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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________________________

FORM 10-K

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

For the Fiscal Year Ended December 31, 2025

— OR —

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

Commission File Number: 333-100240

Oncor Electric Delivery Company LLC

(Exact name of registrant as specified in its charter)


Delaware	75-2967830
(State of organization)	(I.R.S. Employer Identification No.)

1616 Woodall Rodgers Fwy., Dallas, TX 75202	(214) 486-2000
(Address of principal executive offices)(Zip Code)	(Registrant’s telephone number, including area code)

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




Title of each class	Trading Symbol	Name of each exchange on which registered
None	None	None

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

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

Yes ☐ No ☒

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

Yes ☐ No ☒

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

Yes ☐ No ☒

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

Yes ☒ No ☐

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

Large accelerated filer ☐ Accelerated filer ☐

Non-accelerated filer ☒ Smaller reporting company ☐

Emerging growth company ☐

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

☐

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

☒

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

☐

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

☐

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

Yes ☐ No ☒

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

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

DOCUMENTS INCORPORATED BY REFERENCE: None

‎


‎TABLE OF CONTENTS
		Page
Glossary		4
PART I
Items 1. and 2.	BUSINESS AND PROPERTIES	7
Item 1A.	RISK FACTORS	15
Item 1B.	UNRESOLVED STAFF COMMENTS	30
Item 1C.	CYBERSECURITY	30
Item 3.	LEGAL PROCEEDINGS	32
Item 4.	MINE SAFETY DISCLOSURES	32
PART II
Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	33
Item 6.	RESERVED	33
Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	61
Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	118
Item 9A.	CONTROLS AND PROCEDURES	118
Item 9B.	OTHER INFORMATION	121
Item 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	122
PART III
Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	122
Item 11.	EXECUTIVE COMPENSATION	133
Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	174
Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	176
Item 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	182
PART IV
Item 15.	EXHIBIT AND FINANCIAL STATEMENT SCHEDULES	184

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

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

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GLOSSARY


When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
$500M Credit Facility	Refers to the unsecured $500 million revolving credit agreement, dated as of February 21, 2024, among Oncor, as borrower, the lenders from time-to-time party thereto, and Wells Fargo Bank, National Association, as administrative agent, maturing on February 21, 2027
$1B Credit Facility	Refers to the unsecured $1 billion revolving credit agreement, dated as of February 20, 2025, among Oncor, as borrower, the lenders from time-to-time party thereto, Wells Fargo Bank, National Association, as administrative agent and swingline lender, and the other financial institutions party thereto, as amended, maturing on February 20, 2029
$2B Credit Facility	Refers to the amended and restated unsecured $2 billion revolving credit agreement, dated as of February 20, 2025, among Oncor, as borrower, the lenders from time-to-time party thereto, JPMorgan Chase Bank, N.A., as administrative agent and swingline lender, the fronting banks from time-to-time party thereto, and the other financial institutions party thereto, as amended, maturing on February 20, 2031
2031 Euro Notes	Refers to the €500 million aggregate principal amount of euro-denominated senior secured notes due May 15, 2031, which were issued by Oncor in May 2024
2034 Euro Notes	Refers to the €700 million aggregate principal amount of euro-denominated senior secured notes due June 15, 2034, which were issued by Oncor in June 2025
ABO	Accumulated benefit obligation
acquisition accounting	The acquisition method of accounting for a business combination as prescribed by GAAP, whereby the cost or “acquisition price” of a business combination, including the amount paid for the equity and certain transaction costs, is allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill
AFUDC	Allowance for funds used during construction
AI	Artificial intelligence
AOCI	Accumulated other comprehensive income (loss)
APBO	Accumulated postretirement benefit obligation
AR Facility	Refers to the accounts receivable facility entered into by Oncor on April 28, 2023, providing for the contribution of certain accounts receivable and certain other related rights to Receivables LLC, which, in turn, obtains loans secured by the receivables from various third-party lenders, as amended, maturing on April 28, 2028
ASC	Accounting Standards Codification
CAD Notes	Refers to the C$500 million aggregate principal amount of Canadian dollar-denominated senior secured notes due October 1, 2035, which were issued by Oncor in September 2025
Code	The Internal Revenue Code of 1986, as amended
CODM	Chief operating decision maker
CP Notes	Unsecured commercial paper notes issued under the CP Program
CP Program	Oncor’s commercial paper program, as amended
Credit Facilities	Refers collectively to the $500M Credit Facility, the $1B Credit Facility and the $2B Credit Facility
DCRF	Distribution cost recovery factor
Deed of Trust	Deed of Trust, Security Agreement and Fixture Filing, dated as of May 15, 2008, made by Oncor to and for the benefit of The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Mellon, formerly The Bank of New York), as collateral agent, as amended
DER	Distributed energy resources

Disinterested Director	Refers to a member of our board of directors who is, pursuant to our LLC Agreement, one of the seven members of our 13-member board of directors who qualifies as a “disinterested director,” defined as a director who (i) shall be an independent director 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
EECRF	Energy efficiency cost recovery factor
EPA	U.S. Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas, Inc., the independent system operator and the regional coordinator of various electricity systems within Texas
ERISA	Employee Retirement Income Security Act of 1974, as amended
Euro Notes	Refers to the 2031 Euro Notes and the 2034 Euro Notes
FASB	Financial Accounting Standards Board
FERC	U.S. Federal Energy Regulatory Commission
Fitch	Fitch Ratings, Inc. (a credit rating agency)
GAAP	Generally accepted accounting principles of the U.S.
I.R.S.	U.S. Internal Revenue Service
kV	Kilovolts
kWh	Kilowatt-hours
LC&I	Large Commercial & Industrial
LLC Agreement	The Third Amended and Restated Limited Liability Company Agreement of Oncor, dated as of March 9, 2018, by and between Oncor Holdings and Texas Transmission, as amended
Moody’s	Moody’s Investors Service, Inc. (a credit rating agency)
MW	Megawatts
NAV	Net asset value
NERC	North American Electric Reliability Corporation
NYSE	New York Stock Exchange
OBBBA	One Big Beautiful Bill Act of 2025
OCI	Other comprehensive income (loss)
Oncor	Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings
Oncor Holdings	Oncor Electric Delivery Holdings Company LLC, which is the direct majority owner (80.25% equity interest) of Oncor and is wholly owned by STIH
Oncor Retirement Plan	Refers to a defined benefit pension plan sponsored by Oncor
Oncor Ring-Fenced Entities	Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor and Oncor’s direct and indirect subsidiaries
OPEB	Other postretirement employee benefits
OPEB Plans	Refers to plans sponsored by Oncor that offer certain postretirement health care and life insurance benefits to eligible current and former employees of Oncor and certain former affiliated companies and their eligible dependents
PBO	Projected benefit obligation
PBRP	Refers to the Permian Basin Reliability Plan developed by ERCOT and approved by the PUCT in PUCT Docket. No 55718
PUCT	Public Utility Commission of Texas
PURA	Texas Public Utility Regulatory Act, as amended
Receivables LLC	Oncor Receivables LLC, a bankruptcy-remote special purpose entity and a wholly-owned subsidiary of Oncor
REP	Retail electric provider
ROU	Right-of-use
S&P	S&P Global Ratings, a division of S&P Global Inc. (a credit rating agency)
SEC	U.S. Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
Sempra	Sempra, a California corporation

Sempra Order	Refers to the final order issued by the PUCT in 2018 in PUCT Docket No. 47675 approving Sempra’s indirect acquisition of Oncor Holdings
Sharyland	Sharyland Utilities, L.L.C.
SOFR	Refers to the secured overnight financing rate as administered by the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate)
SOFR Adjustment	Refers to an adjustment of +0.10% to term SOFR
SRP	Refers to Oncor’s system resiliency plan to enhance the resiliency of its transmission and distribution system, which plan was approved by the PUCT in 2024 in PUCT Docket No. 56545
STEP	Refers to the Texas 765-kV Strategic Transmission Expansion Plan developed by ERCOT, which includes the PBRP as well as additional transmission projects outside of the Permian Basin
STH	Sempra Texas Holdings Corp., a Texas corporation, which is wholly owned by Sempra and the direct parent of STIH
STIH	Sempra Texas Intermediate Holding Company LLC, a Delaware limited liability company, which is a wholly owned, indirect subsidiary of Sempra and the sole member of Oncor Holdings
Supplemental Retirement Plan	Refers to the Oncor Supplemental Retirement Plan, as amended
Term Loan Credit Agreement	Refers to the unsecured $1.4 billion term loan credit agreement, dated as of December 23, 2025, among Oncor, as borrower, the lenders from time to time party thereto, and Sumitomo Mitsui Banking Corporation, as administrative agent, maturing on March 1, 2027
TCEQ	Texas Commission on Environmental Quality
TCJA	U.S. Tax Cuts and Jobs Act of 2017
TCOS	Transmission cost of service
TCRF	Transmission cost recovery factor
Texas margin tax	A privilege tax imposed on taxable entities chartered/organized or doing business in the State of Texas that, for accounting purposes, is reported as an income tax
Texas RE	Texas Reliability Entity, Inc., an independent organization that develops reliability standards for the ERCOT region and monitors and enforces compliance with NERC standards and ERCOT protocols
Texas Transmission	Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor and is indirectly owned by OMERS Administration Corporation (acting through its infrastructure investment entity, OMERS Infrastructure Management Inc.) and GIC Private Limited
U.S.	United States of America
UTM	Refers to the unified tracker mechanism, established by Texas House Bill 5247, which became effective on June 20, 2025
VIE	Variable interest entity
Vistra	Vistra Corp. and/or its subsidiaries, depending on context
Vistra Retirement Plan	Refers to a defined benefit pension plan sponsored by an affiliate of Vistra

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PART I

Items 1. and 2. BUSINESS AND PROPERTIES

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

Overview of Oncor

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

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

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.

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

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

Ownership Structure and Ring-Fencing Measures

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

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

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

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

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

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;

two members designated by Sempra (through Oncor Holdings);

two members designated by Texas Transmission; and

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:

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;

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;

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;

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;

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;

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

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

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

Oncor’s Strategies

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

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

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

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

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

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

Oncor’s Operations

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

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

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

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

At December 31, 2025, our transmission system included:

18,418 circuit miles of transmission lines:

o7,603 circuit miles of 345kV transmission lines, and

o10,815 circuit miles of 138kV and 69kV transmission lines,

interconnection to 230 third-party generation facilities totaling 63,670 MW directly connected to our transmission system, and

a total of 1,333 transmission and distribution substations.

At December 31, 2025, 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)	21	21	21
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 3,874 distribution feeders at December 31, 2025.

At December 31, 2025, our distribution system included:

127,398 circuit miles of distribution lines:

o90,568 circuit miles of overhead lines, and

o36,830 circuit miles of underground lines,

4,111,000 approximate number of points of delivery, an increase of approximately 65,000 over the number of

points of delivery at December 31, 2024, and

1.85% 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 LC&I users are generally based either on actual monthly demand (kilowatts) or the greater of actual monthly demand (kilowatts) or 80% of peak monthly demand during the prior 11 months.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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 2025, we hosted 15 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.

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.

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. In 2025, we also introduced an internal, company-wide strategy day to engage all employees in the company’s strategic priorities.

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 23% of our employees participating in at least one ERG as of December 31, 2025. 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.

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.

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 21 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.

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 2025 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 2025, which indicated increases in the number of engaged employees, managers, and teams versus prior year results, and are using the results of that survey to continue to develop and implement our employee engagement strategy.

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.

Item 1A.RISK FACTORS

Risks Related to Regulatory and Legislative Matters

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

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

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

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

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

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

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

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

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

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

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

Risks Related to Our Business and Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

Wildfires could have a material adverse effect on our business.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Risks Related to Financial and Market Matters

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

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

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

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

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

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

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

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

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

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

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

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 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 any other direct or indirect owner of Oncor or their affiliates 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 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 December 31, 2025, our regulatory capital structure was 56.3% debt to 43.7% equity. Our ability to incur additional long-term debt is limited by our authorized regulatory capital structure and we are able to issue future long-term debt only to the extent that such issuance would not cause our regulatory capital structure to exceed the authorized regulatory debt-to-equity ratio. In addition, certain of our debt agreements contain debt-to-capital ratio covenants that effectively limit our ability to incur indebtedness in the future.

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

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

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Item 1B.UNRESOLVED STAFF COMMENTS

None.

Item 1C.CYBERSECURITY

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

Our Cybersecurity Strategy

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

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

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

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

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

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

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

Our Cybersecurity Team

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

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

Governance

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

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

Item 3.LEGAL PROCEEDINGS

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

Item 4.MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

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

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

Item 6.RESERVED

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

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

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

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

BUSINESS

Ring-Fencing Measures

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 “Items 1. and 2. Business and Properties—Ownership Structure and Ring-Fencing Measures.”

Significant Activities and Events

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

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

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

KEY FACTORS RELATING TO FUTURE EARNINGS AND RESULTS OF OPERATIONS

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

Regulation, Rates and Cost Recovery

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

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

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

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

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

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

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

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

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

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

Weather

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

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

Capital Availability and Cost

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

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

CRITICAL ACCOUNTING ESTIMATES

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

Accounting for the Effects of Certain Types of Regulation

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

Accounting for the Effects of Income Taxes

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

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

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

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

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

Impairment of Long-Lived Assets and Goodwill

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

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

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

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

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

Defined Benefit Pension Plans and OPEB Plans

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

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

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

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

‎

RESULTS OF OPERATIONS

Operating Data


		Years Ended December 31,
	2025		2024		2023
Reliability statistics (a):
System Average Interruption Duration Index (SAIDI) (non-storm)		78.1		74.7		70.0
System Average Interruption Frequency Index (SAIFI) (non-storm)		1.1		1.1		1.0
Customer Average Interruption Duration Index (CAIDI) (non-storm)		70.4		69.8		70.7
Electricity points of delivery (end of period and in thousands):
Electricity distribution points of delivery (based on number of active meters)		4,111		4,046		3,969
Residential system weighted weather data (b):
Cooling degree days		1,884		2,071		2,268
Heating degree days		788		610		608
Operating statistics:
Electric energy volumes (gigawatt-hours):
Residential		47,312		46,444		47,112
Commercial, industrial, small business and other		125,463		116,247		109,365
Total electric energy volumes		172,775		162,691		156,477

	Years Ended December 31,
	2025		2024		2023
Operating revenues:
Revenues contributing to earnings:
Revenues from contracts with customers
Distribution base revenues
Residential (c)	$	1,613	$	1,477	$	1,334
LC&I (d)		1,390		1,283		1,162
Other (e)		128		125		132
Total distribution base revenues		3,131		2,885		2,628
Transmission base revenues (TCOS revenues)
Billed to third-party wholesale customers		1,091		1,050		959
Billed to REPs serving Oncor distribution customers, through TCRF		605		574		539
Total TCOS revenues		1,696		1,624		1,498
Other miscellaneous revenues		96		95		88
Total revenues from contracts with customers		4,923		4,604		4,214
Other regulated revenues
SRP revenues (f)		180		1		-
UTM revenues (g)		104		-		-
Energy efficiency program performance bonus revenues		33		17		21
Total other regulated revenues		317		18		21
Total revenues contributing to earnings		5,240		4,622		4,235

Revenues collected for pass-through expenses:
TCRF – third-party wholesale transmission service		1,475		1,394		1,291
EECRF and other revenues		63		66		60
Total revenues collected for pass-through expenses		1,538		1,460		1,351
Total operating revenues	$	6,778	$	6,082	$	5,586

________________

(a)SAIDI is the average number of minutes electric service is interrupted per consumer in a 12-month period. SAIFI is the average number of electric service interruptions per consumer in a 12-month period. CAIDI is the average duration in minutes per electric service interruption in a 12-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.

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

(d)Depending on size and annual load factor, distribution base revenues from LC&I 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 11 months.

(e)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.

(f)Includes revenues recognized for recoverable costs associated with distribution-related SRP, including operation and maintenance expenses, depreciation expenses, carrying costs on unrecovered balances and related taxes.

(g)Includes revenues recognized for recoverable costs associated with UTM eligible transmission and distribution capital investments put into service after December 31, 2024 through December 31, 2025, including depreciation expenses, carrying costs on unrecovered balances and related taxes.
‎

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

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

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

An Increase in Distribution Base Revenues — Distribution base revenues increased $246 million to $3.131 billion in 2025. The increase in distribution base revenues primarily reflects:

o$193 million increase due to updated interim DCRF rates implemented to reflect increases in invested capital,

o$45 million increase due to customer growth, and

o$8 million increase due to higher customer consumption.

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

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

Interim DCRF Filings Table


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

____________

(a)Annual revenue impact represents the estimated 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.

An Increase in Transmission Base Revenues — TCOS revenues increased $72 million to $1.696 billion in 2025. The increase in TCOS revenues primarily reflects:

o$85 million increase due to updated interim TCOS rates implemented to reflect increases in invested capital,

partially offset by

o$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 to those customers are adjusted based on the transmission billing units and other adjustments approved by the PUCT. We may request interim updates to our transmission base rates between comprehensive base rate reviews through a UTM application or interim TCOS rate adjustment application.

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

Interim TCOS Filings Table


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

____________

(a)Annual revenue impact represents the estimated 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.

An Increase in Other Miscellaneous Revenues — Other miscellaneous revenues increased $1 million to $96 million in 2025. Energy efficiency program performance bonus revenues were previously included in other miscellaneous revenues, but have been conformed to the current period presentation as other regulated revenues (see below).

An Increase in Other Regulated Revenues — Other regulated revenues increased $299 million to $317 million in 2025. The increase in other regulated revenues primarily reflects:

o$179 million increase in revenues recognized pursuant to the SRP, primarily related to recoverable distribution-related incremental operation and maintenance expenses recognized under the SRP,

o$104 million in revenues recognized pursuant to the UTM, associated with recoverable costs for transmission and distribution capital investments placed into service after December 31, 2024, and

o$16 million higher annual energy efficiency program performance bonus revenues approved in 2025.

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

An Increase in TCRF – third-party wholesale transmission service (TCRF Third-Party) — TCRF Third-Party revenues increased $81 million to $1.475 billion in 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. We currently anticipate requesting interim TCRF updates through our UTM applications. The increase in our TCRF Third-Party revenue recognition reflects the pass-through effect of changes in third-party wholesale transmission service expense.

A Decrease in EECRF and Other Revenues — EECRF and other revenues decreased $3 million to $63 million in 2025. The decrease was primarily due to lower rate case expense rider revenues to cover deferred rate case expense amortization, associated with our 2023 comprehensive rate base review proceeding (PUCT Docket No. 53601), partially offset by higher EECRF revenues to cover energy efficiency program expenses. These 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 regulated revenues upon approval by the PUCT. PUCT rules require us to file an annual EECRF tariff update by the first business day in June of each year for implementation on March 1 of the next calendar year. Other revenues generally include amounts collected through (i) the mobile generation rider, which is a reconcilable rate designed to recover mobile generation lease expenses and operation and maintenance expenses and is generally reviewed and approved by the PUCT in our mobile generation rider filing proceedings, and (ii) the rate case expense rider, which is a reconcilable rate designed to recover rate case expenses approved in comprehensive rate base review proceedings.

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

EECRF Filings Table


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

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

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

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

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

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

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

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

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

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

overall higher net revenues primarily attributable to:

oan increase in other regulated revenues recognized related to the establishment of the UTM,

oupdated interim rates to reflect increases in invested capital,

ocustomer growth, and

ohigher annual energy efficiency program performance bonus revenues,

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

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

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

Fair Value Hedges

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

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

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

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

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

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


	Years Ended December 31,
	2025 compare to 2024
Higher customer deposits	$	314
Lower self-insurance reserve costs incurred, primarily storm related		156
Change in regulatory under/over recoveries – net		51
Change in net income, adjusted for noncash items included in earnings		(2)
Higher contributions to pension plans and OPEB Plans		(102)
Higher interest payments		(139)
Other		75
	$	353

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

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


	Years Ended December 31,
	2025 compare to 2024
Higher net borrowings, excluding payment for senior secured notes extinguishment	$	1,294
Higher capital contributions from members		1,293
Higher distributions to members		(39)
Payment for senior secured notes extinguishment		(441)
	$	2,107

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


	Years Ended December 31,
	2025 compare to 2024
Higher capital expenditures	$	(2,078)
Lower sales tax audit settlement refund classified as investing activities		(47)
Other		11
	$	(2,114)

Long-Term Debt-Related Activities in 2025 and 2026

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

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

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


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

____________

(a)On June 16, 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 December 31, 2025, the amount of available bond credits was $3.503 billion. The repayment in full of the $38 million outstanding principal amount of our 3.86% Senior Secured Notes, Series B, due January 14, 2026 (Series B Notes) upon their maturity on January 14,

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

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

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

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

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

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

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


	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)
Borrowing on November 25, 2025		325
Balance at December 31, 2025	$	325

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

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

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

Short-Term Debt-Related Activities in 2025 and 2026

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

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

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

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

Available Liquidity and Liquidity Needs, Including Capital Expenditures

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

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

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

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


	2026		2027		2028		2029		2030		Thereafter		Total
Principal amounts	$	238	$	1,905	$	1,575	$	1,318	$	700	$	13,488	$	19,224
Interest payments		907		832		786		720		673		7,406		11,324
Total	$	1,145	$	2,737	$	2,361	$	2,038	$	1,373	$	20,894	$	30,548

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

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

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

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


	At December 31,				Increase
	2025		2024		(Decrease)
Cash and cash equivalents	$	87	$	36	$	51
Available unused borrowing capacity under the $2B Credit Facility and CP Program		2,000		1,406		594
Available unused borrowing capacity under the $1B Credit Facility and CP Program		1,000		-		1,000
Available unused borrowing capacity under AR Facility (a)		175		500		(325)
Available unused borrowing capacity under Term Loan Credit Agreement (a)		475		-		475
Available unused borrowing capacity under the $500M Credit Facility		20		20		-
Total available liquidity	$	3,757	$	1,962	$	1,795

__________

(a)On January 29, 2026, we borrowed (i) $150 million under the AR Facility and (ii) $475 million under the Term Loan Credit Agreement. Following such borrowing under the Term Loan Credit Agreement, no additional amounts remain available for borrowing under the Term Loan Credit Agreement.

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

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

Capitalization and Return on Equity

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

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

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


	At December 31,
	2025		2024
	Debt	Equity	Debt	Equity
Authorized regulatory capital structure	57.5%	42.5%	57.5%	42.5%
Actual regulatory capitalization	56.3%	43.7%	56.1%	43.9%
GAAP capitalization	50.9%	49.1%	49.4%	50.6%

Member Contributions and Distributions

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


Receipt Dates	Amounts
February 14, 2025	$	605
May 2, 2025	$	605
July 30, 2025	$	647
October 29, 2025	$	647

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

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


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
October 28, 2025	October 28, 2025	$	219

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). In the event any adverse action with respect to our credit ratings or ratings outlook takes place and causes borrowing costs to increase, we may not be able to recover such increased costs if they exceed our PUCT-approved cost of debt determined in our most recent comprehensive base rate review or subsequent comprehensive base rate reviews.

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

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


Credit Rating Agency	Senior Secured	Commercial Paper	Rating Outlook
S&P	A	A-2	Stable
Moody’s	A2	Prime-2	Negative
Fitch	A	F2	Negative

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

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

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

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

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

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

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

Guarantees

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

COMMITMENTS AND CONTINGENCIES

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

CHANGES IN ACCOUNTING STANDARDS

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

REGULATION AND RATES

Regulatory Matters

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

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

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

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

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

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

State Legislation

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

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

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

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

Federal Legislation

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

Summary

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

‎

Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk

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

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

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

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

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

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

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

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


Expected Maturity Date
2026	2027	2028	2029	2030	There-after	2025 Total Carrying Amount	2025 Total Fair Value (a)	2024 Total Carrying Amount	2024 Total Fair Value (a)

ONCOR ELECTRIC DELIVERY CO LLC 10-K