whether or to what extent holders of the notes would be compensated for any delay in payment or loss of value of the Collateral through the requirement of “adequate protection.”

In the event a bankruptcy court determines the value of the Collateral is not sufficient to repay all amounts due on the notes and any other obligations secured by the Collateral then the holders of the notes and such other obligations would hold secured claims to the extent of the value of the Collateral securing such claims, and would hold unsecured claims with respect to any shortfall. Applicable federal bankruptcy laws may not permit the payment and/or accrual of post-petition interest (including make-whole premiums), costs and attorneys’ fees during a debtor’s bankruptcy case. In addition, if we were to become the subject of a bankruptcy case, the bankruptcy trustee or debtor may seek to avoid certain pre-petition transfers made by us, including transfers held to be preferences or fraudulent conveyances. While transfers to secured creditors are generally not preferential, transfers to undersecured creditors may be subject to avoidance.

Any future pledges of Collateral may be avoidable.

Any future pledge of Collateral in favor of the Collateral Agent may be avoidable by the pledgor (as debtor in possession) or by its trustee in bankruptcy or other third parties if certain events or circumstances exist or occur, such that the pledge or granting of the security interest is deemed a fraudulent conveyance or preference.

The Collateral Agent’s ability to exercise remedies with respect to Collateral is limited.

The Deed of Trust provides the Collateral Agent on behalf of the holders of obligations secured by the Deed of Trust, including the notes, with significant remedies, including a foreclosure and sale of all or part of the Collateral. However, the rights of the Collateral Agent to exercise significant remedies (such as foreclosure) are, subject to certain exceptions, generally limited to a payment default, bankruptcy of us or the acceleration of the indebtedness.

Proceeds from any sale of the Collateral upon a foreclosure may be insufficient to repay the notes in full.

We cannot assure you that the net proceeds from a sale of the Collateral securing the notes would be sufficient to repay all of the notes following a foreclosure upon the Collateral or a liquidation of our assets.

The value of the Collateral and the amount to be received upon a sale of the Collateral will depend upon many factors including, among others, the condition of the Collateral, the ability to sell the Collateral in an orderly sale, the condition of the national and local economies, the availability of buyers and similar factors. The book value of the Collateral should not be relied on as a measure of realizable value for these assets. By their nature, portions of the Collateral may be illiquid and may have no readily ascertainable market value. In addition, a significant portion of the Collateral includes assets that may only be usable, and thus retain value, as part of our existing business operations. Accordingly, any sale of the Collateral separate from the sale of our business operations may not be feasible or of significant value.

Additionally, applicable law requires that every aspect of any foreclosure or other disposition of Collateral be “commercially reasonable.” If a court were to determine that any aspect of the Collateral Agent’s exercise of remedies was not commercially reasonable, the ability of the Collateral Agent and the holders of the notes to recover the difference between the amount realized through such exercise of remedies and the amount owed on the notes may be adversely affected and, in the worst case, the holders of the notes could lose all claims for such deficiency amount.

 

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FORWARD-LOOKING STATEMENTS

This prospectus, including the attached Interim Financial Statements and Annual Financial Statements, and other presentations made by us contain “forward-looking statements” within the meaning of Section 21E of the Exchange Act and Section 27A of the Securities Act, which are subject to risks and uncertainties. All statements, other than statements of historical facts, that are included in this prospectus, including the incorporated documents, 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,” “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 “Risk Factors” in this prospectus and the discussions under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this prospectus and the following important factors, among others, that could cause our actual results to differ materially from those projected in such forward-looking statements:

 

•

legislation, governmental policies and orders, and regulatory actions, including those of the U.S. Congress, the President of the U.S., the Texas Legislature, the Governor of Texas, the FERC, the PUCT, ERCOT, NERC, the Texas RE, the U.S. Department of Energy, the EPA, and the TCEQ, and including with respect to:

 

•

authorized rate of return;

 

•

permitted capital structure;

 

•

industry, market and rate structure;

 

•

rates and recovery of investments;

 

•

approvals of applications;

 

•

acquisition and disposal of assets and facilities;

 

•

ownership, operation and construction of assets and facilities;

 

•

changes in tax laws and policies; and

 

•

changes in and compliance with regulatory requirements, including environmental, sourcing/supply chain, reliability and safety laws and policies;

 

•

legal and administrative proceedings and settlements, including the exercise of equitable powers by courts;

 

•

weather conditions and other natural phenomena, including severe weather events, natural disasters or wildfires;

 

•

cyber-attacks on us or our third-party vendors;

 

•

changes in expected ERCOT and service territory growth;

 

•

changes in, or cancellations of, anticipated projects, including customer requested interconnection projects;

 

•

physical attacks on our system, acts of sabotage, wars, terrorist activities, wildfires, fires, explosions, natural disasters, hazards customary to the industry, or other emergency events;

 

•

our ability to obtain adequate insurance on reasonable terms and the possibility that we may not have adequate insurance to cover all losses incurred by us or third-party liabilities;

 

•

adverse actions by credit rating agencies;

 

•

health epidemics and pandemics, including their impact on our business and the economy in general;

 

•

interrupted or degraded service on key technology platforms, facilities failures, or equipment interruptions;

 

•

economic conditions, including the impact of a recessionary environment, inflation, foreign policy, and global trade restrictions;

 

•

supply chain disruptions, including as a result of tariffs, global trade disruptions, competition for goods and services, and service provider availability;

 

•

unanticipated changes in electricity demand in ERCOT or our service territory;

 

•

ERCOT grid needs and ERCOT market conditions, including insufficient electricity generation within the ERCOT market or disruptions at power generation facilities that supply power within the ERCOT market;

 

•

changes in business strategy, development plans or vendor relationships;

 

•

changes in interest rates, foreign currency exchange rates, or rates of inflation;

 

•

significant changes in operating expenses, liquidity needs and/or capital expenditures;

 

•

inability of various counterparties to meet their financial and other obligations to us, including failure of counterparties to timely perform under agreements;

 

•

general industry and ERCOT trends;

 

•

significant decreases in demand or consumption of electricity delivered by us, including as a result of increased consumer use of third-party DERs or other technologies;

 

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•

changes in technology used by and services offered by us;

 

•

changes in employee and contractor labor availability and cost;

 

•

significant changes in our relationship with our employees, and the potential adverse effects if labor disputes or grievances were to occur;

 

•

changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB, and future funding requirements related thereto;

 

•

significant changes in accounting policies or critical accounting estimates material to us;

 

•

commercial bank and financial market conditions, macroeconomic conditions, access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds and the potential impact of any disruptions in U.S. or foreign capital and credit markets;

 

•

financial market volatility and the impact of volatile financial markets on investments, including investments held by our pension and OPEB plans;

 

•

circumstances which may contribute to future impairment of goodwill, intangible or other long-lived assets;

 

•

our adoption and deployment of artificial intelligence;

 

•

financial and other restrictions under our debt agreements;

 

•

our ability to generate sufficient cash flow to make interest payments on our debt instruments; and

 

•

our ability to effectively execute our operational and financing strategy.

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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INDUSTRY AND MARKET INFORMATION

The industry and market data and other statistical information used throughout this prospectus are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including certain data published by ERCOT. We did not commission any of these publications or reports. Some data is also based on our good faith estimates, which are derived from our review of internal surveys, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While we believe that each of these studies and publications is reliable, we have not independently verified such data and we make no representation as to the accuracy of such information. Forecasts are particularly likely to be inaccurate, especially over long periods of time, and we do not know what assumptions regarding general economic growth are used in preparing the forecasts included in this prospectus. Similarly, while we believe that our internal and external research is reliable, it has not been verified by any independent sources and we make no assurances that the predictions contained therein are accurate.

 

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the exchange notes pursuant to the exchange offers. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive in exchange a like principal amount of outstanding notes, the terms of which are identical in all material respects to the exchange notes, except that the exchange notes will be registered under the Securities Act and do not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement applicable to such outstanding notes. The outstanding notes surrendered in exchange for the exchange notes will be retired and cancelled and cannot be reissued. Accordingly, the issuance of the exchange notes will not result in any change in our capitalization.

 

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CONSOLIDATED CAPITALIZATION AND SHORT-TERM DEBT OF ONCOR AND SUBSIDIARIES

The following table summarizes our consolidated capitalization and short-term debt as of September 30, 2025. This table should be read in conjunction with the more detailed information included under the headings “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Interim Financial Statements and Annual Financial Statements and related notes included herein.

 

		At September 30, 2025
		Amount				Percent
		(millions of dollars, except percentages)
Capitalization (a):
Long-term debt, noncurrent (b)(c)		$	17,958				50.4	%
Membership interests			17,671				49.6
Total capitalization		$	35,629				100.0	%
Short-term debt:
Short-term debt		$	—
Long-term debt, current			—
Total short-term debt		$	—

(a)	For purposes of reporting to the PUCT, the regulatory capitalization ratio at September 30, 2025, was 56.0% debt to 44.0% equity.

(b)

This amount reflects a $61 million remeasurement adjustment at September 30, 2025 on our euro-denominated notes, a $(2) million remeasurement adjustment at September 30, 2025 on our Canadian dollar-denominated notes and the net effects of $(184) million unamortized discount, premium and debt issuance costs related to our outstanding long-term debt securities as of September 30, 2025.

(c)	For more information regarding our long-term debt activity subsequent to September 30, 2025, see “Summary—Recent Developments” in this prospectus.

 

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OUR BUSINESS AND PROPERTIES

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 4.0 million homes and businesses and operating more than 144,000 circuit miles of transmission and distribution lines at December 31, 2024, all with a focus on safety, reliability, and affordability.

We provide:

 

•

wholesale transmission services to our electricity distribution business, as well as to non-affiliated electricity distribution companies, electric cooperatives and municipally-owned utilities, and

 

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distribution services, consisting of retail delivery services to REPs that sell electricity to end-use customers, as well as wholesale delivery services to electric cooperatives and municipally-owned utilities.

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.

PUCT rules allow for interim rate adjustments known as capital trackers that allow utilities to recover, subject to reconciliation, the cost of certain investments before a comprehensive base rate review. Under capital tracker rules, each year we may file 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 filing are ultimately subject to prudence review by the PUCT in the next base rate review after such assets are put into service. In June 2025, HB 5247 was signed into law and became effective. The bill establishes the UTM, which allows qualifying electric utilities to apply for interim rate adjustments once annually through 2035 for cost recovery of certain transmission and distribution capital expenditures, as an alternative to semi-annual (or less frequent) DCRF and TCOS capital tracker filings. As a result of HB 5247 taking effect, we have begun, and expect to continue, deferring to a regulatory asset, certain costs associated with UTM eligible capital investments placed into service since December 31, 2024, and recognizing corresponding amounts in revenues.

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 13 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.

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 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

 

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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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seven Disinterested Directors, who (i) shall be independent directors in all material respects under the rules of the NYSE in relation to Sempra or its subsidiaries and affiliated entities and any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings, and (ii) shall have no 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, currently or within the previous ten years;

 

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two members designated by Sempra (through Oncor Holdings);

 

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two members designated by Texas Transmission; and

 

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two current or former officers of Oncor (each, an Oncor Officer Director).

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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A majority of the Disinterested Directors of Oncor and the directors designated by Texas Transmission that are present and voting (of which at least one must be present and voting) must approve any annual or multi-year budget if the aggregate amount of capital expenditures or operation and maintenance expenditures in such budget is more than a 10% increase or decrease from the corresponding amounts of such expenditures in the budget for the preceding fiscal year or multi-year period, as applicable;

 

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Oncor may not pay any dividends or make any other distributions (except for contractual tax payments) if a majority of its Disinterested Directors or either of the two directors appointed by Texas Transmission determines that it is in the best interests of Oncor to retain such amounts to meet expected future requirements;

 

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At all times, Oncor will remain in compliance with the debt-to-equity ratio established by the PUCT from time to time for ratemaking purposes, and Oncor will not pay dividends or other distributions (except for contractual tax payments) if such payment would cause its debt-to-equity ratio to exceed the debt-to-equity ratio approved by the PUCT;

 

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If the credit rating on Oncor’s senior secured debt by any of the three major rating agencies falls below BBB (or the equivalent), Oncor will suspend dividends and other distributions (except for contractual tax payments), unless otherwise allowed by the PUCT;

 

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Without the prior approval of the PUCT, neither Sempra nor any of its affiliates (excluding Oncor) will incur, guaranty or pledge assets in respect of any indebtedness that is dependent on the revenues of Oncor in more than a proportionate degree than the other revenues of Sempra or on the membership interests of Oncor, and there will be no debt at STH or STIH at any time following Sempra’s indirect acquisition of Oncor Holdings;

 

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Neither Oncor nor Oncor Holdings will lend money to, borrow money from, or share credit facilities with, Sempra or any of its affiliates (other than Oncor subsidiaries), or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings; and

 

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There must be maintained certain “separateness measures” that reinforce the legal and financial separation of Oncor from its owners, including a requirement that dealings between Oncor, Oncor Holdings and their subsidiaries with Sempra, any of Sempra’s other affiliates or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings, must be on an arm’s-length basis, limitations on affiliate transactions, separate recordkeeping requirements and a prohibition on Sempra or its affiliates or any entity with a direct or indirect ownership interest in Oncor or Oncor Holdings pledging Oncor assets or membership interests for any entity other than Oncor.

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 recorded its historical peak hourly demand of 85,508 MW in August 2023. ERCOT has been experiencing significant growth in recent years, and ERCOT studies project growth to continue. The Texas Legislature, the PUCT and ERCOT have taken, and are expected to continue to implement, measures to address anticipated ERCOT growth forecasts.

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, supporting 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 organic growth strategies include 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. Our five-year capital plan reflects significant expected investments and growth. We have implemented an initiative to identify and address projected company needs resulting from the anticipated growth, including people needs, operational changes, supply chain initiatives, and process improvements. We are focused on continuing to expand our processes, workforce, and supply chain to meet that anticipated growth. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources” for more information on our historical and projected capital expenditures.

Keeping rates as low as possible 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.

We also believe there are opportunities for growth arising from customer efforts to decrease their respective carbon footprints through electrification efforts in the ERCOT market. Increased electrification efforts in the ERCOT market, particularly through oil and gas producers electrifying their operations and continued adoption of electric vehicles, could

 

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result in further increased demand within the ERCOT system. In addition, we believe demand in the ERCOT market could be significantly increased as a result of large load customers utilizing growing computing power needs related to cryptocurrency mining, AI technology, data storage and other technological needs and advances. 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. Legislation and regulation to combat climate change could also have an impact on operations and demand in the ERCOT market that require additional capital investments by us or impact electricity volumes delivered. 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 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, 2024, our transmission system included:

 

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18,324 circuit miles of transmission lines:

 

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7,577 circuit miles of 345kV transmission lines, and

 

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10,747 circuit miles of 138kV and 69kV transmission lines,

 

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interconnection to 192 generation facilities totaling 58,597 MW directly connected to our transmission system, and

 

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a total of 1,288 transmission and distribution substations.

At December 31, 2024, our transmission facilities had the following connections to other transmission grids in Texas:

 

		Number of Interconnected Lines
Grid Connections		345kV				138kV				69kV
American Electric Power Company, Inc. (a)			4				5				11
Brazos Electric Power Cooperative, Inc.			4				115				27
CenterPoint Energy Inc.			3				—				—
East Texas Electric Coop			1				14				1
Lone Star Transmission			3				—				—
Lower Colorado River Authority			6				29				2
Rayburn Country Electric Cooperative, Inc.			1				49				2
Texas Municipal Power Agency			7				6				—
Texas New Mexico Power			2				19				14
Other small systems operating wholly within Texas			14				20				6

(a)	One of the 345kV lines is an asynchronous high-voltage direct current connection with the Southwest Power Pool.

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 3,757 distribution feeders at December 31, 2024.

 

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At December 31, 2024, our distribution system included:

 

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125,975 circuit miles of distribution lines:

 

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90,313 circuit miles of overhead lines, and

 

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35,662 circuit miles of underground lines,

 

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4,046,000 approximate number of points of delivery, an increase of approximately 77,000 over the number of points of delivery at December 31, 2023, and

 

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1.95% average growth per year over the past five years in the number of distribution system points of delivery we serve, excluding lighting sites.

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 large commercial and industrial 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.

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 “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 September 30, 2025 and December 31, 2024, 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 22%, respectively, of our total operating revenues for the nine months ended September 30, 2025, 25% and 23%, respectively, of our total operating revenues for the year ended December 31, 2024, 25% and 23%, respectively, of our total operating revenues for the year ended December 31, 2023 and 26% and 24%, respectively, of our total operating revenues for the year ended December 31, 2022. 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 and virtual power plants and other technologies may increasingly compete with our traditional transmission and distribution infrastructure for meeting customers’ electricity needs. See “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, including by limiting future infrastructure investments and reducing our ability to timely recover the cost of our investment in, and earn a reasonable return on, our electricity delivery facilities.”

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.

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 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.

 

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As a regulated utility, our business is subject to extensive governmental regulations and compliance obligations, which could greatly impact our business. See “Risk Factors—Risks Related to Regulatory and Legislative Matters” as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Notes 2 and 6 to Interim Financial Statements and Notes 2 and 7 to Annual Financial Statements for a discussion of certain regulatory matters and commitments and the material effects of compliance with regulations on our business.

Investing in Infrastructure — In 2024, we invested approximately $4.7 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 “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 our facilities are presently in material compliance with applicable state and federal requirements relating to water discharges. 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, and believe we are currently in material compliance with these rules.

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. We are in material compliance with applicable solid and hazardous waste regulations.

Our capital expenditures for environmental matters totaled $76 million in 2024 and are expected to total approximately $85 million in 2025.

Human Capital Management — At December 31, 2024, we had 5,094 employees, including 836 employees covered under a collective bargaining agreement that expires in October 2026. As of December 31, 2024, the average length of service among all employees was 12.1 years, and over 99% of our employees were employed on a full-time basis. For the year ended December 31, 2024, we experienced an annual employee turnover rate of approximately 4.8%, including approximately 1.8% that was attributable to retirements. Our employee data excludes interns, and we had 73 interns serving in full-time or part-time internships at December 31, 2024.

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 was a significant focus of our human capital management efforts in 2024 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 2024, 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 developing our existing talent through upskilling 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.

 

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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:

 

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Safety — Safety is a key priority of the company and our human capital management strategy. Employees are regularly educated and trained on safety issues and receive regular safety communications, particularly in field locations. We have established an annual safety plan, which outlines our yearly safety programs and initiatives, and we also host an annual two-day safety conference for our field employees that highlights our safety priorities, initiatives, and expectations. Our safety procedures are continually improving and adapting to the ever-changing events that our workforce encounters. Employees are encouraged to propose improvements to our safety procedures and are recognized for their innovations and contributions to safety improvements, including through annual safety excellence awards given to individuals and teams for projects or initiatives that yield positive impacts to safety performance, either locally or companywide. In 2024, we hosted 12 celebration events honoring employees for their heroic and life-saving efforts utilizing skills and knowledge learned through on-the-job first aid and CPR training programs. We also regularly track our safety performance and benchmark it against industry peers, and achievement of significant safety milestones are recognized and celebrated. In addition, a safety performance metric is included in our annual and long-term incentive programs to further promote safety among employees.

 

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Ethical Conduct — Ethical conduct is a core value of the company, and every employee is required to complete code of conduct training upon joining Oncor and annually thereafter. We also maintain an ethics and compliance helpline monitored by an independent, third-party service, where any suspected unethical behavior or policy violations may be anonymously reported at any time. Our code of conduct compliance committee meets quarterly to review employee code of conduct compliance-related matters, and the company’s code of conduct compliance program and activities are reviewed with the audit committee of our board of directors (the Audit Committee) on at least an annual basis.

 

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Collaboration and Innovation — Our company-wide “One Oncor” initiative emphasizes cross-functional collaboration, particularly to spur innovation. An innovation and improvement council, made up of management-level employees, focuses on enhancing innovation and continuous improvement throughout the company. This council annually recognizes employee teams for their contributions to innovation and improvement through our annual spirit of innovation awards. We have also instituted an innovation and continuous improvement initiative and developed a framework based on Lean Six Sigma that enables and encourages employees to identify and execute improvement opportunities to our services, business processes, and systems, including an annual internal innovation week campaign. In addition, we offer various training opportunities to employees to obtain Lean Six Sigma certifications, develop process improvement skills, and encourage innovation. We also maintain a portal for all employees to submit innovation and improvement ideas and success stories.

 

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Inclusion & Belonging — We are committed to creating a workplace culture of belonging, empathy and mutual respect. Our officer-level steering committee for inclusion and belonging has instituted and supported various initiatives to promote this effort across the company, such as Oncor’s eight employee resource groups (ERGs), which are open to all employees to join. These ERGs focus on creating an inclusive environment through cultural awareness activities and events, networking opportunities, and community volunteerism. ERG participation continues to grow across the company, with approximately 22% of our employees participating in at least one ERG as of December 31, 2024. These and other strategies help foster a welcoming and inclusive workplace and support our commitment to developing and maintaining a workforce that reflects the customers and communities we serve.

 

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Healthy Lifestyles — We have established various health and wellness initiatives to encourage employees to adopt healthy living habits, including an incentive program that promotes exercise, healthy eating, and healthy lifestyles. Our health and wellness programs focus on physical, financial, and mental health, and we offer employees various resources and programming to enhance their overall well-being, including an employee assistance program that offers mental and behavioral health resources. We also maintain programs that fund Oncor employee participation in eligible community non-profit fitness events, including community non-profit fitness events across our service territory.

 

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Community Involvement — We coordinate various year-round community initiatives, partner with many non-profit organizations, and encourage employee volunteerism, including grants supporting eligible non-profits for which employees provide volunteer hours. We also host a companywide Oncor Cares Week during our annual employee giving campaign. In addition, we have established 19 Oncor Cares Community Councils across our service territory, where employees identify local organizations to support and coordinate volunteer opportunities and fundraisers to benefit those nonprofits and causes. We also maintain a 501(c)(3) private foundation, the Oncor Cares Foundation, to help expand our charitable giving and support for the many communities where we work and live.

 

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Employee Engagement — How engaged our workforce is and how committed our employees are to their work and the company are important to Oncor. We recognize that the more engaged employees are, the more productive they are and the more likely they are to remain with the company. As a result of our annual company-wide employee engagement survey, we continued to initiate various efforts in 2024 to enhance employee engagement at both the local and corporate levels, including manager and supervisor trainings on the survey results. We conducted our annual company-wide employee engagement survey in late 2024, which indicated an increase in the number of engaged employees versus prior year results, and are using the results of that survey to continue to develop and implement our employee engagement strategy.

 

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•

Talent Development — We maintain various leadership and workforce training and development programs to engage employees and promote continued professional growth. In addition, our board of directors annually reviews our talent management strategy, including talent development programs, and our executive officer talent pipeline. Our management also conducts regular ongoing succession planning with respect to other members of management and critical roles with a view towards maintaining a strong leadership pipeline. In addition, we are actively focused on attracting and developing employees at all levels to replace employees likely to retire in the next few years and to meet our anticipated growth needs.

 

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LEGAL PROCEEDINGS

For a discussion of material regulatory proceedings, see “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. For a discussion of certain of these proceedings, see Notes 2 and 6 to Interim Financial Statements and Notes 2 and 7 to Annual Financial Statements.

 

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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 nine months ended September 30, 2025 and 2024 and the fiscal years ended December 31, 2024 and 2023 should be read in conjunction with the Interim Financial Statements and the Annual Financial Statements and related notes to those statements as well as “Risk Factors” in this prospectus.

Our Annual Report on Form 10-K for the year ended December 31, 2023 includes a discussion and analysis of our financial condition and results of operations for the year ended December 31, 2022 in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

All dollar and foreign currency amounts in the following discussion 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 4.0 million homes and businesses as of December 31, 2024, with a focus on safety, reliability, and affordability. Our transmission and distribution rates are regulated by the PUCT and certain cities, and in certain limited instances, by the FERC. We are not a seller of electricity, nor do we purchase electricity for resale. For more information on our business, see “Our Business and Properties” in this prospectus.

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. We are managed as an integrated business; consequently, there is 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. 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 direct or indirect owner of Oncor or Oncor Holdings. For more information on the ring-fencing measures, see “Our Business and Properties—Ownership Structure and Ring-Fencing Measures.”

Significant Activities and Events

2025 Comprehensive Base Rate Review — On June 26, 2025, we filed a request for a comprehensive base rate review. See “—Regulation and Rates” below for a discussion of the current comprehensive base rate review.

UTM — On June 20, 2025, HB 5247 was signed into law and became effective. The bill establishes the UTM, which allows qualifying electric utilities to apply for interim rate adjustments once annually through 2035 for cost recovery of certain transmission and distribution capital expenditures, as an alternative to semi-annual (or less frequent) DCRF and TCOS capital tracker filings. As a result of HB 5247 taking effect, we have begun, and expect to continue, deferring to a regulatory asset, certain costs associated with UTM eligible capital investments placed into service since December 31, 2024, and recognizing corresponding amounts in revenues. See Notes 2 and 3 to Interim 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.

 

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Debt-Related Activities — See “Summary—Recent Developments,” “—Financial Condition—Liquidity and Capital Resources” below, Notes 4 and 5 to Interim Financial Statements, and Notes 5 and 6 to Annual 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 “Risk Factors” in this prospectus.

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 the final order in PUCT Docket No. 53601. 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 filed a request for a base rate review with the PUCT and the cities in our service territory that have retained original jurisdiction over rates, and that proceeding remains pending. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Regulation and Rates—Regulatory Matters” for a discussion of our current base rate review proceeding.

In between base rate reviews, we are eligible to file interim rate adjustment applications that help shorten the regulatory lag associated with recovery of transmission and distribution investments through regulated rates. These capital trackers allow us to recover, subject to reconciliation, the cost of certain transmission and distribution investments before the investments are considered for prudency in a base rate review. Under PUCT rules, we can file up to two interim DCRF rate adjustment applications in a year for certain distribution-related investments and up to two interim TCOS rate adjustment applications in a year to reflect changes in certain transmission-related investments. These interim rate applications are 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. In June 2025, HB 5247 was signed into law and became effective. The bill establishes the UTM, which allows qualifying electric utilities to apply for interim rate adjustments once annually through 2035 for cost recovery of certain transmission and distribution capital expenditures, as an alternative to semi-annual (or less frequent) DCRF and TCOS capital tracker filings. As a result of HB 5247 taking effect, we have begun, and expect to continue, deferring to a regulatory asset, certain costs associated with UTM eligible capital investments placed into service since December 31, 2024, and recognizing corresponding amounts in revenues. In addition, while these interim rate adjustments help reduce the effects of regulatory lag, they do not fully eliminate the regulatory lag between when a capital investment goes into service and when we begin to start recovering the costs of such investment in rates. Investments included in these capital trackers are also subject to prudence review by the PUCT in the next comprehensive base rate review following such adjustments, 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 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.

 

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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 for 2025-2029 disclosed herein are largely tied to expected continued ERCOT growth, particularly in our service territory and transmission footprint, 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 “Our 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, 2023 and 2022 was $26.6 billion, $23.1 billion and $20.7 billion, respectively. 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 2025 and beyond based on Oncor’s anticipated capital investments. See “—Financial Condition—Liquidity and Capital Resources—Available Liquidity and Liquidity Needs, Including Capital Expenditures—Capital Expenditures” for more information regarding our anticipated capital expenditures. The incremental investments included in any calculation of regulatory rate base since the test year in our last base rate review are subject to PUCT review in our next base rate review.

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 priorities could influence regulations, administrative actions and legislation. See “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 “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 “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 have a material adverse effect on our business, financial condition, results of operations and cash flow, 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. Adverse actions 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 Annual Financial Statements. See “Risk Factors—Risks Related to Financial and Market Matters—Adverse actions with respect to our credit

 

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ratings or ratings outlook could negatively affect our cost of debt and our ability to access capital,” and “Risk Factors—Risks Related to Financial and Market Matters—In the future, we could have capital needs that 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. The PUCT-approved cost of debt of 4.39% in our most recently completed comprehensive base rate review (PUCT Docket No. 53601), which was based on a 2021 test year, is reflected in our current base rates and is lower than our actual average cost of debt for the 2024 fiscal year. In 2024, we saw increased borrowing costs due primarily to increases in debt outstanding and to increases in general interest rates. We do not anticipate a change in our PUCT-approved cost of debt prior to a subsequent base rate review proceeding.

CRITICAL ACCOUNTING ESTIMATES

Our significant accounting policies are discussed in Note 1 to Interim Financial Statements and Note 1 to Annual 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 GAAP related to the effect of certain types of regulation. Regulatory assets and liabilities represent probable future revenues that will be recovered from or refunded 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 Interim Financial Statements and Note 2 to Annual 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 2024.

 

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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 Annual Financial Statements for additional information.

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 on 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, 2024, 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 2024.

Goodwill totaling $4.740 billion was reported on our balance sheet at each of September 30, 2025, December 31, 2024 and December 31, 2023.

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 8 to Interim Financial Statements and Note 9 to Annual 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 decreased $49 million during 2024. 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 8 to Interim Financial Statements and Note 9 to Annual Financial Statements regarding other disclosures related to obligations of our pension plans and OPEB plans.

RESULTS OF OPERATIONS

Operating Data

 

		Twelve Months Ended September 30,								Years Ended December 31,
		2025				2024				2024				2023				2022
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (non-storm)			82.2				71.1				74.7				70.0				75.0
System Average Interruption Frequency Index (SAIFI) (non-storm)			1.2				1.0				1.1				1.0				1.2
Customer Average Interruption Duration Index (CAIDI) (non-storm)			70.8				70.4				69.8				70.7				63.5
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of active meters)			4,100				4,027				4,046				3,969				3,896
		Nine Months Ended September 30,								Years Ended December 31,
		2025				2024				2024				2023				2022
Operating statistics:
Electric energy volumes (gigawatt-hours):
Residential			37,567				37,113				46,444				47,112				49,648
Commercial, industrial, small business and other			94,426				86,751				116,247				109,365				99,612
Total electric energy volumes			131,993				123,864				162,691				156,477				149,260
Residential system weighted weather data (b):
Cooling degree days			1,710				1,884				2,071				2,268				2,204
Heating degree days			589				459				610				608				971

(a)

SAIDI is the average number of minutes electric service is interrupted per consumer in a twelve-month period. SAIFI is the average number of electric service interruptions per consumer in a twelve-month period. CAIDI is the average duration in minutes per electric service interruption in a twelve-month period. In each case, our non-storm reliability performance reflects electric service interruptions of one minute or more per customer. Each of these results excludes outages during significant storm events.

(b)

Degree days are measures of how warm or cold it is throughout our service territory. A degree day compares the average of the hourly outdoor temperatures during each day to a 65° Fahrenheit standard temperature. The more extreme the outside temperature, the higher the number of degree days. A high number of degree days generally results in higher levels of energy use for space cooling or heating.

 

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		Nine Months Ended September 30,								Years Ended December 31,
		2025				2024				2024				2023				2022
Operating revenues:
Revenues contributing to earnings:
Revenues from contracts with customers
Distribution base revenues (a)
Residential (a)		$	1,270			$	1,166			$	1,477			$	1,334			$	1,215
Large commercial & industrial (b)			1,042				960				1,283				1,162				1,074
Other (c)			96				93				126				132				158
Total distribution base revenues			2,408				2,219				2,886				2,628				2,447
Transmission base revenues (TCOS revenues)
Billed to third-party wholesale customers			812				787				1,050				959				944
Billed to REPs serving Oncor distribution customers, through TCRF			450				431				574				539				528
Total TCOS revenues			1,262				1,218				1,624				1,498				1,472
Other miscellaneous revenues			72				73				112				109				112
Total revenues from contracts with customers			3,742				3,510				4,622				4,235				4,031
Other regulated revenues
SRP revenues			111				—				—				—				—
UTM revenues (d)			55				—				—				—				—
Total other regulated revenues			166				—				—				—				—
Total revenues contributing to earnings			3,908				3,510				4,622				4,235				4,031
Revenues collected for pass-through expenses:
TCRF – third-party wholesale transmission service			1,094				1,053				1,394				1,291				1,162
EECRF and other revenues			45				47				66				60				50
Total revenues collected for pass-through expenses			1,139				1,100				1,460				1,351				1,212
Total operating revenues		$	5,047			$	4,610			$	6,082			$	5,586			$	5,243

(a)	Distribution base revenues from residential customers are generally based on actual monthly consumption (kWh).

(b)	Depending on size and annual load factor, distribution base revenues from large commercial & industrial customers 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 eleven months.

(c)	Includes distribution base revenues from small business customers whose billing is generally based on actual monthly consumption (kWh), lighting sites and other miscellaneous distribution base revenues.

(d)	Includes revenues recognized for recoverable costs, associated with UTM eligible transmission and distribution capital investments put into service after December 31, 2024, including depreciation expenses, carrying costs on unrecovered balances and related taxes.

 

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Financial Results — Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

Total operating revenues increased $437 million, or 9%, to $5.047 billion during the nine months ended September 30, 2025. Revenues are generally recognized pursuant to tariffs approved by the PUCT or authorized by statute.

Revenues contributing to earnings increased $398 million to $3.908 billion during the nine months ended September 30, 2025. Revenues contributing to earnings consist of revenues from contracts with customers recognized under ASC 606 and other regulated revenues recognized under ASC 980. The net increase reflected the following components:

 

•

An Increase in Distribution Base Revenues — Distribution base revenues increased $189 million to $2.408 billion during the nine months ended September 30, 2025. The increase in distribution base revenues primarily reflects:

 

•

$156 million increase due to updated interim DCRF rates implemented to reflect increases in invested capital, and

 

•

$34 million increase due to customer growth.

Distribution base rates are set periodically in a comprehensive base rate review docket. The base rates implementing the final order in PUCT Docket No. 53601 went into effect in May 2023.

PUCT rules also allow utilities to file, under certain circumstances, up to two interim DCRF rate adjustment applications per year between comprehensive base rate reviews to recover certain distribution investments and certain other related costs.

See the Interim DCRF Filings Table below for a listing of interim DCRF rate adjustment applications impacting revenues for the periods presented herein. As we currently intend to recover costs related to distribution capital investments placed into service since December 31, 2024 through the UTM, we do not intend to file additional interim DCRF rate adjustment applications this year. See Note 2 to Interim Financial Statements for more information on the SRP and the UTM.

Interim DCRF Filings Table

 

PUCT Docket No.		Investment Through		Filed		Effective		Annual Revenue Impact (a)
57707		December 2024 (b)		February 2025		May 2025		$	106
56963		June 2024 (c)		August 2024		December 2024		$	90
56306		December 2023 (d)		March 2024		July 2024		$	81
55525		June 2023 (e)		September 2023		December 2023		$	53
55190		December 2022 (f)		June 2023		September 2023		$	153
51996		December 2020 (g)		April 2021		September 2021		$	88

(a)	Annual revenue impact represents the incremental annual revenue impact, after taking into account revenue effects of customer growth and prior applicable DCRF rate adjustments.

(b)	Reflects distribution-related capital investments generally put into service during the period from July 1, 2024 through December 31, 2024.

(c)	Reflects distribution-related capital investments generally put into service during the period from January 1, 2024 through June 30, 2024.

(d)	Reflects distribution-related capital investments generally put into service during the period from July 1, 2023 through December 31, 2023.

(e)	Reflects distribution-related capital investments generally put into service during the period from January 1, 2023 through June 30, 2023.

(f)	Reflects distribution-related capital investments generally put into service during the period from January 1, 2022 through December 31, 2022.

(g)	Reflects distribution-related capital investments generally put into service during the period from January 1, 2020 through December 31, 2020.

 

•

An Increase in Transmission Base Revenues — TCOS revenues increased $44 million to $1.262 billion during the nine months ended September 30, 2025. The increase in TCOS revenues primarily reflects:

 

•

$57 million increase due to updated interim TCOS rates implemented to reflect increases in invested capital,

partially offset by

 

50

•

$13 million decrease due to lower ERCOT transmission billing units for 2025 versus 2024. Transmission billing units are updated annually to reflect certain changes in average ERCOT-wide peak electricity demand during applicable periods.

TCOS revenues are collected from load serving entities benefiting from our transmission system, and the rates charged those customers are adjusted based on the transmission billing units and other adjustments approved by the PUCT.

PUCT rules also allow utilities to file, under certain circumstances, up to two interim TCOS rate adjustment applications per year between comprehensive base rate reviews to recover transmission investments and certain other related costs.

See the Interim TCOS Filings Table below for a listing of interim TCOS rate adjustment applications impacting revenues for the periods presented herein. We did not file an interim TCOS rate adjustment application in 2024, as a result of the increases in annual ERCOT transmission billing units applicable in 2024. As we currently intend to recover costs related to transmission capital investments placed into service since December 31, 2024 through the UTM, we do not intend to file additional interim TCOS rate adjustment applications this year.

Interim TCOS Filings Table

 

PUCT Docket No.		Investment Through		Filed		Effective		Annual Revenue Impact (a)				Third-Party Wholesale Transmission Revenue Impact				Included in TCRF Revenue Impact
57610		December 2024 (b)		January 2025		March 2025		$	165			$	106			$	59
55282		June 2023 (c)		July 2023		September 2023		$	42			$	27			$	15
53145		December 2021 (d)		January 2022		March 2022		$	27			$	17			$	10

(a)	Annual revenue impact represents the incremental annual revenue impact, after taking into account revenue effects of prior applicable rate adjustments and net changes in billing units.

(b)	Reflects transmission-related capital investments generally put into service during the period from July 1, 2023 through December 31, 2024.

(c)	Reflects transmission-related capital investments generally put into service during the period from January 1, 2023 through June 30, 2023.

(d)	Reflects transmission-related capital investments generally put into service during the period from July 1, 2021 through December 31, 2021.

 

•

A Decrease in Other Miscellaneous Revenues — Other miscellaneous revenues decreased $1 million to $72 million during the nine months ended September 30, 2025. The decrease in other miscellaneous revenues was primarily due to lower mutual assistance related services, partially offset by higher revenues from discretionary service.

 

•

An Increase in Other Regulated Revenues — Other regulated revenues totaled $166 million during the nine months ended September 30, 2025, which primarily reflect:

 

•

$111 million in revenues recognized related to the SRP, and

 

•

$55 million in revenues recognized pursuant to the UTM, associated with recoverable costs incurred in the nine months ended September 30, 2025, related to transmission and distribution capital investments placed into service after December 31, 2024.

Revenues collected for pass-through expenses increased $39 million to $1.139 billion during the nine months ended September 30, 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:

 

•

An Increase in TCRF – third-party wholesale transmission service (TCRF Third-Party) — TCRF Third-Party revenues increased $41 million to $1.094 billion during the nine months ended September 30, 2025 due to higher third-party wholesale transmission service provider billings.

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. The increase in our TCRF Third-Party revenue recognition reflects the pass-through effect of changes in third-party wholesale transmission service expense.

 

51

The UTM allows utilities to file once a year to adjust the TCRF to pass through the wholesale transmission cost charges billed to us by transmission service providers.

 

•

A Decrease in EECRF and Other Revenues — EECRF and other revenues decreased $2 million to $45 million during the nine months ended September 30, 2025. The EECRF and other revenues were generally offset in operation and maintenance expense.

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 miscellaneous 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 mobile generation rider filing proceedings, and (ii) the rate case expense rider, which is a reconcilable rate designed to fully recover rate case expenses approved in our most recent comprehensive rate base review proceeding.

See the EECRF Filings Table below for a listing of EECRF filings impacting revenue in the periods presented.

EECRF Filings Table

 

PUCT Docket No.		Filed		EECRF Monthly Charge Effective Date		Monthly Charge per Residential Customer (a)				Program Costs				Performance Bonus (b)				(Over)/Under- Recovery and Other
58182		May 2025		March 2026		$	1.78			$	64			$	33			$	8
56682		May 2024		March 2025		$	1.36			$	55			$	17			$	—
55074		May 2023		March 2024		$	1.23			$	49			$	21			$	2
53671		May 2022		March 2023		$	1.23			$	52			$	28			$	3

(a)	Monthly charges are for a residential customer using an assumed 1,200 kWh.

(b)	Performance bonuses are recognized at the time of PUCT approval of the EECRF, not the effective date of the EECRF rider.

Wholesale transmission service expense increased $41 million to $1.094 billion during the nine months ended September 30, 2025 due to higher fees paid to third-party transmission entities. 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 $191 million to $1.123 billion during the nine months ended September 30, 2025. The increase was primarily due to $79 million in higher vegetation management expenses, $79 million in higher labor and contractor related costs, $17 million in higher insurance premium expenses, a $10 million sales tax refund recorded in the first quarter of 2024, and $2 million in higher costs related to materials and supplies. We expect to continue to experience higher operation and maintenance expenses, particularly related to labor and contractor costs.

The overall $191 million increase in operation and maintenance expense includes $108 million in incremental SRP operation expenses during the nine months ended September 30, 2025. We expect SRP related operation expenses to ultimately be recovered in rates. For more information on our SRP, see “—Regulation and Rates—SRP (PUCT Docket No. 56545)”.

Depreciation and amortization increased $90 million to $877 million during the nine months ended September 30, 2025. The increase was 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—Available Liquidity and Liquidity Needs, Including Capital Expenditures—Capital Expenditures” for more information on our 2025-2029 capital plan.

Provision in lieu of income taxes netted to $173 million (including a $1 million benefit related to non-operating income) during the nine months ended September 30, 2025 compared to $171 million (including an $1 million benefit related to non-operating income) during the nine months ended September 30, 2024.

The effective income tax rate was 17.4% and 17.6% for the nine months ended September 30, 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 U.S. Tax Cuts and Jobs Act of 2017, partially offset by the effects of the Texas margin tax.

 

52

Taxes other than amounts related to income taxes increased $12 million to $443 million during the nine months ended September 30, 2025. The increase was primarily due to $11 million in higher property tax and a $3 million increase in local franchise taxes payable by us to municipalities, partially offset by a $2 million decrease in payroll taxes. 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—Available Liquidity and Liquidity Needs, Including Capital Expenditures—Capital Expenditures” for more information on our 2025-2029 capital plan.

Other (income) and deductions – net was $16 million favorable for the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024. The variance was primarily due to $24 million in higher AFUDC – equity income, partially offset by $3 million in higher professional fees and a $2 million unfavorable change in the value of certain compensation plan rabbi trust assets, which is generally offset in compensation expense, $1 million in higher reconcilable employee retirement benefit expense, which is generally recoverable through operating revenues, and a $1 million gain on the sale of non-utility property recorded in 2024.

Interest expense and related charges increased $97 million to $578 million during the nine months ended September 30, 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. We anticipate interest expense and related charges to continue to increase, particularly due to increased borrowing needs in light of our capital expenditure plans and higher average interest rates on the borrowings. See “—Financial Condition—Liquidity and Capital Resources—Available Liquidity and Liquidity Needs, Including Capital Expenditures—Capital Expenditures” for more information on our 2025-2029 capital plan.

Net income increased $20 million to $820 million during the nine months ended September 30, 2025. The increase was driven by:

 

•

overall higher revenues primarily attributable to:

 

•

updated interim rates to reflect increases in invested capital,

 

•

an increase in other regulated revenues recognized related to the SRP and the establishment of the UTM, and

 

•

customer growth,

partially offset by

 

•

decreases in ERCOT transmission billing units,

partially offset by

 

•

higher operation and maintenance expense, and

 

•

higher interest expense and depreciation expense associated with increases in invested capital.

OTHER COMPREHENSIVE INCOME (LOSS)

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 outstanding 2035 notes and our outstanding 2055 notes and a $15 million ($12 million net of tax) net fair value loss was realized and recorded in other comprehensive (loss) income. The AOCI will be reclassified into net income as an increase in interest expense over the life of the outstanding 2035 notes and the outstanding 2055 notes respectively.

Beginning in April 2025, we entered into multiple interest rate swap transactions hedging the variability of benchmark bond rates in anticipation of future debt financings. All of those interest rate swaps were outstanding at September 30, 2025. In the nine months ended September 30, 2025, we recorded a $25 million ($21 million net of tax) net unrealized fair value loss on the interest rate swaps in other comprehensive (loss) income.

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 September 30, 2025, with losses reported in other comprehensive income or loss. There was approximately $6 million of the amounts expected to be recorded in AOCI at September 30, 2025 related to the interest rate swaps to be reclassified into net income as an increase to interest expense within the next 12 months.

 

53

Fair Value Hedges

In May 2024 and June 2025, we entered into multiple designated cross-currency swaps 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 designated cross-currency swaps 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 the nine months ended September 30, 2025, we recorded a $37 million net fair value gain of the cross-currency swaps. The amount attributable to excluded components in the nine-month period was a $46 million ($37 million net of tax) loss and was recorded in other comprehensive (loss) income in the nine months ended September 30, 2025.

Financial Results — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

Total operating revenues increased $496 million, or 9%, to $6.082 billion in 2024.

Revenues contributing to earnings increased $387 million to $4.622 billion in 2024. The net increase reflected the following components:

 

•

An Increase in Distribution Base Revenues — Distribution base revenues increased $258 million to $2.886 billion in 2024. The increase in distribution base revenues primarily reflects:

 

•

$203 million increase due to updated interim DCRF rates implemented to reflect increases in invested capital,

 

•

$46 million increase due to a net higher distribution-related revenue component in base rates that took effect May 2023, and

 

•

$45 million increase due to customer growth,

partially offset by

 

•

$39 million decrease due to lower customer consumption primarily attributable to milder weather when compared to the prior period.

 

•

An Increase in Transmission Base Revenues — TCOS revenues increased $126 million to $1.624 billion in 2024. The increase in TCOS revenues primarily reflects:

 

•

$135 million increase due to increases in transmission billing units as a result of certain increases in average ERCOT peak-demand, and

 

•

$9 million increase due to updated interim TCOS rates implemented in 2023 to reflect increases in invested capital,

partially offset by

 

•

$18 million in lower revenues primarily due to the effects of a lower transmission-related revenue component included in base rates implemented May 2023.

 

•

An Increase in Other Miscellaneous Revenues — Other miscellaneous revenues increased $3 million to $112 million in 2024. The increase in other miscellaneous revenues primarily reflects:

 

•

$7 million in higher revenues from discretionary services, including increased facilities studies related to connecting customer facilities to the electric grid that are billed at cost and provided in connection with our electricity delivery services pursuant to our tariffs,

partially offset by

 

•

$4 million in lower annual energy efficiency program performance bonus revenues approved in 2024 compared to 2023.

Revenues collected for pass-through expenses increased $109 million to $1.460 billion in 2024. The net increase reflected the following components:

 

•

An Increase in TCRF – third-party wholesale transmission service (TCRF Third-Party) — TCRF Third-Party revenues increased $103 million to $1.394 billion in 2024 due to higher third-party wholesale transmission service provider billings.

 

54

•

An Increase in EECRF and Other Revenues — EECRF and other revenues increased $6 million to $66 million in 2024. The increase was primarily due to higher mobile generation rider revenues to cover mobile generation lease expenses and operation and maintenance expenses and higher rate case expense rider revenues to cover deferred rate case expense amortization, partially offset by lower EECRF revenues to cover energy efficiency program expenses.

Wholesale transmission service expense increased $103 million to $1.394 billion in 2024. The increase was due to higher billings from third-party transmission service providers.

Operation and maintenance expense increased $143 million to $1.293 billion in 2024. The increase was primarily due to $50 million in higher labor and contractor related costs, $36 million in higher regulatory assets amortization, $33 million in higher insurance premium expenses, a $16 million increase in the accrual recovery amount for our self-insurance reserve as a result of base rates that went into effect May 2023 (which rates implemented a five-year regulatory asset amortization period for certain regulatory assets and an increased annual accrual recovery amount for our self-insurance reserve pursuant to the PUCT’s final order in our comprehensive base rate review), $16 million in higher vegetation management expenses and $3 million in higher costs related to materials and supplies, partially offset by a $10 million refund related to our sales tax audit settlement.

Depreciation and amortization increased $82 million to $1.060 billion in 2024. The increase was primarily attributable to ongoing investments in property, plant and equipment and higher depreciation and amortization rates as a result of implementing the final order in PUCT Docket No. 53601 in 2023.

Provision in lieu of income taxes netted to $206 million (including an $2 million benefit related to non-operating income) in 2024 compared to $177 million (including an $8 million benefit related to non-operating income) in 2023. The increase partially reflects the tax effects associated with the write-off of rate base disallowances in the first quarter of 2023.

The effective income tax rate was 17.5% and 17.0% for 2024 and 2023, 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 Federal Tax Cuts and Jobs Act of 2017, partially offset by the effects of the Texas margin tax. The prior year effective tax rate includes the effect of a refund in 2023 related to prior year amended federal income tax returns.

Taxes other than amounts related to income taxes increased $19 million to $571 million in 2024. The increase was primarily due to higher property taxes, higher payroll taxes and higher local franchise taxes payable by us to municipalities.

Other (income) and deductions—net was $32 million favorable in 2024 compared to 2023. The variance was primarily due to a $15 million favorable change in the value of certain compensation plan rabbi trust assets, which is generally offset in compensation expense, $13 million in lower reconcilable employee retirement benefit expense, which is generally recoverable through operating revenues, $10 million in higher AFUDC – equity income and $2 million in lower professional fees, partially offset by $8 million decrease in gains on sale of non-utility property.

Interest expense and related charges increased $117 million to $653 million in 2024. 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.

Write-off of rate base disallowances was recorded in the amount of $69 million in the first quarter of 2023, as a result of the final order issued by the PUCT in April 2023 in our comprehensive base rate review (PUCT Docket No. 53601), which excluded from rate base certain employee benefit and compensation related costs incurred through December 31, 2021. The write-off includes a $55 million ($43 million net of tax) write-off of disallowed capitalized property, plant and equipment reflected in operating expenses and a $14 million ($11 million net of tax) write-off of non-operating disallowances related to these disallowed employee benefit and compensation related costs.

Net income increased $104 million to $968 million in 2024. The increase was driven by:

 

•

overall higher revenues primarily attributable to:

 

•

updated interim rates to reflect increases in invested capital,

 

•

increases in transmission billing units,

 

•

customer growth, and

 

•

the base rates that went into effect May 2023,

partially offset by

 

•

lower customer consumption primarily attributable to milder weather when compared to the prior period, and

 

55

•

the write-off of rate base disallowances recorded in the first quarter of 2023,

partially offset by

 

•

higher interest expense and depreciation expense associated with increases in invested capital, and

 

•

higher operation and maintenance expense.

OTHER COMPREHENSIVE (LOSS) INCOME

Cash Flow Hedges

In the second quarter of 2024, we entered into interest rate hedge transactions hedging the variability of benchmark bond rates used to determine the interest rates on the anticipated issuance of 30-year senior secured notes. The hedges, which were designated as cash flow hedges, were terminated in June 2024 upon the issuance of $750 million aggregate principal amount of our 5.55% Senior Secured Notes due June 15, 2054, and a $17 million ($13 million net of tax) settlement loss was reported in other comprehensive income or loss.

In the fourth quarter of 2024, we entered into interest rate hedge transactions hedging the variability of benchmark bond rates used to determine the interest rates on the anticipated issuance of five-year senior secured notes. The hedges, which were designated as cash flow hedges, were terminated in November 2024 upon the issuance of $550 million aggregate principal amount of our initial 2029 notes, and a $1 million (approximately $1 million net of tax) settlement gain was reported in other comprehensive income or loss.

We previously entered into multiple interest rate hedge transactions hedging the variability of benchmark bond rates used to determine the interest rates on the then-anticipated issuances of senior secured notes in the past. All of these hedges had been terminated as of December 31, 2024, with losses reported in other comprehensive income or loss. There was approximately $4 million of the amount reported in accumulated other comprehensive loss at December 31, 2024 related to the interest rate hedges to be reclassified into net income as an increase to interest expense within the next 12 months.

Fair Value Hedges

In May 2024, we entered into designated cross-currency swaps that effectively converted our euro-denominated fixed-rate payment obligations under our 2031 Euro Notes with respect to principal and interest payments to U.S. dollar-denominated fixed-rate payment obligations. At December 31, 2024, we recorded a $21 million fair value loss of the cross-currency swaps. The amount attributable to excluded components was $3 million ($2 million net of tax) and was reported in other comprehensive income or loss at December 31, 2024.

Defined Benefit Pension Plans

During the first quarter of 2023, we reclassified $20 million related to certain employee retirement liabilities previously recorded in regulatory assets to other comprehensive income or loss, as a result of the final order in our comprehensive base rate review (PUCT Docket No. 53601) disallowing rate recovery of those costs.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows — Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024

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

 

		Nine Months Ended September 30,
		2025 compared to 2024
Change in self-insurance reserve, primarily storm related		$	172
Change in regulatory under/over recoveries – net			85
Higher interest accruals			48
Change in net income, adjusted for noncash items included in earnings			(8	)
Change in working capital accounts			(75	)
Higher contributions to pension plans and OPEB Plans			(102	)
Other			52
		$	172

 

56

Depreciation and amortization expense reported in operating activities in the condensed statements of consolidated cash flows was $125 million and $127 million more than the amounts reported in the condensed statements of consolidated income for the nine months ended September 30, 2025 and 2024, respectively. The differences are primarily due to certain regulatory asset amortization being reported as operation and maintenance expense in the Condensed 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:

 

		Nine Months Ended September 30,
		2025 compared to 2024
Higher capital contributions from members		$	1,137
Higher net borrowings, excluding payment for senior secured notes extinguishment			774
Higher distributions to members			(197	)
Payment for senior secured notes extinguishment			(441	)
		$	1,273

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

 

		Nine Months Ended September 30,
		2025 compared to 2024
Higher capital expenditures		$	(1,233	)
Sales tax audit settlement refund in 2024, classified as investing activity			(56	)
Other			7
		$	(1,282	)

Long-Term Debt-Related Activities 2025

At September 30, 2025, our long-term debt totaled an aggregate principal amount of $18.142 billion, an increase of $2.749 billion over the $15.393 billion aggregate principal amount of long-term debt outstanding at December 31, 2024. Long-term debt outstanding at September 30, 2025 consisted of U.S. dollar-denominated, euro-denominated and Canadian dollar-denominated fixed rate senior secured notes and variable rate unsecured debt borrowed under the $500M Credit Facility. See Note 5 to Interim 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 “—Material Debt Credit Rating, Financial, and Cross-Default Covenants” below.

Senior Secured Notes Issuances — The following table summarizes our issuances of senior secured notes during the nine months ended September 30, 2025:

 

Senior Secured Notes Issued		Issuance Dates				Principal Amounts Issued
4.65% Senior Notes due November 1, 2029			January 14, 2025			$	100
5.15% Senior Notes, Series H, due May 1, 2029			January 30, 2025				250
5.59% Senior Notes, Series I, due May 1, 2034			February 27, 2025				150
4.50% Senior Notes due March 20, 2027			March 20, 2025				500
5.35% Senior Notes due April 1, 2035			March 20, 2025				650
5.80% Senior Notes due April 1, 2055			March 20, 2025				650
3.625% Senior Notes due June 15, 2034 (a)			June 16, 2025				805
4.20% Senior Notes due October 1, 2035 (b)			September 26, 2025				361
Total senior secured notes issued during the nine months ended September 30, 2025						$	3,466

 

57

(a)

In June 2025, we issued the 2034 Euro Notes. 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 intended to mitigate foreign currency exchange risk associated with the interest and principal payments on the 2034 Euro Notes that are due in euros. In consideration of the effect of 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%.

(b)

On September 26, 2025, we issued the CAD Notes. 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 intended to mitigate foreign currency exchange rate risk associated with the interest and principal payments on the CAD Notes that are due in Canadian dollars. In consideration of the effect of 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%.

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 September 30, 2025, the amount of available bond credits was $3.329 billion and 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 $6.287 billion. See Note 5 to Interim 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 Series A Notes. We issued CP Notes under our CP Program to fund the repayment of the Series A 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. 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 September 30, 2025, the borrowing base for the AR Facility was $500 million, and there were no borrowings outstanding under the AR Facility.

The following table summarizes the activity under the AR Facility in the nine months ended September 30, 2025:

 

		Borrowing (Repayment) Amounts
Balance at December 31, 2024		$	—
Borrowing on January 30, 2025			300
Repayment on March 20, 2025			(300	)
Borrowing on May 29, 2025			210
Repayment on June 17, 2025			(210	)
Balance at September 30, 2025 (a)		$	—

(a)	On November 25, 2025, we borrowed $325 million aggregate principal amount under the AR Facility.

 

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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 5 to Interim Financial Statements for more information on the $500M Credit Facility.

There were $480 million in aggregate borrowings outstanding under the $500M Credit Facility at September 30, 2025 and December 31, 2024. The remaining borrowing capacity was $20 million at September 30, 2025.

$1B Credit Facility — On February 20, 2025, we entered into an unsecured revolving $1B Credit Facility. The $1B Credit Facility has a borrowing capacity of $1.0 billion and a maturity date of February 20, 2028. 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 5 to Interim Financial Statements for more information on the $1B Credit Facility.

At September 30, 2025, there were no borrowings under the $1B Credit Facility.

Term Loan Credit Agreement and Borrowing — On December 23, 2025, we entered into an unsecured $1.4 billion Term Loan Agreement. On December 26, 2025, we made our initial borrowing under the Term Loan Agreement in the amount of $925 million. For more information regarding the Term Loan Agreement, see “Summary—Recent Developments” in this prospectus.

Short-Term Debt-Related Activities in 2025

$2B Credit Facility — On February 20, 2025, we entered into an amended and restated unsecured revolving $2B Credit Facility. As amended and restated, our $2B Credit Facility has a borrowing capacity of $2.0 billion and a maturity date of February 20, 2030. 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. See Note 4 to Interim Financial Statements for additional information regarding the $2B Credit Facility.

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 September 30, 2025, we had no CP Notes outstanding, and as of 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.

See Note 4 to Interim Financial Statements for additional information regarding the short-term CP Program.

Cash Flows — Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

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

 

		Years Ended December 31,
		2024 compare to 2023
Change in net income, adjusted for noncash items included in earnings		$	256
Change in working capital accounts			66
Higher customer deposits			44
Lower payments for third-party wholesale transmission services			26
Change in over/under collected regulated revenues			14
Higher payments related to insurance premiums and related costs			(51	)
Higher pension plans and OPEB Plans contributions			(85	)
Change in self-insurance reserve, primarily storm related			(95	)
Other			12
		$	187

 

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Depreciation and amortization expenses reported in operating activities in the statements of consolidated cash flows were $173 million and $139 million more than the amounts reported in the statements of consolidated income in 2024 and 2023, respectively. The differences are 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 sources (uses) of cash related to financing activities:

 

		Years Ended December 31,
		2024 compare to 2023
Higher net borrowings		$	122
Higher contributions from members			759
Higher distributions to members			(201	)
		$	680

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

 

		Years Ended December 31,
		2024 compare to 2023
Higher capital expenditures		$	(859	)
Sales tax audit settlement refund classified as investing activity			56
Lower proceeds from disposal of assets and others			(6	)
		$	(809	)

Long-Term Debt-Related Activities in 2024

At December 31, 2024, our long-term debt excluding unamortized discount, premium and debt issuance costs, but including the remeasurement adjustment related to the 2031 Euro Notes, totaled an aggregate principal amount of $15.393 billion, an increase of $1.948 billion over the $13.445 billion aggregate principal amount of long-term debt excluding unamortized discount, premium and debt issuance costs outstanding at December 31, 2023.

Long-term debt outstanding at December 31, 2024 consisted of U.S. dollar-denominated and euro-denominated fixed rate senior secured notes and variable rate unsecured debt borrowed under the $500M Credit Facility. See Note 6 to Annual 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 “—Material Debt Credit Rating, Financial, and Cross-Default Covenants” below.

Senior Secured Notes Issuances — The following table summarizes our issuances of senior secured notes in 2024:

 

Senior Secured Notes Issued		Issuance Dates		Principal Amounts Issued
5.00% Senior Notes, Series F, due May 1, 2029 (a)		April 24, 2024		$	100
5.49% Senior Notes, Series G, due May 1, 2054 (a)		April 24, 2024			50
3.50% Euro Notes due May 15, 2031 (b)(c)		May 21, 2024			542
5.55% Senior Notes due June 15, 2054 (c)		June 21, 2024			750
4.65% Senior Notes due November 1, 2029 (c)		November 13, 2024			550
Total senior secured notes issued in 2024				$	1,992

(a)	Issued under a note purchase agreement entered into in March 2024 with the purchasers named therein.

(b)

On May 21, 2024, we issued the 2031 Euro Notes. Our euro-denominated fixed-rate payment obligations under the 2031 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 2031 Euro Notes that are due in euros. In consideration of the effect of cross-currency swaps, the U.S. dollar principal amount due on the 2031 Euro Notes at maturity will be $542 million and the all-in U.S. dollar fixed-rate coupon on the 2031 Euro Notes is 5.371%.

(c)	Issued under an existing indenture.

 

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Senior Secured Notes Repayment — In June 2024, we repaid in full at maturity the $500 million aggregate principal amount of our 2.75% Senior Secured Notes due June 1, 2024, plus accrued and unpaid interest on such notes.

AR Facility — At December 31, 2024, the borrowing base for the AR Facility was $500 million and no borrowings were outstanding under the AR Facility.

The following table summarizes the borrowings and repayments under our AR Facility in 2024:

 

		Borrowing (Repayment) Amounts
Balance at December 31, 2023		$	—
Borrowing on January 30, 2024			300
Borrowing on April 29, 2024			100
Repayment on May 21, 2024			(400	)
Borrowing on June 27, 2024			140
Borrowing on August 30, 2024			235
Borrowing on September 30, 2024			125
Repayment on November 13, 2024			(500	)
Balance at December 31, 2024		$	—

$500M Credit Facility — The following table summarizes the activity under the $500M Credit Facility in 2024:

 

		Borrowing (Repayment) Amounts
Borrowing on February 28, 2024		$	220
Borrowing on March 28, 2024			280
Repayment on December 30, 2024			(20	)
Balance at December 31, 2024		$	480

Short-Term Debt-Related Activities in 2024

CP Program — As of December 31, 2024 and December 31, 2023, we had $594 million and $282 million of CP Notes outstanding, respectively. The weighted average interest rate for CP Notes was 4.76% and 5.54% at December 31, 2024 and December 31, 2023, respectively. All outstanding CP Notes at December 31, 2024 and December 31, 2023 had maturity dates of less than one year.

See Note 5 to Annual Financial Statements for additional information regarding our short-term debt.

Available Liquidity and Liquidity Needs, Including Capital Expenditures

Capital Expenditures — Our board of directors has approved a capital expenditures budget of approximately $7.1 billion for 2025. We have also announced a 2025 to 2029 five-year base capital expenditure plan of approximately $36.1 billion. We expect to announce a new five-year base capital plan for the years 2026 through 2030 in the first half of 2026, subject to completion of our base rate review, and currently anticipate that new base capital plan will be at least 30% higher than the 2025 to 2029 $36.1 billion base capital plan. We also expect significant potential capital expenditure opportunities incremental to the 2026 to 2030 base capital plan.

We are monitoring the impact of global tariffs on our supply chain and capital expenditure plan, and while we do not currently anticipate a material impact on us from the tariffs that have been announced to date, tariff and trade regulations continue to evolve and we cannot predict the ultimate impact such regulations will have on our supply chain, capital expenditures plan, financial condition, results of operations, liquidity, and cash flows. See “Risk Factors—Risks Related to Our Business and Operations—Our capital deployment plan may not be executed as planned, which could adversely impact our reputation, reliability, financial condition and results of operations” for more information on risks related to execution

 

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of our capital plan and “Risk Factors—Risks Related to Our Business and Operations—We are dependent upon a limited number of suppliers and service providers for certain of our operations. Disruptions in our supply chain or the availability of our suppliers to perform on expected or acceptable terms, including as a result of competition for materials, the contractor labor market and inflation, could negatively impact us” for more information on risks related to our supply chain.

Long-Term Debt Maturities and Interest — As of December 31, 2024, our obligations related to long-term debt (excluding unamortized discount, premium and debt issuance costs, but including the remeasurement adjustment related to the 2031 Euro Notes) and related interest payments are as follows:

 

		2025				2026				2027				2028				2029				Thereafter				Total
Principal amounts(a)		$	974			$	238			$	480			$	1,250			$	968			$	11,483			$	15,393
Interest payments(a)			685				666				640				617				564				6,599				9,771
Total(a)		$	1,659			$	904			$	1,120			$	1,867			$	1,532			$	18,082			$	25,164

(a)	For more information regarding our long-term debt activity subsequent to December 31, 2024, see “Summary—Recent Developments” and Note 5 to Interim Financial Statements in this prospectus.

See Note 5 to Interim Financial Statements and Note 6 to Annual Financial Statements for more information regarding long-term debt.

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 $22 million and $6 million, respectively, during the remainder of 2025 and approximately $591 million and $140 million, respectively, in the five-year period from 2025 to 2029. 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. During the nine months ended September 30, 2025, we made cash contributions to the pension plans and OPEB Plans of $172 million and $18 million, respectively. In 2024, we made cash contributions to the pension plans and OPEB Plans of $91 million and $23 million, respectively. See Note 8 to Interim Financial Statements and Note 9 to Annual 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. See Note 6 to Interim Financial Statements and Note 7 to Annual 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 “Risk Factors—Risks Related to Our Business and Operations—We regularly evaluate opportunities to make selective strategic acquisitions involving regulated assets. Acquisitions involve various risks, and we may not be able to realize the anticipated benefits of any such acquisitions.”

Available Liquidity — Our primary sources of liquidity, aside from operating cash flows, at September 30, 2024, December 31, 2023 and December 31, 2022 are summarized in the following table:

 

		At September 30, 2025				At December 31, 2024				At December 31, 2023
Cash and cash equivalents		$	198			$	36			$	19
Available unused borrowing capacity under the $2B Credit Facility and CP Program			2,000				1,406				1,718
Available unused borrowing capacity under the $1B Credit Facility and CP Program			1,000				—				—
Available unused borrowing capacity under AR Facility			500	(a)			500				500
Available unused borrowing capacity under the $500M Credit Facility			20				20				—
Total available liquidity		$	3,718			$	1,962			$	2,237

(a)	For more information regarding our long-term debt activity subsequent to September 30, 2025, see “Summary—Recent Developments” in this prospectus.

 

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We expect cash flows from operations combined with long-term debt issuances and credit agreements as well as availability under the Credit Facilities, the Term Loan Agreement, 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, and additional accounts receivable 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, or the Credit Facilities, the Term Loan Agreement, our CP Program and AR Facility. 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 “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, discount, 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.

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 on May 1, 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. 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 September 30, 2025, December 31, 2024 and December 31, 2023:

 

		At September 30, 2025								At December 31, 2024								At December 31, 2023
		Debt				Equity				Debt				Equity				Debt				Equity
Authorized regulatory capital structure			57.5	%			42.5	%			57.5	%			42.5	%			57.5	%			42.5	%
Actual regulatory capitalization			56.0	%			44.0	%			56.1	%			43.9	%			55.8	%			44.2	%
GAAP capitalization			50.4	%			49.6	%			49.4	%			50.6	%			48.3	%			51.7	%

 

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Member Contributions and Distributions

Contributions — We received cash capital contributions from our members of $647 million on October 29, 2025. In the nine months ended September 30, 2025, we received the following cash capital contributions from our members:

 

Receipt Dates		Amounts
February 14, 2025		$	605
May 2, 2025		$	605
July 30, 2025		$	647

During 2024, we received the following cash capital contributions from our members:

 

Receipt Dates		Amounts
February 16, 2024		$	240
May 3, 2024		$	240
July 31, 2024		$	240
October 31, 2024		$	114
December 20, 2024		$	377

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 September 30, 2025 and December 31, 2024, we had $837 million and $686 million, respectively, available to distribute to our members.

On October 28, 2025, our board of directors declared a cash distribution of $219 million, which was paid to our members on October 28, 2025. In the nine months ended September 30, 2025, our board of directors declared, and we paid, the following cash distributions to our members:

 

Declaration Dates		Payment Dates		Amounts
February 13, 2025		February 13, 2025		$	177
April 30, 2025		May 1, 2025		$	177
July 29, 2025		July 29, 2025		$	219

During 2024, our board of directors declared, and we paid, the following cash distributions to our members:

 

Declaration Dates		Payment Dates		Amounts
February 14, 2024		February 15, 2024		$	125
April 30, 2024		May 1, 2024		$	126
July 30, 2024		July 30, 2024		$	125
December 9, 2024		December 19, 2024		$	377

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 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) and the Term Loan Agreement. 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.

 

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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.

Material Debt Credit Rating, Financial and Cross-Default Covenants — Each of the Credit Facilities and the Term Loan Agreement contains terms pursuant to which the interest rates and commitment fees charged, respectively, 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 the Term Loan Agreement and likely increase the cost of our 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 Note 4 to Interim Financial Statements for additional information regarding each of the Credit Facilities and the CP Program.

The Credit Facilities, the Term Loan Agreement, 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 capital leases (referred to as finance leases under current accounting literature), short-term debt and debt due currently in accordance with GAAP). Capitalization under the Credit Facilities, the Term Loan Agreement, the AR Facility, 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. Capitalization under our note purchase agreement dated May 6, 2019 (May 2019 NPA) is calculated as membership interests plus liabilities for indebtedness maturing more than 12 months from the date of determination, with capitalization determined in accordance with GAAP and practices applicable to our type of business. The ratio under the May 2019 NPA is calculated as total debt (all debt of Oncor and its subsidiaries on a consolidated basis) divided by the sum of total debt plus capitalization. At September 30, 2025, we were in compliance with this covenant and all other covenants under 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 and the May 2019 NPA, 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 or the notes under the May 2019 NPA to be declared due and payable.

Under 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.

Guarantees

At September 30, 2025 and December 31, 2024, we did not have any material guarantees.

COMMITMENTS AND CONTINGENCIES

See Note 6 to Interim Financial Statements and Note 7 to Annual Financial Statements for a discussion of commitments and contingencies.

CHANGES IN ACCOUNTING STANDARDS

See Note 1 to Interim Financial Statements and Note 1 to Annual Financial Statements for a discussion of changes in accounting standards.

 

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REGULATION AND RATES

Regulatory Matters

2025 Comprehensive Base Rate Review (PUCT Docket No. 58306) — On June 26, 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. The base rate review test year is based on calendar year 2024 results with certain adjustments. The base rate review includes a request for an average increase over test year adjusted annualized revenue of approximately 13%, and, if approved as requested, would result in an aggregate annualized revenue increase of approximately $834 million over current adjusted rates. The base rate review also requests a revised regulatory capital structure ratio of 55% debt to 45% equity, an authorized return on equity of 10.55%, and a 4.94% authorized cost of debt. Our current authorized regulatory capital structure ratio is 57.5% debt to 42.5% equity, our current authorized return on equity is 9.7%, and our current authorized cost of debt is 4.39%. On November 13, 2025, Oncor, on behalf of the parties to the comprehensive base rate review, filed a notice of a settlement in principle among the parties and requested an abatement to the procedural schedule. On November 13, 2025, the administrative law judge assigned to the proceeding abated the procedural schedule. On January 16, 2026, Oncor provided a status update noting that the parties continue to finalize settlement documentation. We cannot predict whether or to what extent our requests in the rate review will be approved or the proceeding’s ultimate effect on our results of operations, financial condition, or cash flows.

PUCT rules permit the filing of a request for interim rates while a rate proceeding is pending. On September 9, 2025, the administrative law judge assigned to the proceeding approved a settlement agreement among the parties relating to interim rates. That order provides that if the proceeding is still pending as of January 1, 2026, and not otherwise subject to a PUCT-approved settlement of the proceeding, our existing rates will become interim rates, subject to refund or surcharge back to January 1, 2026 based upon the final rates approved by the PUCT in the proceeding.

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

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

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. To date in 2025, two special sessions have been convened, with the second special session concluding on September 4, 2025. 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 2025, the Texas Legislature passed HB 5247, which was signed by the Governor and took effect on June 20, 2025. The bill establishes the UTM, which allows qualifying electric utilities to (i) apply for interim rate adjustments once annually through 2035 for cost recovery of certain transmission and distribution capital expenditures, as an alternative to semi-annual (or less frequent) 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.

 

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Qualifying electric utilities consist of utilities that (i) operate solely inside the ERCOT market, (ii) have been identified by the PUCT as having responsibility for constructing transmission infrastructure as part of ERCOT’s Permian Basin Reliability Plan, and (iii) make annual capital expenditures in transmission and distribution that exceed 300% of annual depreciation. As an entity that operates solely within the ERCOT market, has been identified as having responsibility for constructing portions of the Permian Basin Reliability Plan, and anticipates making annual transmission and distribution capital expenditures that exceed 300% of annual depreciation, we expect to utilize the UTM instead of DCRF and TCOS capital tracker filings. We currently plan to make our first UTM filing in the first half of 2026 for recovery of costs associated with eligible investments placed into service after December 31, 2024. In the meantime, we have begun, and expect to continue, recording regulatory assets for costs associated with those capital investments as they are placed into service and recognizing corresponding revenues. See Notes 2 and 3 to Interim 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 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, 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.

Federal Legislation

On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 which includes, among other provisions, changes to the federal income tax system, including the allowance of immediate expensing of qualifying research and development expenses. We are evaluating the future impact of the One Big Beautiful Bill Act on our financial statements.

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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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS

ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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 September 30, 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 materially impact our results of operations. See Note 10 to Interim Financial Statements and Note 11 to Annual Financial Statements for more information on our interest rate risk hedging activities.

At September 30, 2025, all of our senior secured notes carried fixed interest rates. Borrowings under the AR Facility would 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. 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 an adjustment of 0.10% (the SOFR Adjustment). Receivables LLC also pays a used and unused fee in connection with the AR Facility. At September 30, 2025, the borrowing base for the AR Facility was $500 million, and there were no borrowings outstanding under the AR Facility. On November 25, 2025, we borrowed $325 million aggregate principal amount under the AR Facility.

In addition, borrowings of long-term debt under the $1B Credit Facility would bear interest on a floating rate basis. At September 30, 2025, there were no borrowings outstanding under the $1B Credit Facility.

Borrowings of long-term debt under the $500M Credit Facility at September 30, 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 September 30, 2025, $480 million in aggregate borrowings were outstanding under the $500M Credit Facility.

At September 30, 2025, except for the $500M Credit Facility, all of our long-term debt carried fixed interest rates. Based on the amount of floating rate debt outstanding under the $500M Credit Facility as of September 30, 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 4 and 5 to Interim Financial Statements.

In addition, borrowings of short-term debt under the $2B Credit Facility bear interest on a floating rate basis. At September 30, 2025, we had no floating rate debt outstanding under the $2B Credit Facility.

 

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At December 31, 2024, except for the $500M Credit Facility, all of our long-term debt carried fixed interest rates. The following table presents our long-term debt maturities as of December 31, 2024 and related information:

 

		Expected Maturity Date
		2025				2026				2027				2028				2029				There- after				2024 Total Carrying Amount				2024 Total Fair Value (a)				2023 Total Carrying Amount				2023 Total Fair Value (a)
		(U.S. dollars in millions and percent)
Long-term debt (including current maturities):
Fixed rate debt amount (b)		$	974			$	238			$	—			$	1,250			$	968			$	11,483			$	14,913			$	12,966			$	13,445			$	12,798
Weighted average interest rate (c)			1.09	%			5.24	%			—				3.99	%			5.05	%			4.68	%			4.45	%			—				4.25	%			—
Variable rate debt amount (b)		$	—			$	—			$	480			$	—			$	—			$	—			$	480			$	480			$	—			$	—
Weighted average interest rate			—				—				5.44	%			—				—				—				5.44	%			—				—				—
Total Long-Term Debt (d)		$	974			$	238			$	480			$	1,250			$	968			$	11,483			$	15,393			$	13,446			$	13,445			$	12,798

(a)	The fair value is estimated using observable market data, representing Level 2 valuations under accounting standards related to the determination of fair value.

(b)	Excludes unamortized premiums, discounts and debt issuance costs, but includes the remeasurement adjustment related to the 2031 Euro Notes.

(c)	Based on annualized interest rates for each outstanding series of fixed rate notes.

(d)	For more information regarding our long-term debt activity subsequent to December 31, 2024, see “Summary—Recent Developments” and Note 5 to Interim Financial Statements in this prospectus.

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 10 to Interim Financial Statements and Note 11 to Annual 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 Annual Financial Statements and Note 10 to Interim 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.

Our exposure to credit risk associated with accounts receivable totaled $1.186 billion, $987 million, and $958 million at September 30, 2025, December 31, 2024, and December 31, 2023, respectively. The accounts receivable balance is before the allowance for uncollectible accounts, which totaled $20 million, $17 million, and $14 million at September 30, 2025, December 31, 2024, and December 31, 2023, respectively. The exposure at September 30, 2025, December 31, 2024, and December 31, 2023 includes accounts receivable of $836 million, $628 million and $640 million, respectively, in the

 

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