CENTERPOINT ENERGY INC 10-K

cnp-20251231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ______________________ Form 10-K (Mark One) ☑ 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 FOR THE TRANSITION PERIOD FROM TO Registrant, State or Other Jurisdiction of Incorporation or Organization Commission file number Address of Principal Executive Offices, Zip Code and Telephone Number I.R.S. Employer Identification No. 1-31447 CenterPoint Energy, Inc. 74-0694415 (a Texas corporation) 1111 Louisiana Houston, Texas 77002 (713) 207-1111 1-3187 CenterPoint Energy Houston Electric, LLC 22-3865106 (a Texas limited liability company) 1111 Louisiana Houston, Texas 77002 (713) 207-1111 1-13265 CenterPoint Energy Resources Corp. 76-0511406 (a Delaware corporation) 1111 Louisiana Houston, Texas 77002 (713) 207-1111 Securities registered pursuant to Section 12(b) of the Act: Registrant Title of each class Trading symbol(s) Name of each exchange on which registered CenterPoint Energy, Inc. Common Stock, $0.01 par value CNP New York Stock Exchange NYSE Texas CenterPoint Energy Houston Electric, LLC 6.95% General Mortgage Bonds due 2033 n/a New York Stock Exchange CenterPoint Energy Resources Corp. 6.625% Senior Notes due 2037 n/a New York Stock Exchange 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. CenterPoint Energy, Inc. Yes þ No o CenterPoint Energy Houston Electric, LLC Yes þ No o CenterPoint Energy Resources Corp. Yes þ No o Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. CenterPoint Energy, Inc. Yes o No þ CenterPoint Energy Houston Electric, LLC Yes o No þ CenterPoint Energy Resources Corp. Yes o No þ 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. CenterPoint Energy, Inc. Yes þ No o CenterPoint Energy Houston Electric, LLC Yes þ No o CenterPoint Energy Resources Corp. Yes þ No o 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). CenterPoint Energy, Inc. Yes þ No o CenterPoint Energy Houston Electric, LLC Yes þ No o CenterPoint Energy Resources Corp. Yes þ No o 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 CenterPoint Energy, Inc. þ o o ☐ ☐ CenterPoint Energy Houston Electric, LLC o o þ ☐ ☐ CenterPoint Energy Resources Corp. o o þ ☐ ☐ 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 Act. o 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. CenterPoint Energy, Inc. o CenterPoint Energy Houston Electric, LLC o CenterPoint Energy Resources Corp. o 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). CenterPoint Energy, Inc. o CenterPoint Energy Houston Electric, LLC o CenterPoint Energy Resources Corp. o Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). CenterPoint Energy, Inc. Yes ☐ No þ CenterPoint Energy Houston Electric, LLC Yes ☐ No þ CenterPoint Energy Resources Corp. Yes ☐ No þ The aggregate market values of the voting stock held by non-affiliates of the Registrants as of June 30, 2025 are as follows: CenterPoint Energy, Inc. (using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to Securities Exchange Act of 1934 and excluding shares held by directors and executive officers) $ 23,867,105,630 CenterPoint Energy Houston Electric, LLC None CenterPoint Energy Resources Corp. None Indicate the number of shares outstanding of each of the issuers’ classes of common stock as of February 13, 2026: CenterPoint Energy, Inc. 652,871,584 shares of common stock outstanding, excluding 166 shares held as treasury stock CenterPoint Energy Houston Electric, LLC 1,000 common shares outstanding, all held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc. CenterPoint Energy Resources Corp. 1,000 shares of common stock outstanding, all held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy, Inc. CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. meet the conditions set forth in general instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10-K. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement relating to the 2026 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2025, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K. GLOSSARY AFSI Adjusted financial statement income AFUDC Allowance for funds used during construction AI Artificial intelligence ALJ Administrative Law Judge AMAs Asset Management Agreements AMS Advanced Metering System Arevon Arevon Energy, Inc., which was formed through the combination of Capital Dynamics, Inc.’s U.S. Clean Energy Infrastructure business unit and Arevon Asset Management ARO Asset retirement obligation ARP Alternative revenue program ASC Accounting Standards Codification ASU Accounting Standards Update AT&T Common AT&T Inc. common stock ATM Forward Purchasers Bank of America, N.A., Barclays Bank PLC, Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, MUFG Securities EMEA plc and Royal Bank of Canada ATM Forward Sellers BofA Securities, Inc. Barclays Capital Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc. and RBC Capital Markets, LLC ATM Managers BofA Securities, Inc., Barclays Capital Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc. and RBC Capital Markets, LLC Bcf Billion cubic feet Board CenterPoint Energy’s Board of Directors Bond Companies Transition Bond Company IV, Restoration Bond Company II and Restoration Bond Company III, each a consolidated VIE that is a wholly-owned, bankruptcy-remote, special purpose entity formed solely for the purpose of securitizing transition property or system restoration property through the issuance of transition bonds or system restoration bonds BTA Build Transfer Agreement CAMT Corporate Alternative Minimum Tax CARES Act Coronavirus Aid, Relief, and Economic Security Act CCN Certificate of Convenience and Necessity CCR Coal Combustion Residuals CCR Rule Final rule published by the EPA in 2015 to regulate coal ash as non-hazardous material under the RCRA CECA Clean Energy Cost Adjustment CEIP CenterPoint Energy Intrastate Pipelines, LLC, a wholly-owned subsidiary of CERC Corp. CenterPoint Energy CenterPoint Energy, Inc., and its subsidiaries CenterPoint Energy Credit Agreement Second Amended and Restated Credit Agreement, dated December 6, 2022, by and among CenterPoint Energy, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, the financial institutions as bank parties thereto and the other parties thereto. CenterPoint Energy Extension Agreement Extension Agreement to the CenterPoint Energy Credit Agreement, dated January 29, 2025, by and among CenterPoint Energy, JPMorgan Chase Bank, N.A., as administrative agent, and the banks party thereto CEOH Vectren Energy Delivery of Ohio, LLC, doing business as CenterPoint Energy Ohio, which converted its corporate structure from Vectren Energy Delivery of Ohio, Inc. to an Ohio limited liability company on June 13, 2022, formerly a wholly-owned subsidiary of Vectren, acquired by CERC on June 30, 2022 CEP Capital Expenditure Program CERC CERC Corp., together with its subsidiaries CERC Credit Agreement Second Amended and Restated Credit Agreement, dated December 6, 2022, by and among CERC, as borrower, Wells Fargo Bank, National Association, as administrative agent, the financial institutions as bank parties thereto and the other parties thereto CERC Extension Agreement Extension Agreement to the CERC Credit Agreement, dated January 29, 2025, by and among CERC, Wells Fargo Bank, National Association, as administrative agent, and the banks party thereto CERC Corp. CenterPoint Energy Resources Corp. GLOSSARY CERCLA Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended Change in Control Plan CenterPoint Energy Change in Control Plan (as amended and restated effective May 1, 2017) Charter Common Charter Communications, Inc. common stock CIP Conservation Improvement Program Code The Internal Revenue Code of 1986, as amended CODM Chief Operating Decision Maker Common Stock CenterPoint Energy, Inc. common stock, par value $0.01 per share Convertible Notes CenterPoint Energy’s 4.25% Convertible Senior Notes due 2026 Convertible Notes Indenture Indenture dated as of August 4, 2023 by and between CenterPoint Energy and The Bank of New York Mellon Trust Company, National Association, as trustee, as supplemented COVID-19 Novel coronavirus disease 2019, and any mutations or variants thereof, and related global outbreak that was subsequently declared a pandemic by the World Health Organization CPCN Certificate of public convenience and necessity CPS Energy City Public Service Board of San Antonio, Texas Credit Agreements The CenterPoint Energy Credit Agreement, Houston Electric Credit Agreement, CERC Credit Agreement and SIGECO Credit Agreement CSIA Compliance and System Improvement Adjustment DCRF Distribution Cost Recovery Factor DOC U.S. Department of Commerce DOT U.S. Department of Transportation DRR Distribution Replacement Rider DSMA Demand Side Management Adjustment Dth Dekatherms ECA Environmental Cost Adjustment EDF Renewables EDF Renewables Development, Inc. EDIT Excess deferred income taxes EECR Energy Efficiency Cost Recovery EECRF Energy Efficiency Cost Recovery Factor EEFC Energy Efficiency Funding Component EEFR Energy Efficiency Funding Rider ELG Effluent Limitation Guidelines EIA U.S. Energy Information Administration Energy Systems Group Energy Systems Group, LLC, previously a wholly-owned subsidiary of Vectren EPA Environmental Protection Agency EPC Engineering, Procurement and Construction Equity Distribution Agreement Equity Distribution Agreement, dated as of January 10, 2024, by and between CenterPoint Energy, the ATM Managers, the ATM Forward Purchasers and the ATM Forward Sellers Equity Purchase Agreement Equity Purchase Agreement, dated as of May 21, 2023, by and between Vectren Energy Services and ESG Holdings Group ERCOT Electric Reliability Council of Texas ERCOT ISO ERCOT Independent System Operator ERISA Employee Retirement Income Security Act of 1974 ERO Electric Reliability Organization ESG Holdings Group ESG Holdings Group, LLC a Delaware limited liability company, and an affiliate of Oaktree Capital Management Exchange Act The Securities Exchange Act of 1934, as amended Extension Agreements The CenterPoint Energy Extension Agreement, Houston Electric Extension Agreement, CERC Extension Agreement and SIGECO Extension Agreement FAC Fuel Adjustment Clause FASB Financial Accounting Standards Board GLOSSARY February 2021 Winter Storm Event The extreme and unprecedented winter weather event in February 2021 (also known as Winter Storm Uri) resulting in electricity generation supply shortages, including in Texas, and natural gas supply shortages and increased wholesale prices of natural gas in the United States, primarily due to prolonged freezing temperatures. FERC Federal Energy Regulatory Commission Fitch Fitch Ratings, Inc. Form 10-K Annual Report on Form 10-K FPA Federal Power Act GAAP Generally Accepted Accounting Principles General Mortgage General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee, as supplemented from time to time GHG Greenhouse gases GRIP Gas Reliability Infrastructure Program GWh Gigawatt-hours HLPSA Hazardous Liquid Pipeline Safety Act of 1979 Houston Electric CenterPoint Energy Houston Electric, LLC and its subsidiaries Houston Electric Credit Agreement Second Amended and Restated Credit Agreement, dated December 6, 2022, by and among Houston Electric, as borrower, Mizuho Bank, Ltd., as administrative agent, the financial institutions as bank parties thereto and the other parties thereto Houston Electric Extension Agreement Extension Agreement to the Houston Electric Credit Agreement, dated January 29, 2025, by and among Houston Electric, Mizuho Bank, Ltd., as administrative agent, and the banks party thereto Human Capital and Compensation Committee Human Capital and Compensation Committee of the Board Hurricane Beryl The powerful and destructive storm that made landfall in Texas on July 8, 2024 and caused widespread damage to Houston Electric’s electric delivery system HVAC Heating, ventilation and air conditioning IAS International Accounting Standards IBEW International Brotherhood of Electrical Workers ICPA Inter-Company Power Agreement IDEM Indiana Department of Environmental Management IG Intelligent Grid Indiana Electric Operations of SIGECO’s electric transmission and distribution services, and includes its power generating and wholesale power operations Indiana Gas Indiana Gas Company, Inc., a wholly-owned subsidiary of CERC Corp. Indiana North Gas operations of Indiana Gas Indiana South Gas operations of SIGECO Indiana Utilities Indiana Electric, Indiana North and Indiana South, collectively IRA Inflation Reduction Act of 2022 IRP Integrated Resource Plan IRS Internal Revenue Service IURC Indiana Utility Regulatory Commission Junior Subordinated Notes Junior Subordinated Series A Notes, Junior Subordinated Series B Notes and Junior Subordinated Series C Notes Junior Subordinated Notes Indenture Junior Subordinated Indenture, dated as of August 14, 2024, between CenterPoint Energy and The Bank of New York Mellon Trust Company, National Association, as trustee, as supplemented Junior Subordinated Series A Notes 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series A, due 2055 Junior Subordinated Series B Notes 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series B, due 2055 Junior Subordinated Series C Notes 6.700% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series C, due 2055 kV Kilovolt LAMS Asset Purchase Agreement Asset Purchase Agreement, dated as of February 19, 2024, by and among CERC Corp. and the LAMS Buyers GLOSSARY LAMS Buyers Delta North Louisiana Gas Company, LLC, a Delaware limited liability company, Delta South Louisiana Gas Company, LLC, a Delaware limited liability company, Delta Mississippi Gas Company, LLC, a Delaware limited liability company, and Delta Energy Resources, LLC, a Delaware limited liability company LDC Local Distribution Company LNG Liquefied natural gas Load Shed Curtailing the amount of electricity a TDU can transmit and distribute to its customers LTIPs Long-term incentive plans M&DOT Mortgage and Deed of Trust, dated November 1, 1944, between Houston Lighting and Power Company and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented May 2024 Storm Events The sudden and destructive severe weather events in May 2024 that included hurricane-like winds and tornadoes and resulted in widespread damage to Houston Electric’s electric delivery system MCRA MISO Cost and Revenue Adjustment MDL Multi-district litigation MGP Manufactured gas plant MISO Midcontinent Independent System Operator MMBtu One million British thermal units MMcf Million cubic feet Moody’s Moody’s Investors Service, Inc. MPUC Minnesota Public Utilities Commission Mva Megavolt amperes MW Megawatts NAV Net asset value NECA National Electrical Contractors Association NERC North American Electric Reliability Corporation Netflix Netflix, Inc. NFGC National Fuel Gas Company, a New Jersey corporation NGA Natural Gas Act of 1938 NGLs Natural gas liquids NGPA Natural Gas Policy Act of 1978 NGPSA Natural Gas Pipeline Safety Act of 1968 NOLs Net operating losses NRG NRG Energy, Inc. NYSE New York Stock Exchange OBBBA Tax reform legislation informally known as the One Big Beautiful Bill Act Ohio Securities Purchase Agreement Securities Purchase Agreement, dated as of October 20, 2025, by and between CERC Corp. and NFGC OPEIU Office & Professional Employees International Union Oriden Oriden LLC Origis Origis Energy USA Inc. OUCC Indiana Office of Utility Consumer Counselor OVEC Ohio Valley Electric Corporation PHMSA Pipeline and Hazardous Materials Safety Administration PIPES Act Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 Posey Solar Posey Solar, LLC, a Delaware limited liability company PPA Power purchase agreement PRPs Potentially responsible parties PTCs Production Tax Credits PUCO Public Utilities Commission of Ohio PUCT Public Utility Commission of Texas GLOSSARY Railroad Commission Railroad Commission of Texas RCRA Resource Conservation and Recovery Act of 1976 Registrant Each of CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Reliant Energy Reliant Energy, Incorporated REP Retail electric provider Restoration Bond Company II CenterPoint Energy Restoration Bond Company II, LLC, a wholly-owned subsidiary of Houston Electric Restoration Bond Company II Securitization Bonds Restoration Bond Company II’s Series 2025-A Senior Secured System Restoration Bonds Restoration Bond Company III CenterPoint Energy Restoration Bond Company III, LLC, a wholly-owned subsidiary of Houston Electric Restructuring CERC Corp.’s common control acquisition of Indiana Gas and CEOH from VUH on June 30, 2022 ROE Return on equity ROU Right of use S&P S&P Global Ratings, a division of S&P Global Inc. Scope 1 emissions Direct source of GHG emissions from a company’s operations Scope 2 emissions Indirect source of GHG emissions from a company’s energy usage Scope 3 emissions Indirect source of GHG emissions from a company’s end-users SEC Securities and Exchange Commission Securities Act The Securities Act of 1933, as amended Securitization Bonds Transition and system restoration bonds issued by the Bond Companies and SIGECO Securitization Bonds issued by the SIGECO Securitization Subsidiary Seller Note Agreement Seller Note Agreement by and between CERC Corp. and NFGC to be entered into at the closing of the proposed sale of all of the issued and outstanding equity interests in CEOH to NFGC contemplated by the Ohio Securities Purchase Agreement Series A Preferred Stock CenterPoint Energy’s previously outstanding Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share Series 2025B Bonds SIGECO’s 5.09% First Mortgage Bonds, Series 2025B, Tranche A due 2031 and it’s 5.52% First Mortgage Bonds, Series 2025B, Tranche B due 2035 Series 2025C Bonds SIGECO’s 5.77% First Mortgage Bonds, Series 2025C, Tranche A due 2040 and it’s 6.18% First Mortgage Bonds, Series 2025C, Tranche B due 2055 SIGECO Southern Indiana Gas and Electric Company, a wholly-owned subsidiary of Vectren SIGECO Credit Agreement Credit Agreement, dated as of December 6, 2022, by and among SIGECO, as borrower, Wells Fargo Bank, National Association, as administrative agent, the financial institutions as banks parties thereto and the other parties thereto SIGECO Extension Agreement Extension Agreement to the SIGECO Credit Agreement, dated as of January 29, 2025, by and among SIGECO, Wells Fargo Bank, National Association, as administrative agent and the banks party thereto SIGECO Securitization Bonds SIGECO Securitization Subsidiary’s Series 2023-A Senior Secured Securitization Bonds SIGECO Securitization Subsidiary SIGECO Securitization I, LLC, a direct, wholly-owned subsidiary of SIGECO SOFR Secured Overnight Financing Rate SRC Sales Reconciliation Component SRP The transmission and distribution system resiliency plan filed by Houston Electric with the PUCT on January 31, 2025, which proposes investing approximately $5.75 billion over a three-year period for transmission and distribution infrastructure, information technology and cybersecurity assets and event response capability TBD To be determined TCA Texas Consumer Association TCJA Tax reform legislation informally called the Tax Cuts and Jobs Act of 2017 TCOS Transmission Cost of Service TCRF Transmission Cost Recovery Factor TDSIC Transmission, Distribution and Storage System Improvement Charge TDU Transmission and distribution utility GLOSSARY TEEEF Assets leased or costs incurred as “temporary emergency electric energy facilities” under Section 39.918 of the Public Utility Regulatory Act, also referred to as temporary generation TEEEF Rule Texas Administrative Code, Title 16, Section 25.56, which became effective January 8, 2025 and was further amended on February 6, 2025 Texas RE Texas Reliability Entity Transition Bond Company IV CenterPoint Energy Transition Bond Company IV, LLC, a wholly-owned subsidiary of Houston Electric TSA Transportation Security Administration USW United Steelworkers Union UWUA Utility Workers Union of America Utility Holding Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy Vectren Vectren, LLC, which converted its corporate structure from Vectren Corporation to a limited liability company on June 30, 2022, a wholly-owned subsidiary of CenterPoint Energy as of February 1, 2019, and, after the Restructuring, is held indirectly by CenterPoint Energy through Vectren Affiliated Utilities, Inc. Vectren Energy Services Vectren Energy Services Corporation, an Indiana corporation and a wholly-owned subsidiary of CenterPoint Energy VIE Variable interest entity Vistra Energy Corp. Texas-based energy company focused on the competitive energy and power generation markets. VRP Voluntary Remediation Program WBD Warner Bros. Discovery, Inc. WBD Common Warner Bros. Discovery, Inc. Series A common stock ZENS 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 ZENS-Related Securities As of December 31, 2025 and December 31, 2024, consisted of AT&T Common, Charter Common and WBD Common 2024 Form 10-K Annual Report on Form 10-K for the fiscal year ended December 31, 2024 2026 Convertible Notes CenterPoint Energy’s 4.25% Convertible Senior Notes due 2026 2026 Convertible Notes Indenture Indenture dated as of August 4, 2023 by and between CenterPoint Energy and The Bank of New York Mellon Trust Company, National Association, as trustee, as supplemented 2028 Convertible Notes CenterPoint Energy’s 3.00% Convertible Senior Notes due 2028 2028 Convertible Notes Indenture Indenture, dated as of July 31, 2025, by and between CenterPoint Energy and The Bank of New York Mellon Trust Company, National Association, as trustee TABLE OF CONTENTS PART I Page Item 1. Business 1 Item 1A. Risk Factors 19 Item 1B. Unresolved Staff Comments 44 Item 1C. Cybersecurity 44 Item 2. Properties 45 Item 3. Legal Proceedings 49 Item 4. Mine Safety Disclosures 49 PART II Item 5. Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 50 Item 6. [Reserved] 50 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 50 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 87 Item 8. Financial Statements and Supplementary Data 90 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 180 Item 9A. Controls and Procedures 180 Item 9B. Other Information 183 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 183 PART III Item 10. Directors, Executive Officers and Corporate Governance 183 Item 11. Executive Compensation 183 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 183 Item 13. Certain Relationships and Related Transactions, and Director Independence 183 Item 14. Principal Accounting Fees and Services 183 PART IV Item 15. Exhibits and Financial Statement Schedules 185 Item 16. Form 10-K Summary 185 i CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION From time to time the Registrants make statements concerning their expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “target,” “will” or other similar words. The Registrants have based their forward-looking statements on management’s beliefs and assumptions based on information reasonably available to management at the time the statements are made. The Registrants caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, the Registrants cannot assure you that actual results will not differ materially from those expressed or implied by the Registrants’ forward-looking statements. In this Form 10-K, unless context requires otherwise, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric, CERC and SIGECO. Some of the factors that could cause actual results to differ from those expressed or implied by the Registrants’ forward-looking statements are described under “Risk Factors” in Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” and “ — Liquidity and Capital Resources — Other Matters — Other Factors That Could Affect Cash Requirements” in Item 7 of Part II of this report, which discussions are incorporated herein by reference. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, other than as required under applicable securities laws, the Registrants undertake no obligation to update or revise any forward-looking statements. SUMMARY OF RISK FACTORS An investment in CenterPoint Energy’s securities involves a significant degree of risk. Below is a summary of certain risk factors to consider in evaluating CenterPoint Energy as well as its Common Stock. However, this list is not exhaustive. Before investing in CenterPoint Energy, carefully consider the risk factors discussed or referenced below and in Item 1A. “Risk Factors” of this combined report on Form 10-K. If any of the risks discussed below and in Item 1A. “Risk Factors” were actually to occur, CenterPoint Energy’s, Houston Electric’s and CERC’s business, financial condition, results of operations or cash flows could be adversely affected. In that case, CenterPoint Energy might not be able to pay dividends on its Common Stock, or the trading price of its Common Stock could decline. Risk Factors Affecting Operations Electric Transmission, Distribution and Generation (CenterPoint Energy and Houston Electric) • Disruptions at third-party or Indiana Electric’s power generation facilities, generation inadequacy, directives issued by regulatory authorities or other matters could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and Houston Electric and Indiana Electric may not be able to promptly respond, repair and restart their facilities, which could adversely affect their businesses, financial condition, results of operations and cash flows. • Indiana Electric’s execution of its generation transition plan is subject to various risks, including timely recovery of capital investments and increased costs and risks related to the timing and cost of development and/or construction of new generation facilities. • Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in payments of these receivables could adversely affect Houston Electric’s business, financial condition, results of operations and cash flows. • Houston Electric’s use of TEEEF is subject to various risks, potential performance issues and allegations about Houston Electric’s procurement and deployment of the resources (including the planning, execution and effectiveness of the same), regulatory and environmental requirements, and timely recovery of capital. ii Natural Gas (CenterPoint Energy and CERC) • Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for our natural gas business customers. • We are subject to fluctuations in natural gas prices, which could affect the ability of our suppliers and customers to meet their obligations or may impact our operations, which could adversely affect our business, financial condition, results of operations and cash flows. • Our natural gas businesses must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on our businesses, financial condition, results of operations and cash flows. Risk Factors Affecting Regulatory, Environmental and Legal Risks • Rate regulation of the Registrants’ electric and natural gas businesses may delay or deny their ability to earn an expected return and fully and timely recover their costs. • Our successful execution and completion of capital projects and programs, including those within our 10-year capital plan, are subject to substantial risks, and our business, financial condition, results of operations and cash flows could be materially affected should such efforts not be executed and completed as planned. • We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results. • Negative opinions of CenterPoint Energy from customers, investors, legislators, regulators, creditors, rating agencies and other stakeholders relating to actual or perceived system reliability and safety, the speed of our response to service interruptions, rates and customer affordability, our ability to successfully execute our capital plan, media coverage and actions by third parties, could harm our reputation and have an adverse impact on our business, financial condition, results of operations and cash flows. • We are subject to operational and financial risks and liabilities arising from environmental laws and regulations, including regulation of CCR, federal and state climate change legislation and regulation and certain local initiatives that seek to limit fossil fuel usage. • CenterPoint Energy is subject to operational and financial risks and liabilities associated with its sustainability and related activities, including the implementation of and efforts to achieve its energy transition goals. • We are subject to extensive regulation, which could result in higher costs for system improvements, as well as fines or other sanctions. Risk Factors Affecting Financial, Economic and Market Risks • Disruptions to the global supply chain, inflation, labor shortages and scarcity of certain materials may impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our business, financial condition, results of operations and cash flows. • If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures and operations or refinance outstanding indebtedness could be limited. • CenterPoint Energy is a holding company that derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries to meet its payment obligations and to pay dividends on its common stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions. • If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments may result in significant cash payments, which would adversely impact its cash flows and liquidity. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows and liquidity. Risk Factors Affecting Safety and Security Risks • The Registrants’ businesses have safety risks. • Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our business, financial condition, results of operations and cash flows. • We may not be successful in our adoption, development and deployment of AI, which could adversely affect our business, reputation or financial results. iii General and Other Risks • Our revenues and results of operations are seasonal. • Severe weather events, natural disasters and other climate-related impacts could adversely impact our businesses, financial condition, results of operations and cash flows. • We are exposed to risks related to changes in demand and energy consumption that could adversely impact our business, financial condition, results of operations and cash flows. • Our business, financial condition, results of operations and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions. • Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results. • Our businesses will continue to have to adapt to, implement and integrate technological change and may not be successful implementing such technological change as designed or may have to make significant investments to adapt to and integrate technological change. iv PART I Item 1. Business This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Information contained herein relating to any individual Registrant is filed by such Registrant solely on its own behalf. No Registrant makes any representation as to information relating to the other Registrants or the subsidiaries of CenterPoint Energy, Inc. other than itself or its subsidiaries. Except as discussed in Note 12 to the consolidated financial statements, no Registrant has an obligation in respect of any other Registrant’s debt securities, and holders of such debt securities should not consider the financial resources or results of operations of any Registrant other than the obligor in making a decision with respect to such securities. The discussion of CenterPoint Energy’s consolidated financial information includes the financial results of Houston Electric and CERC. Where appropriate, information relating to a specific Registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric and CERC, unless otherwise stated. OUR BUSINESS Overview CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems. As of December 31, 2025, CenterPoint Energy’s indirect, wholly-owned operating subsidiaries included: • Houston Electric, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston. • CERC Corp., which (i) directly owns and operates natural gas distribution systems in Minnesota and Texas, (ii) indirectly, through Indiana Gas and CEOH, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and • SIGECO, which provides energy delivery services to electric and natural gas customers located in and near Evansville in southwestern Indiana and owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. As of December 31, 2025, CenterPoint Energy’s reportable segments were Electric, Natural Gas and Corporate and Other. Houston Electric and CERC each consist of one reportable segment. For a description of CenterPoint Energy’s reportable segments, see Note 16. For a discussion of net income by segment, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations by Reportable Segment” in Item 7 of Part II of this report. On March 7, 2025, SIGECO acquired 100% of the equity interests in Posey Solar, which was constructing a 191 MW solar array in Posey County, Indiana, for approximately $357 million. On March 31, 2025, CenterPoint Energy, through its subsidiary CERC Corp., completed the sale of its Louisiana and Mississippi natural gas LDC businesses for approximately $1.2 billion. On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement to sell all of the issued and outstanding equity interests in CEOH for total consideration of approximately $2.62 billion, which is comprised of the following: (i) $1.42 billion in cash payable to CERC Corp. upon closing of the transaction, subject to adjustments as set forth in the Ohio Securities Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing of the transaction; and (ii) a 364-day seller promissory note, in the original principal amount of $1.2 billion, to be issued by NFGC at the closing of the transaction and payable to CERC Corp. as provided by the terms and conditions of the Seller Note Agreement. The transaction is expected to close in the fourth quarter of 2026, subject to the satisfaction of customary closing conditions. For further information, see Note 4 to the consolidated financial statements. The Registrants’ principal executive offices are located at 1111 Louisiana Street, Houston, Texas 77002 (telephone number: 713-207-1111). 1 We make available free of charge on CenterPoint Energy’s internet website, http://www.centerpointenergy.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, we make available free of charge on CenterPoint Energy’s internet website: • our Code of Ethics for our Chief Executive Officer and Senior Financial Officers; • our Ethics and Compliance Code; • our Supplier Code of Conduct; • our Corporate Governance Guidelines; and • the charters of the Audit, Corporate Governance and Nominating, Human Capital and Compensation, and Safety and Operations committees of our Board. Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our internet website within five business days of such change or waiver and maintained for at least 12 months or timely reported on Item 5.05 of Form 8-K. Investors should also note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the investor relations section of our internet website to communicate with our investors. It is possible that the financial and other information posted there could be deemed to be material information. Except to the extent explicitly stated herein, documents and information on our internet website are not incorporated by reference herein. Electric (CenterPoint Energy) The Electric reportable segment is comprised of Houston Electric and Indiana Electric. For information regarding the properties of the Electric reportable segment, see “Properties — Electric (CenterPoint Energy and Houston Electric)” in Item 2 of this report, which information is incorporated herein by reference. Houston Electric (CenterPoint Energy and Houston Electric) Houston Electric is a transmission and distribution electric utility that operates wholly within the state of Texas. Houston Electric does not make direct retail or wholesale sales of electric energy or own or operate any power generating facilities other than TEEEF. Electric Transmission On behalf of REPs, Houston Electric delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kV in locations throughout Houston Electric’s certificated service territory. Houston Electric constructs and maintains transmission facilities and provides transmission services under tariffs approved by the PUCT. Electric Distribution Houston Electric’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer through distribution feeders. Houston Electric’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. Houston Electric provides distribution services under tariffs approved by the PUCT. PUCT rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT. 2 TEEEF As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric has entered into contractual arrangements to facilitate access to TEEEF units, both on a long-term basis and, to a limited extent, on a month-to-month basis, that can aid in restoring power to customers during certain significant power outages that are impacting its distribution system. In June 2025, Houston Electric entered into definitive documentation (the “ERCOT Transaction”), subject to PUCT approval, with relevant parties to release its 15 large 27 MW to 32 MW TEEEF units to the San Antonio area until March 2027 unless terminated earlier pursuant to the provisions of the ERCOT Transaction, during which Houston Electric will not receive revenue or profit from ERCOT and will also not charge Houston-area customers for these TEEEF units while they are in the San Antonio area serving ERCOT. In November 2025, Houston Electric proposed to release its five medium (5.7 MW) TEEEF units and to remove the associated lease costs from its rates effective January 1, 2026. On February 13, 2026, Houston Electric requested continued abatement until February 27, 2026 due to continued settlement discussions. As of December 31, 2025, Houston Electric leased 519 MW of TEEEF on a long-term basis. For more information, see Note 7 and Note 19 to the consolidated financial statements. Bond Companies Houston Electric has VIEs, including Transition Bond Company IV and Restoration Bond Company II, which are consolidated. The consolidated VIEs are wholly-owned, bankruptcy-remote, special purpose entities that were formed solely for the purpose of securitizing transition property or system restoration property through the issuance of transition bonds or system restoration bonds, and conducting activities incidental thereto. The Securitization Bonds are repaid through charges imposed on customers in Houston Electric’s service territory. On October 15, 2024, Transition Bond Company IV repaid in full its last outstanding transition bonds at maturity. For further discussion of the Securitization Bonds and the outstanding balances as of December 31, 2025 and 2024, see Note 12 to the consolidated financial statements. Customers Houston Electric serves nearly all of the Houston/Galveston metropolitan area near the Texas Gulf Coast. Houston Electric’s customers consist of REPs, which sell electricity to metered customers in Houston Electric’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside Houston Electric’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the PUCT. Houston Electric does not have long-term contracts with any of its customers, but rather operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day. For information regarding Houston Electric’s major customers, see Note 16 to the consolidated financial statements. The table below reflects the number of REPs and metered customers in Houston Electric’s service area as of December 31, 2025: REPs Residential Commercial/ Industrial Total Customers Texas Gulf Coast 67 2,544,880 314,433 2,859,313 Competition There are no other electric transmission and distribution utilities in Houston Electric’s service area. For another provider of transmission and distribution services to provide such services in Houston Electric’s territory, it would be required to obtain a CCN from the PUCT and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. Houston Electric is not aware of any other party intending to enter this business in its service area at this time. Distributed generation (i.e., power generation located at or near the point of consumption) could result in a reduction of demand for Houston Electric’s distribution services but has not been a significant factor to date. Seasonality Houston Electric’s revenues are primarily derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of that REP. Houston Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months when more electricity is used for cooling purposes. 3 Franchises Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 40 years. Indiana Electric (CenterPoint Energy) Indiana Electric consists of SIGECO’s electric transmission and distribution services, including its electric generation assets and wholesale power operations. The table below reflects the number of metered customers to whom Indiana Electric supplied electric service as of December 31, 2025: Residential Commercial/Industrial Total Customers Southwestern Indiana 134,695 19,707 154,402 System Load Total load and the related reserve margin at the time of the system summer peak on June 25, 2025 is presented below in MW, except for reserve margin at peak: 2025 Total load at peak 1,073 Generating capability 1,071 Purchase supply (effective capacity) (1) 263 Interruptible contracts & direct load control 14 Total power supply capacity 1,348 Reserve margin at peak 26 % (1) Total reflects long-term and short-term capacity contracts secured to meet MISO planning requirements. The winter peak load for the 2024-2025 season of approximately 849 MW occurred on January 21, 2025. Solar and Wind Indiana Electric has entered into various PPAs to purchase solar power and wind power to meet its future generation needs as reported in the table below: Power Type Counterparty Location Date in Service/Expected Date in Service Capacity (MW) Term (in Years) Wind NextEra Energy, Inc. Tama County, Iowa 2025 170 27 Solar Origis Knox County, Indiana 2026 150 20 Wind NextEra Energy, Inc. Knox County, Illinois 2026 147 25 467 For further information about Indiana Electric’s solar power and wind power activities, see “Item 2. Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. Coal Purchases Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Major suppliers are those that account for greater than 10% of Indiana Electric’s coal purchases. For the year ended December 31, 2025, Sunrise LLC accounted for 100% of Indiana Electric’s coal purchases. 4 The table below presents information related to coal purchases during the year ended December 31, 2025 and coal inventory as of December 31, 2025: (In tons, except average cost per ton) Coal purchased for generating electricity 643,030 Coal inventory as of December 31, 2025 422,503 Average cost of coal per ton $68.04 Firm Purchase Supply Indiana Electric enters into long-term purchase supply agreements to meet its generation needs as disclosed below: Fuel Type Provider Location Contract Expiration Capacity (MW) Purchased in 2025 (in GWh) Coal OVEC (1) Indiana and Ohio 2040 32 203 Wind Benton County Wind Farm, LLC Benton County, Indiana 2028 30 81 Wind Fowler Ridge II Wind Farm, LLC Benton/Tippecanoe Counties, Indiana 2029 50 129 Wind Salt Creek Wind, LLC Tama County, Iowa 2052 170 52 282 465 (1) As part of its power portfolio, Indiana Electric is a 1.5% shareholder in the OVEC. Based on its participation in the ICPA between OVEC and its shareholder companies, Indiana Electric has the right to 1.5% of OVEC’s generating capacity output and shares in 1.5% of the operating expenses and debt obligations of OVEC. MISO-Related Activity Indiana Electric is a member of the MISO, a FERC-approved regional transmission organization. The MISO serves the electric transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission facilities and generation facilities as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing as determined by the MISO market. MISO-related purchase and sale transactions are recorded using settlement information provided by the MISO. These purchase and sale transactions are accounted for on at least a net hourly position. MISO-related activity for the year ended December 31, 2025 was as follows: In GWh Net purchases (1) 3,007 Net sales (2) 2 (1) Represents intervals when purchases from the MISO were in excess of generation sold to the MISO. (2) Represents intervals when sales to the MISO were in excess of purchases from the MISO. Interconnections As of December 31, 2025, Indiana Electric had interconnections with Louisville Gas and Electric Company, Duke Energy Shared Services, Inc., Indianapolis Power & Light Company, Hoosier Energy Rural Electric Cooperative, Inc. and Big Rivers Electric Corporation providing the ability to simultaneously interchange approximately 660 MW during peak load periods. Indiana Electric, as required as a member of the MISO, has turned over operational control of the interchange facilities and its own transmission assets to the MISO. Indiana Electric, in conjunction with the MISO, must operate the bulk electric transmission system in accordance with NERC Reliability Standards. As a result, interchange capability varies based on regional transmission system configuration, generation dispatch, seasonal facility ratings and other factors. Indiana Electric is in compliance with reliability standards promulgated by NERC. 5 SIGECO Securitization Subsidiary SIGECO has a VIE, SIGECO Securitization Subsidiary, which is consolidated. This consolidated VIE is a wholly-owned, bankruptcy-remote, special purpose entity that was formed solely for the purpose of facilitating the securitization financing of qualified costs. The obligations of the SIGECO Securitization Bonds are repaid through charges imposed on customers in Indiana Electric’s service territory. For further discussion of the SIGECO Securitization Bonds and the outstanding balance as of December 31, 2025, see Note 12 to the consolidated financial statements. Competition There are no other electric transmission and distribution utilities in Indiana Electric’s service area. Indiana Electric is a vertically integrated utility that owns the generation, transmission, and distribution components of a utility. For another provider of transmission and distribution services to provide such services in Indiana Electric’s territory, it would be required to obtain IURC approval of such service territory. Indiana service territory certificates are exclusive. Distributed generation (i.e., power generation located at or near the point of consumption) could result in reduced demand for Indiana Electric’s distribution services but has not been a significant factor to date. Seasonality Indiana Electric’s revenues are primarily derived from rates that it collects from customers in its service territory based on the amount of electricity it delivers. Indiana Electric’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months when more electricity is used for cooling purposes, and during the cooler months when more electricity is used for heating purposes. Natural Gas (CenterPoint Energy and CERC) CenterPoint Energy’s and CERC’s natural gas distribution businesses engage in regulated intrastate natural gas sales to, and natural gas transportation and storage for, residential, commercial, industrial and transportation customers. CenterPoint Energy’s and CERC’s natural gas distribution businesses provide permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP. CenterPoint Energy’s and CERC’s natural gas distribution businesses also provided services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales. Additionally, CenterPoint Energy and CERC’s natural gas distribution businesses provided home repair protection plans to natural gas customers in Indiana, Ohio and Texas through a third party as of December 31, 2025. For information regarding the properties of the Natural Gas reportable segment, read “Properties — Natural Gas (CenterPoint Energy and CERC)” in Item 2 of this report, which information is incorporated herein by reference. On March 31, 2025, CenterPoint Energy, through its subsidiary CERC Corp., completed the sale of its Louisiana and Mississippi natural gas LDC businesses. On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement to sell all of the issued and outstanding equity interests in CEOH for total consideration of approximately $2.62 billion, which is comprised of the following: (i) $1.42 billion in cash payable to CERC Corp. upon closing of the transaction, subject to adjustments as set forth in the Ohio Securities Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing of the transaction; and (ii) a 364-day seller promissory note, in the original principal amount of $1.2 billion, to be issued by NFGC at the closing of the transaction and payable to CERC Corp. as provided by the terms and conditions of the Seller Note Agreement. The transaction is expected to close in the fourth quarter of 2026, subject to the satisfaction of customary closing conditions. For further information, see Note 4 to the consolidated financial statements. 6 Customers The table below reflects the number of CenterPoint Energy’s and CERC’s natural gas distribution business customers by state as of December 31, 2025: Residential Commercial/ Industrial/Transportation Total Customers Indiana (Indiana Gas) 613,299 55,996 669,295 Minnesota 865,667 73,063 938,730 Ohio 312,131 24,711 336,842 Texas 1,843,325 124,730 1,968,055 Total CERC Natural Gas 3,634,422 278,500 3,912,922 Indiana (SIGECO) 105,497 10,666 116,163 Total CenterPoint Energy Natural Gas 3,739,919 289,166 4,029,085 The largest metropolitan areas served in each state were Houston, Texas; Minneapolis, Minnesota; Evansville, Indiana; and Dayton, Ohio. The table below reflects the percentage of total throughput by customer type for the year ended December 31, 2025: CenterPoint Energy CERC Residential 34 % 36 % Commercial/Industrial and Transportation 66 % 64 % Total Throughput 100 % 100 % Seasonality The demand for natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal and affected by variations in weather conditions. In 2025, approximately 68% and 69% of the total throughput for CenterPoint Energy’s and CERC’s natural gas distribution businesses, respectively, occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during the colder months. Supply and Transportation In 2025, CenterPoint Energy’s natural gas distribution businesses purchased virtually all of their natural gas supply pursuant to contracts with remaining terms varying from a few months to three years. Major suppliers are those that account for greater than 10% of CenterPoint Energy’s or CERC’s annual natural gas supply purchases. Major suppliers of natural gas for the year ended December 31, 2025 were as follows: CenterPoint Energy CERC Tenaska Marketing Ventures, LLC 32 % 30 % Macquarie Energy, LLC 12 % 13 % BP Energy Company 8 % 8 % Total of major suppliers 52 % 51 % Numerous other suppliers provided the remainder of CenterPoint Energy’s and CERC’s natural gas supply requirements. CenterPoint Energy’s and CERC’s natural gas distribution businesses transport their natural gas supplies through various intrastate and interstate pipelines under contracts with remaining terms, including extensions, varying from one to fifteen years. CenterPoint Energy’s and CERC’s natural gas distribution businesses anticipate that these gas supply and transportation contracts will be renewed or replaced prior to their expiration. CenterPoint Energy’s and CERC’s natural gas distribution businesses actively engage in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of their state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless 7 collars and caps) with CenterPoint Energy’s and CERC’s natural gas distribution business’ physical gas suppliers. Their gas supply plans generally call for 50–70% of normal winter supplies to be stabilized in some fashion. The regulations of the states in which CenterPoint Energy’s and CERC’s natural gas distribution businesses operate allow them to pass through changes in the cost of natural gas, including savings and costs of financial derivatives associated with the index-priced physical supply, to their customers under purchased gas adjustment provisions in their tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies. CenterPoint Energy’s and CERC’s natural gas distribution businesses use various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. CenterPoint Energy’s and CERC’s natural gas distribution businesses may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production. On an ongoing basis, CenterPoint Energy’s and CERC’s natural gas distribution businesses enter into contracts to provide sufficient supplies and pipeline capacity to meet their customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors. CenterPoint Energy’s and CERC’s natural gas distribution businesses continue to utilize AMAs associated with their utility distribution service in Indiana, Minnesota and Texas. Generally, AMAs are contracts between CenterPoint Energy’s and CERC’s natural gas distribution businesses and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, CenterPoint Energy’s and CERC’s natural gas distribution businesses agree to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for CenterPoint Energy’s and CERC’s natural gas distribution businesses and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s natural gas distribution businesses. CenterPoint Energy’s and CERC’s natural gas distribution businesses may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s natural gas distribution businesses have an obligation to purchase their winter storage requirements that have been released to the asset manager under these AMAs. The AMAs have varying terms, the longest of which expires in 2029. Pursuant to the provisions of the agreements, CenterPoint Energy’s and CERC’s natural gas distribution businesses either sell natural gas to the asset manager and agree to repurchase an equivalent amount of natural gas throughout the year at the same cost, or simply purchases its full natural gas requirements at each delivery point from the asset manager. Each of CenterPoint Energy and CERC had no amounts outstanding under these AMAs as of December 31, 2025 and 2024. Competition CenterPoint Energy’s and CERC’s natural gas distribution businesses compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CenterPoint Energy’s and CERC’s natural gas distribution business’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Franchises In almost all communities in which CenterPoint Energy’s and CERC’s natural gas distribution businesses provide natural gas distribution services, they operate under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years. CenterPoint Energy’s and CERC’s natural gas distribution businesses expect to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Corporate and Other (CenterPoint Energy) CenterPoint Energy’s Corporate and Other reportable segment consists of corporate support operations that support CenterPoint Energy’s business operations and also includes office buildings and other real estate used for business operations. CenterPoint Energy’s Corporate and Other reportable segment also consisted of energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group. For additional information on the sale of Energy Systems Group, see Note 4 to the consolidated financial statements. 8 REGULATION The Registrants are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. The following discussion is based on regulation in the Registrants’ businesses as of December 31, 2025. Federal Energy Regulatory Commission FERC has jurisdiction under the NGA and the NGPA, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. FERC also regulates the transmission and wholesale sales of electricity in interstate commerce, mergers, acquisitions and corporate transactions by electricity companies, energy markets, reliability standards and the issuance of short-term debt by public utilities regulated by FERC. FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions, to conduct audits and investigations, and to impose significant civil penalties (up to approximately $1.6 million per day per violation, subject to periodic adjustment to account for inflation) for statutory violations and violations of the FERC’s rules or orders. Indiana Electric is a “public utility” under the FPA and is subject to regulation by FERC. Houston Electric is not a “public utility” under the FPA and, therefore, is not generally regulated by FERC, although certain of its transactions are subject to limited FERC jurisdiction. FERC has certain responsibilities with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT. FERC has designated NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. The ERO and FERC have authority to (a) impose fines and other sanctions on applicable entities that fail to comply with approved standards and (b) audit compliance with approved standards. FERC has approved the delegation by NERC of authority for reliability in ERCOT to the Texas RE and in MISO to ReliabilityFirst Corporation. Neither Houston Electric nor Indiana Electric anticipate that the reliability standards proposed by NERC and approved by FERC will have a material adverse impact on their operations. To the extent that Houston Electric and Indiana Electric are required to make additional expenditures to comply with these standards, it is anticipated that Houston Electric and Indiana Electric will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT and the MISO, respectively, for electric transmission provided. The FPA also provides that, whenever the Secretary of the U.S. Department of Energy determines that an emergency exists by reason of a sudden increase in the demand for electric energy, or a shortage of electric energy or of facilities for the generation or transmission of electric energy, then the Secretary of the U.S. Department of Energy has the authority to require by order such temporary connections of facilities and such generation, delivery, interchange or transmission of electric energy as in the Secretary’s judgment will best meet the demands of the emergency and serve the public interest. As a public utility holding company, under the Public Utility Holding Company Act of 2005, CenterPoint Energy and its consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by FERC and state regulatory authorities in certain circumstances. For a discussion of the Registrants’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. 9 State and Local Regulation – Electric Transmission & Distribution (CenterPoint Energy and Houston Electric) Houston Electric is a member of ERCOT, which serves as the independent system operator and regional reliability coordinator for member electric power systems in most of Texas. The ERCOT market represents approximately 90% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market operates under the reliability standards developed by NERC, approved by FERC and monitored and enforced by the Texas RE. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. The ERCOT ISO is responsible for operating the bulk electric power supply system in the ERCOT market. Houston Electric’s transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. Houston Electric participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid. Houston Electric conducts its operations pursuant to a CCN issued by the PUCT that covers its present service area and facilities. The PUCT and certain municipalities have the authority to set the rates and terms of service provided by Houston Electric under cost-of-service rate regulation. Houston Electric holds non-exclusive franchises from certain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give Houston Electric the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 40 years. In ERCOT, end users purchase their electricity directly from certificated REPs. Houston Electric’s distribution rates charged to REPs for residential and small commercial customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of large commercial and industrial customers are primarily based on peak demand. All REPs in Houston Electric’s service area pay the same rates and other charges for transmission and distribution services. This regulated delivery charge may include the transmission and distribution rate (which includes municipal franchise fees), a DCRF mechanism for recovery of incremental distribution-invested capital above that which is already reflected in the base distribution rate, a TEEEF mechanism for recovery of costs associated with leasing and operating certain TEEEF, a TCRF mechanism for recovery of approved wholesale transmission cost changes billed by a transmission service provider, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, an EECRF charge, and charges associated with securitization of regulatory assets, stranded costs and restoration costs. Transmission rates charged to distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay Houston Electric the same rates and other charges for transmission services. With the IURC’s approval, Indiana Electric is a member of the MISO, a FERC-approved regional transmission organization. The MISO serves the electrical transmission needs of much of the Midcontinent region and maintains operational control over Indiana Electric’s electric transmission and generation facilities as well as those of other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, bidding its owned generation into the Day Ahead and Real Time markets and procuring power for its retail customers at Locational Marginal Pricing as determined by the MISO market. Indiana Electric also receives transmission revenue that results from other members’ use of Indiana Electric’s transmission system. Generally, these transmission revenues, along with costs charged by the MISO, are considered components of base rates and any variance from that included in base rates is recovered from or refunded to retail customers through tracking mechanisms. For a discussion of certain of Houston Electric’s and Indiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. State and Local Regulation – Electric Generation (CenterPoint Energy) The energy and capacity secured from Indiana Electric’s available generation resources are utilized primarily to serve the needs of retail electric customers residing within Indiana Electric’s franchised service territory. The expenses and capital investments associated with operating Indiana Electric’s generation facilities are recovered through IURC-approved base rates as well as periodic rate recovery mechanisms including the CECA, ECA, FAC, MCRA, and RCRA mechanism. Costs that are deemed unreasonable or imprudent by the IURC may not be recoverable through retail electric rates. Indiana Electric also receives revenues from the MISO to compensate it for benefits the generation facilities provide to the transmission system. 10 Proceeds from the sales of energy from Indiana Electric’s generation facilities that exceed the requirements of retail customers are provided to retail electric customers. The generation facilities owned and operated by Indiana Electric are subject to various environmental regulations enforced by the EPA and the IDEM. Operations of Indiana Electric’s generation facilities are subject to regulation by the EPA and the IDEM as it pertains to water quality, waste disposal and air emissions from the generation facilities. For further discussion, see “Our Business — Environmental Matters” below. For a discussion of Indiana Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. State and Local Regulation – Natural Gas (CenterPoint Energy and CERC) In almost all communities in which CenterPoint Energy’s and CERC’s natural gas distribution businesses provide natural gas distribution services, they operate under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years. CenterPoint Energy’s and CERC’s natural gas distribution businesses expect to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Substantially all of CenterPoint Energy’s and CERC’s natural gas distribution businesses are subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by those municipalities that have retained original jurisdiction. In certain of the jurisdictions in which they operate, CenterPoint Energy’s and CERC’s natural gas distribution businesses have annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital or actual margins realized. For a discussion of certain of CenterPoint Energy’s and CERC’s natural gas distribution businesses’ ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. Department of Transportation (CenterPoint Energy and CERC) CenterPoint Energy and CERC are subject to regulation by PHMSA under the NGPSA and the HLPSA. The NGPSA delegated to PHMSA through DOT the authority to regulate gas pipelines. The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Every four years PHMSA is up for reauthorization by the U.S. Congress and with that reauthorization comes changes to the legislative requirements that the U.S. Congress sets forth for the oversight of natural gas and hazardous liquid pipelines. In 2020, the PIPES Act was enacted. The PIPES Act reauthorized PHMSA through 2023 and imposed a few new mandates on the agency. The law establishes a PHMSA technology pilot, authorizes a new idled pipe operating status and contains process protections for operators during PHMSA enforcement proceedings. Section 114 of the PIPES Act is a self-mandating rule for natural gas pipeline operations like CERC’s that focuses on processes and procedures to eliminate or reduce emissions during normal operations. Further, Section 113 of the PIPES Act directed PHMSA to develop regulations to require natural gas pipeline operators to implement leak detection and repair programs, as well as requirements for mitigating emissions in operations. The PIPES Act of 2023 was approved by the House Transportation and Infrastructure Committee on December 6, 2023 to reauthorize PHMSA’s safety programs for the next four years. Final versions of the Section 113 Leak Detection and Repair, and Safety of Natural Gas Distribution Pipelines, 2020 PIPES Act rules remain frozen until a Department of Transportation appointee can review and proceed further. In January 2021, PHMSA published a final rule amending the federal Pipeline Safety Regulations to ease regulatory burdens on the construction, operation, and maintenance of gas transmission, distribution, and gathering systems. CenterPoint Energy and CERC anticipate that compliance with PHMSA’s regulations, performance of the remediation activities by CenterPoint Energy’s and CERC’s natural gas distribution businesses and intrastate pipelines, and verification of records on maximum allowable operating pressure will continue to require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. In particular, the cost of compliance with the DOT’s integrity management rules will depend on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such 11 procedures outside of those defined areas, may also affect the costs incurred. Implementation by PHMSA of the PIPES Act, in particular the final rule implementing Section 113, acts reauthorizing PHMSA or other future acts may result in other regulations or the reinterpretation of existing regulations that could impact compliance costs. In addition, CenterPoint Energy and CERC may be subject to the DOT’s enforcement actions and penalties if they fail to comply with pipeline regulations. ENVIRONMENTAL MATTERS The following discussion is based on environmental matters in the Registrants’ businesses as of December 31, 2025. The Registrants’ operations are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric transmission and distribution systems, steam electric and renewable generation systems and the facilities that support these systems, the Registrants must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact the Registrants’ business activities in many ways, including, but not limited to: • restricting the way the Registrants can handle or dispose of wastes, including wastewater discharges and air emissions; • limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited by endangered species; • requiring remedial action and monitoring to mitigate environmental conditions caused by the Registrants’ operations or attributable to former operations; • enjoining the operations of facilities with permits issued pursuant to such environmental laws and regulations; and • impacting the demand for the Registrants’ services by directly or indirectly affecting the use or price of fossil fuels, including, but not limited to, natural gas. To comply with these requirements, the Registrants may need to spend substantial amounts and devote other resources from time to time to, among other activities: • construct or acquire new facilities and equipment; • acquire permits for facility operations or purchase emissions allowances; • modify, upgrade or replace existing and proposed equipment; and • decommission or remediate waste management areas, fuel storage facilities and other locations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions and monitoring and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to assess, clean up and restore sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and/or property damage allegedly caused by the release of hazardous substances or other waste products into the environment. Our obligations associated with these requirements change as administrations change and as legislatures and regulators pass new laws and regulations and amend existing ones. Therefore, it is difficult to project future costs of compliance and their impact on competition. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and monitoring, and actual future expenditures may be different from the amounts currently anticipated. The Registrants try to anticipate future regulatory requirements that might be imposed and plan accordingly to maintain compliance with changing environmental laws and regulations. Based on current regulatory requirements and interpretations, the Registrants do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on their business, financial position, results of operations or cash flows. In addition, the Registrants believe that their current environmental remediation activities will not materially interrupt or diminish their operational ability. The Registrants cannot provide assurances that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause them to incur significant costs. The following is a discussion of material current environmental issues, laws and regulations that relate to the Registrants’ operations. The Registrants believe that they are in substantial compliance with these environmental laws and regulations. GHG Emissions and Climate Change-Related Regulation and Compliance (CenterPoint Energy) The issue of climate change has received focus at the state, federal and international level. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG and other climate change-related matters on the state, federal or international level. On 12 January 20, 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement (which took effect on January 27, 2026), marking a significant shift in U.S. climate policy; on January 7, 2026, it was announced that the United States will withdraw from the United Nations Framework Convention on Climate Change, a treaty that underpins international efforts on global climate; and on February 12, 2026, the EPA announced the finalization of a rule repealing the Endangerment Finding (defined below) as it relates to new motor vehicles. Accordingly, our obligations associated with GHG emissions and climate change-related matters change as administrations change and as legislatures and regulators pass new laws and regulations and amend existing ones. The EPA released its initial GHG regulation for fossil fuel-fired electric generating units in 2015. In April 2024, the EPA finalized the current New Source Performance Standards for Greenhouse Gas Emissions from New, Modified, Reconstructed Fossil Fuel-Fired Units; and Repeal of the Affordable Clean Energy Rule, which applies new GHG performance standards for those existing coal-fired power plants expected to continue operation beyond December 31, 2029. The rule is currently being challenged by a variety of stakeholders in litigation before the Circuit Court of Appeals for the D.C. Circuit. In October 2024, the U.S. Supreme Court declined to stay the implementation of the rule while the rule is on judicial review. However, on June 17, 2025, the EPA proposed a rule to repeal GHG emission standards for fossil fuel-fired electric generating units, or in the alternative, to repeal a narrower set of requirements, including the emission guidelines for existing fossil fuel-fired steam electric generating units, the carbon capture and sequestration/storage (CCS)-based standards for coal-fired steam generating units undertaking a large modification and the CCS-based standards for new base load stationary combustion turbines. Additionally, the IRA established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from certain natural gas transmission facilities, the rules for which were finalized on November 18, 2024. However, on March 14, 2025, President Trump signed a Congressional Review Act resolution disapproving the EPA’s final rule, thereby prohibiting the rule from taking effect, and the OBBBA postponed the imposition of the methane emissions charge to 2034. On September 16, 2025, the EPA proposed a rule to end the Greenhouse Gas Reporting Program (“GHGRP”) for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposed rule). Reporting for petroleum and natural gas systems under the GHGRP would be deferred until 2034 under the proposal. On February 12, 2026, the EPA announced the repeal of the 2009 “Endangerment Finding” under the Clean Air Act, which found that GHG emissions endanger the public health and welfare of current and future generations and that emissions of GHGs from motor vehicles contribute to GHG pollution. The repeal calls into question the EPA’s authority to regulate GHG emissions, as well as the EPA’s prior scientific assessment of climate change risks. Litigation regarding the repeal is anticipated and it is unclear how the repeal will impact the EPA’s regulation of GHG emissions going forward. On March 6, 2024, the SEC adopted final rules to require disclosure of certain climate-related information in registration statements and annual reports. Litigation challenging the rule was filed by multiple parties in multiple jurisdictions, which have been consolidated and assigned to the U.S. Court of Appeals for the Eighth Circuit. On September 12, 2025, the U.S. Court of Appeals issued an order to hold the petitions challenging the climate disclosure rules in abeyance pending further action by the SEC. CenterPoint Energy has adopted energy transition goals. Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 emissions estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 emissions estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. These energy transition goals are expected to be used to position CenterPoint Energy to comply with regulatory requirements from any future administrations to further reduce GHG emissions. For more information regarding CenterPoint Energy’s energy transition goals and their related risks, see “Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks ...” CenterPoint Energy’s energy transition goals are aligned with Indiana Electric’s generation transition plan and are expected to position Indiana Electric to comply with future regulatory requirements related to GHG emissions reductions. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than through TEEEF, and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that burn fossil fuels to generate electricity. Nevertheless, Houston Electric’s and Indiana Electric’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within their respective service territories. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Registrants’ services. Further, our third-party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact CenterPoint Energy’s business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to CenterPoint Energy. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics relative to other fossil fuels would be expected to benefit CenterPoint Energy and CERC and their natural gas-related businesses. At this time, however, we cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Registrants’ businesses. 13 Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. Significant changes in policy due to administration change can create regulatory uncertainty. For example, the repeal of the Endangerment Finding could lead to a patchwork of conflicting state superfund laws and state regulation relating to climate change and GHG emissions. Although the amount of compliance costs remains uncertain, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. For example, CenterPoint Energy’s and CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or would have the effect of reducing the consumption of natural gas. While the requirements of a federal or state rule remain uncertain, CenterPoint Energy will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, CenterPoint Energy does not purchase carbon credits. In connection with its energy transition goals, CenterPoint Energy expects to purchase carbon credits in the future; however, CenterPoint Energy does not currently expect the number of credits, or cost for those credits, to be material. Air Emissions The Registrants’ operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including electric generating facilities and natural gas processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions. The Registrants may be required to obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. The Registrants may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. Water Discharges The Registrants’ operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material into wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from the Registrants’ pipelines or facilities could result in fines or penalties as well as significant remedial obligations. Waters of the United States On May 25, 2023, the U.S. Supreme Court issued a decision limiting the scope of federal jurisdiction over wetlands in the case of Sackett v. Environmental Protection Agency , and on August 29, 2023, the EPA issued a final rule that sought to conform with the U.S. Supreme Court decision. As a result of ongoing rulemaking litigation, the Registrants’ operations in all states with the exception of Minnesota fall under the pre-2015 regulatory regime consistent with the Supreme Court decision in Sackett , while operations in Minnesota fall under the 2023 rule, as amended. However, on November 17, 2025, the EPA announced a proposed rule that seeks to further clarify the definition of “Waters of the United States.” CenterPoint Energy is unable to predict the outcome of current or future litigation or regulatory proceedings, but does not expect a material impact on its operations relating to these rules. CenterPoint Energy will continue to monitor regulatory and legal developments relating to the Clean Water Act that may affect its business. ELG In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards, which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. In February 2019, the IURC approved Indiana Electric’s ELG Compliance Plan for its F.B. Culley Generating Station, which was completed in compliance with the requirements of ELG . On April 25, 2024, the EPA released its final Supplemental ELG and Standards for the Steam Electric Generating Point Source Category, and on December 31, 2025, the EPA published its final rule further extending the applicable compliance deadlines. The Registrants currently anticipate that they will be in compliance with the Supplemental ELG Guidelines and any extensions thereto at the Culley facility due to previous wastewater treatment upgrades. 14 Cooling Water Intake Structures Section 316 of the federal Clean Water Act requires steam electric generating facilities use “best technology available” to minimize adverse environmental impacts on a body of water. In May 2014, the EPA finalized a regulation requiring installation of “best technology available” to mitigate impingement and entrainment of aquatic species in cooling water intake structures. Indiana Electric has completed the required ecological studies and anticipates timely compliance at its F.B. Culley facility in accordance with deadlines to be established by IDEM. Hazardous Waste The Registrants’ operations generate wastes, including some hazardous wastes, that are subject to the federal RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous wastewaters produced and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements. Coal Ash In 2015, the EPA finalized the CCR Rule. Indiana Electric historically operated three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility; these ash ponds are no longer in operation. Both the Culley East and A.B. Brown facility have been taken out of service and closure activities continue. The Culley West pond closure activities were completed in December 2020. For further discussion about Indiana Electric’s ash ponds, see Note 14(c) to the consolidated financial statements. On April 25, 2024, the EPA released its final Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities; Legacy CCR Surface Impoundments rule (CCR Legacy Rule), which was published in the federal register in May 2024. The CCR Legacy Rule requires companies to investigate previously closed impoundments that were used historically for ash disposal or locations which have had ash placed on them in amounts set forth in the CCR Legacy Rule. The Registrants have completed their preliminary review of potential sites that will require further investigation under the CCR Legacy Rule and identified certain sites in Indiana for further evaluation. For further discussion about Indiana Electric’s sites identified pursuant to the CCR Legacy Rule, see Note 14(c) to the consolidated financial statements. Liability for Remediation CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of “hazardous substances” into the environment. Classes of PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of the Registrants’ ordinary operations they do, from time to time, generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties, to take action in response to threats to the public health or the environment and to recover the costs they incur from the responsible classes of persons. Under CERCLA, the Registrants could potentially be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for associated response and assessment costs, including for the costs of certain health studies. Liability for Preexisting Conditions For information about preexisting environmental matters, see Note 14(c) to the consolidated financial statements. 15 HUMAN CAPITAL CenterPoint Energy believes its employees are its greatest asset, and their unique skills, knowledge, experience and backgrounds are critical to safely and reliably delivering electricity and natural gas to CenterPoint Energy’s customers across its service territories. CenterPoint Energy’s core values—safety, integrity, accountability, initiative and respect—guide how it makes decisions and provide the foundation for a strong culture of ethics where employees are responsible for upholding these values and following CenterPoint Energy’s Ethics and Compliance Code. The following table sets forth the number of employees by Registrant and reportable segment as of December 31, 2025: Number of Employees Number of Employees Represented by Collective Bargaining Groups Reportable Segment CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC Electric 3,516 3,153 — 1,896 1,705 — Natural Gas 3,259 — 2,984 1,703 — 1,613 Corporate and Other (1) 2,019 — — 113 — — Total 8,794 3,153 2,984 3,712 1,705 1,613 (1) Employees in the Corporate and Other reportable segment provide services to the Electric and Natural Gas reportable segments and the costs of these services have been charged directly to the Electric and Natural Gas reportable segments using assignment methods that management believes are reasonable. For further information, see Note 18 to the consolidated financial statements. CenterPoint Energy’s workforce includes 3,712 employees represented by collective bargaining agreements. For information about the status of collective bargaining agreements, see Note 8(j) to the consolidated financial statements. Talent Attraction, Development and Retention. CenterPoint Energy’s human capital priorities include attracting, retaining and developing high performing talent through its talent management activities. CenterPoint Energy endeavors to attract quality candidates through its recruitment and selection processes. CenterPoint Energy seeks to recruit qualified employees regardless of race, gender, color, sexual orientation, age, religion, national origin, or physical or mental disability. The CenterPoint Energy talent acquisition team engages with college campuses to create awareness of opportunities in engineering, finance and technical occupations, and maintains relationships with student organizations across CenterPoint Energy’s service territories. CenterPoint Energy also maintains internship and apprenticeship programs that are designed to provide real-world experience, training and mentoring to interns and apprentices. Additionally, CenterPoint Energy works with other energy utility companies, associations, unions, educators and business partners to support workforce readiness and long-term talent development in the energy industry. CenterPoint Energy’s strategy to attract, retain and develop its employees combines talent discussions and succession planning as essential elements of workforce planning and development. To support its commitment to delivering electricity and natural gas safely and reliably, CenterPoint Energy focuses on the continued development of its greatest assets, its employees, to build a sustainable leadership pipeline. To meet the business’ future needs, CenterPoint Energy’s goal is to create great leaders capable of developing their employees, while supporting the business’ goals and maintaining a high-performing workforce through employee engagement and workplace culture. CenterPoint Energy has a number of tools for leadership and employee development that expand opportunities available to employees. For example, CenterPoint Energy maintains a corporate university that offers a variety of content and resources to employees, including instructor-led and on-demand learning, to help meet employees’ needs for professional, leadership and business unit-specific development. Additionally, CenterPoint Energy conducts regular talent discussions, including succession planning with various levels of leadership, to provide business continuity and identify its future leaders and opportunities. CenterPoint Energy invests in employee development throughout the year to align individual performance to business needs, drive development planning and support career progression. CenterPoint Energy’s progress is reviewed regularly for continued improvement. Engagement. CenterPoint Energy is dedicated to advancing an open and high-performing work environment where business results are achieved through the experience, skills, abilities and talents of the whole workforce. CenterPoint Energy aims to create a workplace where every employee is engaged, aligned with our values, strategy, goals and priorities, and understands how each person contributes to CenterPoint Energy’s long-term performance. In 2025, CenterPoint Energy’s senior leadership team conducted an employee engagement survey and held quarterly town hall meetings with employees to share key company updates, with employees across CenterPoint Energy participating in person or via video conference. 16 Compensation and Benefits. CenterPoint Energy is committed to providing its employees with competitive pay and benefits. Its compensation philosophy is to maintain employee total compensation that is competitive with the relevant markets, internally equitable, and based on company and individual performance. CenterPoint Energy expects that this will enable it to attract, motivate and retain employees with the skills and competencies necessary to achieve its business strategy. In addition to competitive compensation, CenterPoint Energy provides its employees with a comprehensive benefits package designed to help employees stay healthy, care for their families, plan for the future and enjoy peace of mind. The benefits package includes medical, dental, vision, life, disability and accidental insurance coverage; retirement, company match savings plans; paid time off, parental leave, wellness and employee assistance programs. The employee wellness resources encompass support for mental, financial and physical health. INFORMATION ABOUT OUR EXECUTIVE OFFICERS (as of February 13, 2026) Name Age Title Jason P. Wells 48 Chair of the Board, President and Chief Executive Officer Christopher A. Foster 47 Executive Vice President and Chief Financial Officer Monica Karuturi 47 Executive Vice President and General Counsel Jason M. Ryan 50 Executive Vice President, Regulatory Services and Government Affairs Jesus Soto, Jr. 58 Executive Vice President and Chief Operating Officer Jason P. Wells has served as Chair of the Board since October 8, 2025, and as President and Chief Executive Officer of CenterPoint Energy and a member of the Board since January 5, 2024. Previously he served as President and Chief Operating Officer of CenterPoint Energy from May 2023 to January 2024; as President, Chief Operating Officer and Chief Financial Officer of CenterPoint Energy from January 2023 to May 2023; and as Executive Vice President and Chief Financial Officer of CenterPoint Energy from September 2020 to December 2022. Prior to joining CenterPoint Energy, Mr. Wells served as Executive Vice President and Chief Financial Officer of PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric Company, from June 2019 to September 2020. He previously served as Senior Vice President and Chief Financial Officer of PG&E Corporation from January 2016 to June 2019 and as Vice President, Business Finance of Pacific Gas and Electric Company from August 2013 to January 2016. PG&E Corporation filed Chapter 11 bankruptcy on January 29, 2019 and successfully emerged from bankruptcy on July 1, 2020. He also served in various finance and accounting roles of increasing responsibility at Pacific Gas and Electric Company. Mr. Wells earned his bachelor’s degree and master’s degree in accounting, both from the University of Florida. He is a certified public accountant (inactive). Mr. Wells serves on the Executive Committee and Board for the Greater Houston Partnership, the Advisory Board of the Kinder Institute for Urban Research at Rice University, and the Boards of Central Houston, Inc., M.D. Anderson Cancer Center, Performing Arts Houston and the United Way of Greater Houston. Christopher A. Foster has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since May 2023. Previously, he served as Executive Vice President and Chief Financial Officer of PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric Company, from March 2021 to May 2023. He previously served in various positions of increasing responsibilities at PG&E since 2011, including as Vice President and Interim Chief Financial Officer from September 2020 to March 2021, and Vice President, Treasury and Investor Relations from March 2020 to September 2020. PG&E Corporation filed Chapter 11 bankruptcy on January 29, 2019 and successfully emerged from bankruptcy on July 1, 2020. He earned his bachelor’s degree from Michigan State University. Mr. Foster serves on the Board of Exploratorium, a San Francisco-based science and technology museum, as well as the Board of Directors of the Houston Parks Board. Monica Karuturi has served as Executive Vice President and General Counsel of CenterPoint Energy since January 2022. She previously served as Senior Vice President and General Counsel from July 2020 to January 2022; as Vice President and Deputy General Counsel from April 2019 to July 2020; as Vice President and Associate General Counsel - Corporate and Securities from October 2015 to April 2019; and as Associate General Counsel - Corporate from September 2014 to October 2015. Prior to joining CenterPoint Energy, Ms. Karuturi served as counsel for LyondellBasell Industries for corporate and finance matters and strategic transactions. Ms. Karuturi earned her bachelor’s degree from Brown University, master’s degree in health policy and management from Columbia University, and juris doctorate from Georgetown University Law Center. Ms. Karuturi was appointed as a Commissioner of the Texas Access to Justice Commission by the Texas Supreme Court in June 2015 and served in this capacity until June 2021. She was also appointed as Chair of the Houston Bar Foundation in 2021 and served until December 2024. She currently serves as a member of the Board of Directors of Nextpower Inc. and the Houston Zoo. 17 Jason M. Ryan has served as Executive Vice President, Regulatory Services and Government Affairs of CenterPoint Energy since January 2022. He previously served as Senior Vice President, Regulatory Services and Government Affairs from July 2020 to January 2022; as Senior Vice President and General Counsel from April 2019 to July 2020; as Senior Vice President, Regulatory and Government Affairs from February 2019 to April 2019; as Vice President of Regulatory and Government Affairs and Associate General Counsel from March 2017 to February 2019; and as Vice President and Associate General Counsel from September 2014 to March 2017. He was appointed to the Texas Diabetes Council by Texas Governor Perry in 2013 for a term ending in 2019, and he has since been reappointed by Texas Governor Abbott twice (most recently in 2025 for a term ending in 2031). Mr. Ryan earned his bachelor’s degree from the Texas McCombs School of Business and juris doctorate from the University of Texas School of Law. Mr. Ryan currently serves on the boards of the Lone Star Flight Museum and the Association of Electric Companies of Texas. He also serves on the executive committee of the legal committee of the American Gas Association. Jesus Soto, Jr. has served as Executive Vice President, Chief Operating Officer of CenterPoint Energy since August 2025. Previously, he served as Executive Vice President, Utility Performance Solutions of Quanta Services, Inc., a publicly-traded energy infrastructure services company, from October 2023 to August 2025. He previously served as the Chief Operating Officer for Mears Group, Inc., a wholly-owned subsidiary of Quanta Services, Inc., from September 2019 to September 2023, and as Senior Vice President of Gas Operations for PG&E Corporation, a publicly traded electric utility holding company serving customers in Northern and Central California through its subsidiary Pacific Gas and Electric Company, from May 2012 to July 2019. Prior to joining PG&E Corporation, he served as Vice President of Operations Services and Vice President of Engineering and Construction for the Pipeline Group of El Paso Corporation, a former publicly traded natural gas and related energy products provider. Mr. Soto earned his bachelor's degree from the University of Texas at El Paso, his master's degree in civil engineering from Texas A&M University, and his master's degree in business administration from the University of Phoenix. Mr. Soto serves on the Board of Directors of GTI Energy, an energy technology development and training company, and as Chair of the Industry Pipeline Safety Management Systems Team of the American Petroleum Institute. 18 Item 1A. Risk Factors CenterPoint Energy is a holding company that conducts all of its business operations through subsidiaries, primarily Houston Electric, CERC and SIGECO. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this combined report on Form 10-K, summarizes the principal risk factors associated with the holding company and the businesses conducted by its subsidiaries. However, additional risks and uncertainties either not presently known or not currently believed by management to be material may also adversely affect CenterPoint Energy’s businesses. For other factors that may cause actual results to differ from those indicated in any forward-looking statement or projection contained in this combined report on Form 10-K, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7, which should be read in conjunction with the risk factors contained in this Item 1A. Carefully consider each of the risks described below, including those relating to Houston Electric, LLC and CenterPoint Energy Resources Corp., which, along with CenterPoint Energy, Inc., are collectively referred to as the Registrants. Unless the context indicates otherwise, where appropriate, information relating to a specific Registrant has been segregated and labeled as such and specific references to Houston Electric and CERC in this section also pertain to CenterPoint Energy. In this combined report on Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries. Risk Factors Affecting Operations Electric Transmission, Distribution and Generation (CenterPoint Energy and Houston Electric) Disruptions at third-party or Indiana Electric’s power generation facilities, generation inadequacy, directives issued by regulatory authorities or other matters could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and Houston Electric and Indiana Electric may not be able to promptly respond, repair and restart their facilities, which could adversely affect their businesses, financial condition, results of operations and cash flows. Houston Electric owns the transmission and distribution infrastructure in its service territory that delivers electric power to its customers, but it does not own or operate any bulk power generation facilities. Indiana Electric owns and operates power generation facilities in addition to the transmission and distribution infrastructure in its service territory. Both Houston Electric and Indiana Electric must follow the directives issued by their independent system operator, ERCOT and MISO, respectively. ERCOT and MISO have in the past and may in the future issue directives requiring members to implement controlled outages as a result of an emergency or reliability issues. Houston Electric has faced and may in the future face challenges to its planning and preparation for such directives and its implementation of Load Shed, including, for example, allegations that it had discretion as to how to Load Shed and which customers experienced outages and the duration of those outages. As a result, claims and lawsuits could be filed against CenterPoint Energy for personal injury, property damage or other damage or loss as a result of its Load Shed planning, preparation, implementation, and decisions in order to meet the directives of ERCOT and MISO, respectively. For example, during the February 2021 Winter Storm Event, the ERCOT regulated Texas electric system experienced an unprecedented power generation shortage as the amount of electricity generated by the state’s power generation companies was insufficient to meet the amount demanded by customers. This resulted in ERCOT directing TDUs to significantly Load Shed, which caused customer outages across the ERCOT electric grid of Texas, including in Houston Electric’s service territory. CenterPoint Energy received various claims and lawsuits with respect to the February 2021 Winter Storm Event, alleging, among other things, wrongful death, personal injury, property damage and other injuries and damages. See Note 7 to the consolidated financial statements and “— Houston Electric’s use of TEEEF ...” for further information. If power generation capacity is severely disrupted or is inadequate for any reason in the future or in the event of significant system disturbances, Houston Electric’s or Indiana Electric’s transmission and distribution services may be diminished, interrupted or halted, which could lead to prolonged customer outages, and Houston Electric and Indiana Electric may not be able to promptly repair and restart their facilities, which could adversely affect our businesses, financial condition, results of operations and cash flows. Further, as with the lawsuits filed in the aftermath of the February 2021 Winter Storm Event, claims and lawsuits could be filed against the Registrants, which could also adversely affect our business, financial condition, and results of operations. Additionally, Indiana Electric’s generating facilities are subject to operational risks, and Houston Electric and Indiana Electric are subject to risk relating to the generating facilities that supply the power transmitted by Houston Electric and Indiana Electric; these risks have in the past and may in the future result in service interruptions and unscheduled outages, unanticipated operation and maintenance expenses, reputational harm and increased purchase power costs. For example, in June 2022, F.B. Culley Unit 3, a coal-fired generation unit, experienced a boiler feed pump turbine failure that caused the unit to be out of service for nearly nine months. In this time frame, CenterPoint Energy purchased energy on the open market. Such open market purchases have and may again result in increased costs and have an adverse impact on our business, financial condition, results of operations and cash flows. Further, Indiana Electric is party to a number of PPAs with third parties. Indiana Electric’s 19 operations may be disrupted or otherwise insufficient if third parties do not deliver required power under our PPAs. These risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator or other human error; aging infrastructure; interruption of fuel supply or increased prices of fuel as a result of, among other things, contract expirations, inflation and/or tariffs; disruptions in the production or delivery of electricity; inability to comply with regulatory or permit requirements; governmental action; labor disputes; severe weather; natural disasters; or cyberattacks, all of which could adversely affect Indiana Electric’s and Houston Electric’s businesses, including their financial condition, results of operations and cash flows. Further, Indiana Electric currently relies on coal for a portion of its generation capacity. Indiana Electric purchases the majority of its coal supply, and in 2025 purchased all of its coal supply, from a single, unrelated party and, although the coal supply is under long-term contract, the loss of this supplier or transportation interruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s business, financial condition, results of operations and cash flows. Future labor shortages in the coal industry as well as coal supply shortages (such as those experienced by Indiana Electric in 2021 and part of 2022), may lead to increased cost and have an adverse impact on our business, financial condition, results of operations and cash flows. Further, as Indiana Electric’s generating facilities may experience unanticipated disruptions as a result of renewable supply shortages, including, but not limited to, unfavorable wind and solar conditions such as cloudy or windless days, and such disruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s business, financial condition, results of operations and cash flows. The operations of Houston Electric and Indiana Electric are subject to the usual hazards associated with electricity transmission and distribution, including inclement or severe weather, natural disasters, including wildfires, mechanical failure, contact with electrified facilities by people, equipment, and debris, unscheduled downtime, equipment interruptions, loss or outage of key technology platforms or systems, contamination, remediation, explosions, fires, chemical spills, discharges or releases of toxic or hazardous substances and other environmental risks. Such hazards can cause personal injury and loss of life, severe damage to or destruction of property and equipment, including loss of transmission and distribution lines and related equipment and environmental damage, and may result in suspension of operations, disruption of service to customers, prolonged outages and the imposition of civil or criminal penalties. For example, in 2024, Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in a substantial number of its customers being without power, many for extended periods of time. Although CenterPoint Energy currently maintains property and casualty insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with potential hazards incident to Houston Electric and Indiana Electric’s businesses, and there is no guarantee that the insurance that CenterPoint Energy currently maintains will continue to be available at rates we believe are reasonable. Indiana Electric’s execution of its generation transition plan is subject to various risks, including timely recovery of capital investments and increased costs and risks related to the timing and cost of development and/or construction of new generation facilities. Indiana requires each electric utility to develop and submit an IRP to the IURC every three years, unless extended, that uses economic modeling to consider the costs and risks associated with available resource options to provide reliable, cost effective electric service for the next 20-year period. Indiana Electric has used past IRPs and will continue to use future IRPs to evaluate its mix of generation resources. Indiana Electric engages with the communities it serves, its regulators and third-parties in developing its generation transition plan. Recent IRPs, including the 2025 IRP, have identified preferred portfolios that include a wider mix of generating resources such as coal-fired generation, solar, wind, solar with storage and dispatchable natural gas combustion turbines. While the IURC does not approve or reject Indiana Electric’s IRP, the IURC does comment on the IRP. Indiana Electric is required to obtain a CPCN prior to constructing or acquiring generating resources. Indiana Electric also obtains IURC approval of PPAs and demand-side management plans to help support cost recovery. Indiana Electric must manage several risks associated with its generation transition plan. The IURC may delay providing comments on an IRP, requiring Indiana Electric to either wait for comments or proceed to implement its IRP without IURC comments. The IURC comments may raise concerns with Indiana Electric’s IRP that make it difficult to obtain approval of the generation transition plan if not addressed. There is no guarantee that the IURC will approve Indiana Electric’s requests to implement part of its generation transition. If Indiana Electric fails to receive IURC approvals necessary to acquire the projects or resources identified in its IRP or if other governmental action is taken with respect to Indiana Electric’s generation resources or generation transition plan, Indiana Electric may not be able to implement its generation transition plan in a timely manner or at all. For example, while Indiana Electric’s 2025 IRP (similar to previous IRPs) preferred portfolios included the retirement of F.B. Culley Unit 2, a coal-fired generation unit, by the end of 2025, the U.S. Department of Energy issued emergency order 202(c) in December 2025 directing Indiana Electric to continue operating the unit through March 23, 2026. Additionally, changes in how renewable resources are accredited to meet MISO’s planning reserve margin requirement have made it less economic to pursue these resources. In connection with its IRPs, Indiana Electric’s determinations with respect to the appropriate mix of generation resources may change from plans that were previously announced. For example, while Indiana 20 Electric’s 2022/2023 IRP recommended the conversion of F.B. Culley Unit 3 from coal to natural gas by 2027, the 2025 IRP re-evaluated this conversion in light of customer affordability concerns, among other things, and deferred the decision regarding F.B. Culley Unit 3’s replacement to a future IRP. If Indiana Electric is unable to implement its generation transition plan, it may have an adverse effect on CenterPoint Energy’s ability to execute on its energy transition goals, execute on its growth strategy, achieve its financial goals, and otherwise impact its business, financial condition, results of operations and cash flows. Even if a generation project is approved, risks associated with the development or construction of any new generation exist, including new legislation or governmental action restricting or delaying new generation, moratorium legislation, changes to trade practices (including tariffs, bans, retaliatory trade measures taken against the United States or related governmental action), changes to business practice manuals of MISO or corresponding impacts such as interconnection delays (which may be exacerbated by significant new load additions), the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, the ability to appropriately estimate costs of new generation, the effects of potential construction delays, project scope changes, and cost overruns, cost of and ability to meet capacity requirements and related customer affordability considerations. For example, due to shifting market dynamics, changing project considerations such as substantial delays in commercial operation dates (due in part to MISO interconnection delays), cost increases and concerns about customer affordability, Indiana Electric terminated several wind and solar projects in 2025. If Indiana Electric is unable to meet its generation needs through development or acquisition of new generation, it would be required to buy the necessary capacity and electricity on the open market. Such open market purchases may result in increased costs and may have an adverse impact on our business, financial condition, results of operations and cash flows. If we are unable to complete or acquire such generation facilities or resources, or if they do not perform as anticipated, our business, financial condition, results of operations and cash flows may be adversely affected. Houston Electric’s receivables are primarily concentrated in a small number of REPs, and any delay or default in payments of these receivables could adversely affect Houston Electric’s business, financial condition, results of operations and cash flows. Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity. As of December 31, 2025, Houston Electric provided electric delivery service to approximately 67 REPs. Adverse conditions, including, but not limited to, the February 2021 Winter Storm Event or other extreme weather (which may result in abnormal power prices), structural problems in the market served by ERCOT, the impact of public health events or similar occurrences, mismanagement by the REPs, inflation or financial difficulties of one or more REPs, have and may in the future impair the ability of these REPs to pay for Houston Electric’s services or cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis. Applicable PUCT regulations significantly limit the extent to which Houston Electric can apply normal commercial terms to otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and Houston Electric thus remains at risk for payments relating to services provided prior to any shift to another REP or provider of last resort. Houston Electric’s PUCT-approved tariff outlines the remedies available to Houston Electric in the event that a REP defaults on amounts owed. Among the remedies available to Houston Electric are seeking recourse against any cash deposit, letter of credit, or surety bond provided by the REP or implementing mutually agreeable terms with the REP. Another remedy is to require that customers be shifted to another REP or a provider of last resort. Houston Electric thus incurs risk for payments related to services provided prior to the shift to another REP or the provider of last resort. A significant portion of Houston Electric’s billed receivables from REPs are due from affiliates of NRG and Vistra Energy Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2025 was $279 million. Approximately 37% and 23% of this amount was owed by affiliates of NRG and Vistra Energy Corp., respectively. Any delay or default in payment by REPs could adversely affect Houston Electric’s business, financial condition, results of operations and cash flows. If a REP was unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made regarding prior payments Houston Electric had received from such REP. For example, following the February 2021 Winter Storm Event, multiple REPs filed for bankruptcy. As of December 31, 2025 and 2024, as authorized by the PUCT, CenterPoint Energy and Houston Electric had a regulatory asset of $7 million and $8 million, respectively for bad debt expenses resulting from REPs’ defaults on their obligations to pay delivery charges to Houston Electric, net of collateral and recovery in rates. See “— Rate regulation of the Registrants’ electric ...” For further information on certain of Houston Electric’s ongoing regulatory proceedings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report. 21 Houston Electric’s use of TEEEF is subject to various risks, potential performance issues and allegations about Houston Electric’s procurement and deployment of the resources (including the planning, execution and effectiveness of the same), regulatory and environmental requirements, and timely recovery of capital. Following the February 2021 Winter Storm Event, the Texas legislature passed a law to allow TDUs, such as Houston Electric, to lease and temporarily operate TEEEF during widespread power outages where ERCOT has ordered a TDU to Load Shed or the TDU’s distribution facilities are not being fully served by the bulk power system under normal operations. In response to this legislation, Houston Electric began leasing large (27 MW to 32 MW) TEEEF and medium (5.7 MW) TEEEF. In 2023, the Texas legislature amended the law to allow wider use of TEEEF, and in response, Houston Electric has entered into contractual arrangements to facilitate access to small (200 kW to 1,250 kW) TEEEF units; the small TEEEF units represent approximately 4% of the MWs of Houston Electric’s total portfolio of TEEEF assets. In 2025, following the passage of the TEEEF Rule, Houston Electric requested from the PUCT preapproval to lease small TEEEF units for a three-year term. These proceedings remain ongoing and, until PUCT preapproval is received, Houston Electric plans to maintain the current contractual arrangement providing access to the small TEEEF units on a month-to-month basis. See Note 7 to the consolidated financial statements for further information. Additionally, in June 2025, the law was further amended to provide that, effective on or after the date of the amendment’s passage, TDUs may only enter into, renew or extend leases for TEEEF units with a maximum generation capacity of five or fewer MW and that are rapidly deployable. The law prescribes specific and limited use for TEEEF, and Houston Electric’s TEEEF have limited generation capacity, such that in future events customers could still be without power despite deployment of TEEEF resources. Additionally, as further described below, the large TEEEF units (which represent approximately 91% of the MWs of Houston Electric’s total portfolio of TEEEF assets as of December 31, 2025) were released to the greater San Antonio region as of June 2025 for a contractual term through March 2027 unless terminated earlier in accordance with the provisions of the ERCOT Transaction, and Houston Electric has proposed releasing the medium TEEEF units (which represent approximately 5% of the MWs of Houston Electric’s total portfolio of TEEEF assets as of December 31, 2025). If Houston Electric is unable to deploy sufficient TEEEF resources in time to respond to a particular event (including as a result of releasing TEEEF to third parties or similar transactions as further described below); if TEEEF resources fail to perform, or are perceived to fail to perform, as intended; if Houston Electric is otherwise unable, or perceived as unable, to provide back-up generation resources and restore power (such as in the event of ERCOT issuing a directive requiring TDUs to Load Shed); or if the use of TEEEF resources or their failure to perform causes or is alleged to cause any personal injury, property damage, or other damage or loss due to allegations Houston Electric failed to deploy such units reasonably or effectively and failed to respond to particular power outages, Houston Electric could be subject to claims, demands, litigation, liability, regulatory scrutiny, and loss of reputation and new legislation could be passed making it no longer viable for Houston Electric to lease TEEEF at the same or similar scale that it currently leases such resources or at all. For example, following Hurricane Beryl, various federal, state and local governmental and regulatory agencies and other entities called for or conducted inquiries and investigations into the efforts made by Houston Electric to prepare for, and respond to, this event, including, among other things, Houston Electric’s procurement of TEEEF, and certain government officials argued that Houston Electric, rather than ratepayers, should be held responsible for paying approximately $800 million (the amount the PUCT had previously approved Houston Electric to recover from ratepayers relating to Houston Electric’s leasing of TEEEF). Ongoing and future inquiries, investigations and proposed legislation regarding Houston Electric’s TEEEF could adversely affect our business, financial condition, results of operations and cash flows, including with respect to our recovery of costs incurred as a result of Hurricane Beryl or future severe weather events; the assessment of financial penalties; changes to Houston Electric’s system, service territories, operations and/or regulatory treatment; and the viability for Houston Electric to continue leasing TEEEF. In June 2025, Houston Electric entered into the ERCOT Transaction, subject to PUCT approval, to release its large TEEEF units to ERCOT at CPS Energy facilities to serve the greater San Antonio region until March 2027 unless terminated earlier pursuant to the provisions of the ERCOT Transaction, reduce its TEEEF fleet capacity and reduce its rates to reflect the removal of the large TEEEF units from its fleet. Following the completion of service in the San Antonio area, Houston Electric anticipates that it would complete one or more future transactions involving its large TEEEF units; because the TEEEF units would not be available to serve customers during such time, Houston Electric plans to continue to not charge customers for these units for any future periods. Further, in November 2025, Houston Electric proposed to release its medium TEEEF units from its TEEEF fleet and remove the associated lease costs from its rates. Houston Electric also anticipates entering into and receiving revenue from future transactions involving its medium TEEEF units. There can be no assurance that the PUCT will approve the ERCOT Transaction and Houston Electric’s proposal to release its medium TEEEF units. If the ERCOT Transaction and/or Houston Electric’s proposal to release its medium TEEEF units are not approved, it may have an adverse effect on our business, financial condition, results of operations and cash flows, as well as potentially lead to negative consequences from regulatory authorities or other public authorities. Suitable future transactions may not be available on terms and conditions we find acceptable, or the expected benefits of Houston Electric’s release of its large and medium TEEEF units 22 or any completed future transactions may not be realized fully or at all, or may not be realized in the anticipated timeframe, which could adversely impact our business, financial condition, results of operations and cash flows. Finally, if such transactions are successful and thereby result in Houston Electric having fewer TEEEF units to deploy in its service territory, and conditions occur that could be or are perceived to have the potential to be addressed by Houston Electric’s deployment of TEEEF, Houston Electric could be subject to claims, demands, litigation, liability, regulatory scrutiny and loss of reputation. Despite the recovery of certain TEEEF costs in the past, there can be no assurance that Houston Electric will seek to or be able to recover certain future TEEEF costs or be able to retain those costs previously approved for recovery. For example, in 2024, the TCA filed a complaint with the PUCT requesting that it end the cost recovery and return on investment on Houston Electric’s large and medium TEEEF units as previously approved, and these proceedings remain ongoing. See Note 7 to the consolidated financial statements for further information. If Houston Electric is unable to recover or must return any or certain of its TEEEF costs, our business, financial condition, results of operations and cash flows may be adversely affected. Additionally, while Houston Electric has insurance coverage and indemnity rights for its use of TEEEF resources, if its insurers or indemnitors fail to meet their indemnity obligations, Houston Electric could be liable for personal injury, property damage, or other damage or loss. Further, TEEEF resources are subject to various environmental regulations and permitting requirements, which could have an impact on Houston Electric’s ability to use these units. If Houston Electric is not in compliance with any environmental regulation or permitting requirement, Houston Electric could be subject to further potential liability. The use of TEEEF is also subject to various other requirements, and failure to comply with them could subject Houston Electric to additional liability as well as challenges to its use of TEEEF in general. Natural Gas (CenterPoint Energy and CERC) Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for our natural gas business customers. We depend on third-party service providers to maintain an adequate supply of natural gas and for available storage and intrastate and interstate pipeline capacity to satisfy our customers’ needs, all of which are critical to system reliability. Substantially all of our natural gas supply is purchased on intrastate and interstate pipelines. If we are unable to secure an independent natural gas supply of our own or if third-party service providers fail to timely deliver natural gas to meet our requirements, the resulting decrease in natural gas supply in our service territories could have an adverse effect on our business, financial condition, results of operations and cash flows. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage deliveries or other events affecting natural gas supply, including, but not limited to, operational failures, hurricanes, tornadoes, floods, severe winter weather conditions, wildfires, acts of terrorism, human error or cyberattacks or changes in legislative or regulatory requirements, could also have a negative impact on our businesses, financial condition, results of operations and cash flows. Further, to the extent that our natural gas requirements cannot be met through access to or continued use of existing natural gas infrastructure or if additional infrastructure, including onshore and offshore exploration and production facilities, gathering and processing systems and pipeline and storage capacity is not constructed at a rate that satisfies demand, then our operations could be negatively affected. We are subject to fluctuations in natural gas prices, which could affect the ability of our suppliers and customers to meet their obligations or may impact our operations, which could adversely affect our business, financial condition, results of operations and cash flows. We are subject to risk associated with changes in the price of natural gas. The regional and other markets in which we purchase natural gas are competitive and can be subject to significant pricing volatility as a result of many factors, including inflation, adverse weather conditions, supply and demand changes, availability of competitively priced alternative energy sources, political and geopolitical instability, commodity production levels and storage capacity, energy and environmental legislation and regulations and economic and financial market conditions. The natural gas market has been, and may continue to be, volatile due to growing domestic demand, increased natural gas exports, weather and other factors. Significant increases in natural gas prices, such as those experienced during the February 2021 Winter Storm Event, might affect our ability to collect balances due from customers and could create the potential for uncollectible accounts expense to exceed the recoverable levels built into tariff rates. In addition, a sustained period of high natural gas prices could (i) decrease demand for natural gas in the areas in which we operate, thereby resulting in decreased sales and revenues and (ii) increase the risk that our suppliers or customers fail or are unable to meet their obligations. An increase in natural gas prices would also increase working capital requirements by increasing the investment that must be made to maintain natural gas inventory levels. 23 Our natural gas businesses must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on our business, financial condition, results of operations and cash flows. Our natural gas businesses compete primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and natural gas marketers also compete directly with us for natural gas sales to end users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass our facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas delivered by us as a result of competition with alternate energy sources may have an adverse impact on our business, financial condition, results of operations and cash flows. Risk Factors Affecting Regulatory, Environmental and Legal Risks Rate regulation of the Registrants’ electric and natural gas businesses may delay or deny their ability to earn an expected return and fully and timely recover their costs. The Registrants’ electric and natural gas businesses are regulated by certain municipalities, state commissions and federal agencies, such as FERC. Their rates are set in comprehensive base rate proceedings (i.e., general rate cases) based on an analysis of their invested capital, their expenses and other factors in a designated test year (often either fully or partially historic), subject to periodic review and adjustments. Each of these rate proceedings is subject to third-party intervention and appeal, and the timing of a general base rate proceeding may be out of the Registrants’ control. The Registrants can make no assurance that their or their subsidiaries respective base rate proceedings will result in requested or favorable adjustments to their rates, in full and timely cost recovery or approval of other requested items, including, among other things, capital structure and ROE. Moreover, these base rate proceedings have caused in certain instances, and in the future could cause, the Registrants’ electric and/or natural gas businesses to recover their investments below their requested levels, below the national average return for utilities or below recently approved return levels for other utilities in their respective jurisdictions. For instance, in the 2024 Houston Electric general rate case, Houston Electric filed a base rate case seeking approval for revenue increases of approximately $60 million and a 10.4% ROE, but pursuant to the final settlement agreement filed with the PUCT, Houston Electric received an overall revenue requirement decrease of approximately $47 million to current revenues and a 9.65% ROE relative to the initial filing. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their businesses, financial condition, results of operations and cash flows could be adversely affected. Further, the Registrants or their subsidiaries might be required to implement additional measures, such as the adoption of ring-fencing measures by Houston Electric in connection with its 2019 rate case proceeding. Such additional measures may adversely impact the Registrants’ businesses and could have an adverse effect on their businesses, financial condition, results of operations and cash flows. The rates that Registrants’ electric and natural gas businesses are allowed to charge may not match their costs at any given time, a situation referred to as “regulatory lag.” Regulatory lag has been and may be exaggerated in the future under certain circumstances, such as increased capital investments that are recovered in arrears. For example, the MPUC ordered extraordinary gas costs incurred in the February 2021 Winter Storm Event be recovered over a 63-month period from 2022 — 2027 and CERC forego recovery of the associated carrying costs. Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by the Registrants and their subsidiaries to reduce the effects of regulatory lag (for example, CSIA, DCRF, DRR, DSMA, GRIP, RCRA, TCOS and TDSIC), such adjustment mechanisms are subject to the applicable regulatory body’s approval, which we cannot assure would be approved, and are subject to certain limitations that may reduce or otherwise impede the Registrants’ or their subsidiaries ability to adjust their rates or result in rates below those requested. Therefore, the Registrants can make no assurance filings for such mechanisms will result in favorable adjustments to rates or in full cost recovery. Further, from time to time, the Registrants’ regulators approve the issuance of system restoration bonds or securitization bonds to facilitate the recovery of certain qualified costs, including costs incurred as a result of severe weather or to recover stranded asset costs. For example, Houston Electric is currently seeking to recover system restoration costs associated with Hurricane Beryl and certain other significant storms through the issuance and sale of non-recourse system restoration bonds. The issuance of system restoration bonds or securitization bonds may be delayed due to regulatory or other actions outside of our control. If the issuance of system restoration bonds or securitization bonds is delayed, we may not be able to recover our costs in a timely manner, which could have an adverse effect on CenterPoint Energy’s, CERC’s, and Houston Electric’s businesses, financial condition, results of operations and cash flows. Inherent in the regulatory process is some level of risk that jurisdictional regulatory authorities may challenge the reasonableness or prudency of operating expenses incurred or capital investments made by the Registrants or their subsidiaries and deny the full recovery of their cost of service in rates. For example, concerns about customer affordability could cause regulators to approve lesser amounts in ratemaking or cost recovery proceedings. From time to time, reviews and investigations 24 have caused in certain instances, and in the future could cause, the Registrants to recover their costs or investments below their requested levels. For example, in October 2022, the MPUC issued a written order disallowing recovery of approximately $36 million of the $409 million originally requested by CERC in connection with its recovery of costs incurred as a result of the February 2021 Winter Storm Event. Notwithstanding the application of such rate adjustment mechanisms, the regulatory process by which rates are determined is subject to change as a result of legislative processes, rulemakings or litigation, as the case may be, and may not always be available or result in rates that will produce recovery of the Registrants’ or their subsidiaries’ costs or enable them to earn their authorized return. New legislation could be adopted in any of the states in which we operate that could alter the regulatory framework and prevent us from getting timely recovery of our costs and investments. Additionally, changes to the rate case or interim adjustment mechanisms (including the termination of such mechanisms) could result in an increase in regulatory lag or otherwise impact the Registrants’ ability to recover their costs in a timely manner. Decisions from regulators are typically subject to appeal, and any such appeal could further exacerbate regulatory lag and lead to additional uncertainty associated with rate case proceedings. The regulatory process may also be adversely affected by the political, regulatory and economic environment and customer affordability concerns in the states in which we operate. We are also affected by the actions of numerous advocacy groups, and success by any such groups in directly or indirectly influencing legislators and regulators could have a material adverse effect on our business, financial condition, results of operations and cash flows. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their businesses, financial condition, results of operations and cash flows could be adversely affected. For further information on rate case proceedings and interim rate adjustment mechanisms, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report. The regulated utility businesses, and the energy industry as a whole, have experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments (including those that have already been approved by a regulator). For example, Houston Electric’s SRP, which was approved by the PUCT in November 2025, includes twenty-seven resiliency measures totaling approximately $2.68 billion in capital investments and an estimated $185 million in operations and maintenance expense. Rising costs and investments and the upward trend in spending is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms, all of which could result in adverse cost recovery determinations and/or face resistance from customers and other stakeholders, especially in a rising cost environment, whether due to inflation, customer affordability concerns, tariffs or changes to governmental policies and programs, high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs could increase financing needs and otherwise adversely affect our business, financial condition, results of operations and cash flows. Our successful execution and completion of capital projects and programs, including those within our 10-year capital plan, are subject to substantial risks, and our business, financial condition, results of operations and cash flows could be materially affected should such efforts not be executed and completed as planned. We are managing ongoing, and planning future, significant capital projects relating to, among other things, improvements to our electric and natural gas transmission and distribution infrastructure. The execution of our capital projects, including those within our 10-year capital plan, may not be completed in accordance with current expectations or produce the desired results. Our ability to execute and complete our capital projects, including Houston Electric’s proposed 765 kV and other transmission projects, in a timely and cost-effective manner and within budget is contingent upon many variables and subject to substantial risks. These variables and risks include, but are not limited to, availability of and costs for materials, equipment, commodities and qualified labor; cost and availability of financing; cost of regulatory compliance; economic and market conditions; regulatory approvals, licensing and permitting; land and easement acquisition (including requirements and constraints relating to eminent domain); regulatory, political, public and community relations risks (including in relation to customer affordability concerns); tax law; our ability to capitalize on business opportunities and such opportunities providing desirable rates of return; load growth (including our forecasts thereof) and our ability to capitalize on opportunities relating thereto; safety and environmental requirements; the ability of third parties to provide timely and satisfactory performance under their contracts; delays and cost increases; and supply chains and material constraints. Certain events that may be beyond our control may occur that materially affect the schedule, cost and performance of these projects, including Houston Electric’s proposed 765 kV and other transmission projects. These events may relate to facing public and policymaker opposition to the projects or the real or perceived cost of such projects; delays in obtaining permits; challenges in securing sufficient land/easements for projects (including challenges to our use of eminent domain); shortages in materials and qualified labor; third parties not performing as expected or required under their contracts and/or experiencing financial problems that inhibit their ability to fulfill their obligations under contracts; supply chain delays or disruptions; changes in the scope and timing of projects; strikes; and adverse weather conditions. For example, our failure to capitalize on the opportunities presented by these developments or potential large load customers delaying or cancelling their planned projects could lead to delays or the cancellation of the projects 25 included in our 10-year capital plan. Additionally, regulators may investigate the prudence of costs in our rates and examine, among other things, the reasonableness or prudence of our level of expenditures (including costs associated with our capital projects). If we do not execute or complete our capital projects, including those within our 10-year capital plan, in accordance with current expectations or if our capital plan does not produce the desired results, our business, financial condition, results of operations and cash flows could be materially affected. We face risks related to project siting, financing, construction, permitting, governmental approvals, public opposition, and the negotiation of project development agreements that may impede our development and operating activities. Houston Electric, Indiana Electric and CERC own, develop, construct, manage and operate electric transmission, distribution and generation facilities or natural gas distribution facilities, as applicable. A key component of our growth is our ability to construct and operate these facilities. As part of these operations, we must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. We have previously experienced delays in receiving approval with regards to certain permits and licenses, and have had investigations and enforcement actions with regards to certain of our projects, which have caused delays to our projects in the past. Our projects, such as in the case of Houston Electric’s proposed 765 kV and other transmission projects, have faced and may in the future face opposition from individuals, community organizations, environmental and other activist groups, and other public-interest entities. In the future, these approvals may not be granted in a timely manner (including due to potential staffing issues at U.S. regulatory agencies) or at all or may be modified, rescinded or fail to be extended for a variety of reasons, including due to legal or regulatory changes or political, public and community relations pressure. Should we in the future be unsuccessful in obtaining necessary licenses or permits on acceptable terms or resolving third-party challenges to such licenses or permits, should there be a delay in obtaining or renewing necessary licenses or permits, or should regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances, our future net income and cash flows could be reduced and our business, financial condition and results of operations could be impacted. Any failure to negotiate successful project development agreements for new facilities with third parties could also have adverse effects. We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could negatively affect our financial results. The Registrants are subject to numerous legal proceedings, including lawsuits and environmental matters in addition to regulatory proceedings, the most significant of which are summarized in Note 14 to the consolidated financial statements. Litigation is subject to many uncertainties; recent trends have shown jury verdicts, settlements and other liability have been significantly increasing; and the Registrants cannot predict the outcome of all matters with assurance. Additionally, under some circumstances, the Registrants could potentially have claims filed against them or incur liabilities associated with assets and businesses no longer owned by them as a result of sales, divestitures or other transfers to third parties who may be unable to fulfill their indemnity obligations to the Registrants. Final resolution of these matters, or any potential future claims or liabilities, may require additional expenditures over an extended period of time that may be in excess of established insurance or reserves and may have an adverse effect on the Registrants’ businesses, financial condition, results of operations and cash flows. For further information, see “— Our insurance coverage may not...” Customers’, investors’, legislators’, regulators’, creditors’, rating agencies’ and other stakeholders’ opinions of us are affected by many factors, including actual or perceived system reliability and safety, the speed of our response to service interruptions, rates and customer affordability, our ability to successfully execute our capital plan, media coverage and actions by third parties, and negative opinions developed by such stakeholders could harm our reputation and have an adverse impact on our business, financial condition, results of operations and cash flows. Our results are influenced by the expectations of our customers, investors, legislators, regulators, creditors, rating agencies and other stakeholders. Those expectations are based, in part, on the actual or perceived reliability, safety and affordability of our utility services. Our actual or perceived ability to prevent, mitigate, prepare for and timely respond to electric outages, natural gas leaks or events and related accidents and similar interruptions caused by severe weather, physical or cybersecurity incidents or other unanticipated events, as well as our own or third parties’ actions or failure to act, can affect customer, regulator and legislator satisfaction or potentially subject us to regulatory action and litigation. For example, CenterPoint Energy, CenterPoint Energy Service Company, LLC and Houston Electric are subject to litigation and claims arising out of Hurricane Beryl and various federal, state and local governmental and regulatory agencies and other entities called for or conducted inquiries and investigations into Hurricane Beryl and the efforts made by Houston Electric to prepare for, and respond to, this event, including the associated electric service outage issues. Ongoing and future inquiries, investigations and proposed legislation regarding Hurricane Beryl could adversely affect our business, financial condition, results of operations and cash flows, including with respect to our recovery of costs incurred as a result of Hurricane Beryl or future severe weather events; the assessment of financial penalties; changes to Houston Electric’s system, service territories, operations and/or 26 regulatory treatment; and the viability for Houston Electric to continue leasing TEEEF. The level of rates and actual or perceived affordability of our services, the timing and magnitude of rate increases, and the volatility of rates can also affect the opinions of customers, legislators, regulators and other political figures of us. For example, in 2025, the Governor of Indiana directed the commissioner of the OUCC to evaluate utilities’ profits and find cost-saving measures to ease the financial burden on customers. Our ability to successfully execute our capital plan may also affect customers’, investors’, legislators’, regulators’, creditors’, rating agencies’ and other stakeholders’ opinions and actions. Opinions of us can additionally be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation. Our efforts to secure permits and/or acquire land and easements (including through eminent domain) for infrastructure investments, including with respect to Houston Electric’s proposed 765 kV and other transmission projects, as well as execute on and/or obtain regulatory approvals for transmission, generation and other facilities can also affect opinions of us. We are also subject to adverse publicity related to actual or perceived environmental practices or impacts, including in relation to climate change and our ability to timely achieve our energy transition goals, as well as negative opinions regarding the appropriateness of our climate-related goals. If customers, investors, legislators, regulators, creditors, rating agencies or other stakeholders have or develop a negative opinion of us or our utility services, this could result in, among other things, less favorable legislative and regulatory outcomes (including but not limited to failure to obtain requested approvals on capital investments) or increased regulatory oversight, negative effects on our access to, and the cost of, capital, project delays or cancellations, increased litigation and negative public perception. The foregoing may harm our reputation and have adverse effects on our business, financial condition, results of operations and cash flows. We are subject to operational and financial risks and liabilities arising from environmental laws and regulations, including regulation of CCR, climate change legislation and certain local initiatives that seek to limit fossil fuel usage. Our operations are subject to stringent and complex laws and regulations pertaining to the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric generating facilities and electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, including among others, restricting the use of fossil fuels through future climate legislation or regulation, restricting the use of natural gas-fired appliances in new homes, limiting airborne emissions from generating facilities, restricting the way we manage wastes, including wastewater discharges, air emissions and CCR removal, and requiring remedial action or monitoring to mitigate environmental actions caused by our operations or attributable to former operations. Environmental laws and regulations applicable to our operations are complex and subject to continued uncertainty, and we are subject to risks from changing or conflicting interpretations of existing laws, modifications to existing laws, new laws, and new or modified permit terms. We may need to spend substantial amounts and devote other resources from time to time to comply with these requirements. Further, in the course of operations we have released, and may in the future inadvertently release, various contaminants. Any such releases could have a significant impact on the environment and result in significant fines. Failure to comply with applicable environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including measures taken by individuals and non-governmental organizations seeking to enforce environmental laws against us or allege a failure to comply with such laws, and could lead to the assessment of monetary penalties, which we have been subject to from time to time, revocation of permits, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean, restore and monitor sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. Regulatory agencies have also adopted, and from time to time consider adopting, new legislation and/or modifying existing laws and regulations to reduce GHGs. There continues to be a wide-ranging policy and regulatory debate, at the state level, nationally and internationally, regarding the possible means for their regulation. Although the United States withdrew from the Paris Agreement in 2026, and more recently the United Nations Framework Convention on Climate Change, and the current federal administration has revised and is expected to further revise compliance requirements under a number of federal environmental regulatory programs, many states and localities continue to pursue their own climate policies, and differences in energy policy priorities adopted by future federal administrations could result in additional GHG reduction requirements in the United States. As a distributor and transporter of natural gas and electricity, and a generator of electricity in Indiana, the Registrants’ revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory action that would require installation of new control technologies or a modification of their operations or that would have the effect of reducing the consumption of natural gas or electricity or prevent the use of certain fuel types. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be greater than the amounts we currently anticipate, which could adversely affect our business, financial condition, results of operations and cash flows. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a 27 decrease in demand for our services. For further discussion, see “Business—Environmental Matters” in Item 1 and “ —Our natural gas businesses must compete with…” Evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels may have substantial impacts on our electric generation and natural gas businesses. For example, because Indiana Electric currently relies on coal for a portion of its generation capacity, certain financial institutions may choose not to participate in CenterPoint Energy’s financing arrangements until future coal generation closures satisfy their thresholds for investments. Further, some investors choose to not invest in CenterPoint Energy due to CenterPoint Energy’s and CERC’s use of fossil fuels. Also, certain cities in CenterPoint Energy’s and CERC’s operational footprint have discussed the adoption of initiatives to prohibit the construction of new natural gas facilities that would provide service and focus on electrification. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on fossil natural gas. Certain state and local governments have also passed, or are considering, legislation banning the use of natural gas-fired appliances in new homes, which could affect consumer use of natural gas. Should such bans be enacted within CenterPoint Energy’s and CERC’s operational footprint, they could adversely affect consumer demand for natural gas. Any such initiatives and legislation could adversely affect CenterPoint Energy’s and CERC’s businesses, financial condition, results of operations and cash flows. Further, certain investors, lenders, regulators and other stakeholders are focusing on issues related to environmental justice, which may result in increased scrutiny of our applicable regulatory processes and additional costs of compliance or may adversely affect our reputation. While President Trump in 2025 signed an executive order calling to terminate all environmental justice offices and positions in the federal government, as well as any environmental justice initiatives, programs or other activities, the focus on environmental justice matters by certain stakeholders may nevertheless provide communities opposed to our operations with greater opportunities to challenge or delay our projects. Opposition to our projects or successful challenges or appeals to permits issued for our projects could result in cancellation of such projects and the loss of investments we have made with respect thereto. CenterPoint Energy is subject to operational, financial and other risks and potential liabilities associated with our sustainability and related activities, including the implementation of and efforts to achieve our energy transition goals. CenterPoint Energy has adopted energy transition goals and its analysis and plans for execution require it to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees, and our ability to achieve these goals will ultimately be driven by the needs of our business, the needs and desires of the customers, jurisdictions and other stakeholders we serve and our performance for our shareholders. In addition, forecasting is inherently speculative and the trajectory of the greater energy transition is uncertain. Should one or more of CenterPoint Energy’s underlying assumptions require updating, our actual results and ability to make progress towards and achieve our energy transition goals and the timing thereof could differ materially from its expectations, and CenterPoint Energy may elect to modify or update such goals. Further, there can be no guarantee that CenterPoint Energy will sustain or achieve these goals. Certain of the assumptions that could impact CenterPoint Energy’s ability to meet our energy transition goals and the timing thereof include, but are not limited to: GHG emission levels, service territory size, capacity needs and customer demand remaining in line with CenterPoint Energy’s expectations when such goals were announced, including with respect to demand for our services and in relation to the recent sale of CenterPoint Energy’s Louisiana and Mississippi natural gas LDC businesses and the announced sale of CenterPoint Energy’s Ohio natural gas LDC business; the ability to appropriately estimate and effectively manage business opportunities from and maintain reliability in connection with new customers and load growth resulting from, among other things, expansion of data centers (associated with, among other things, increasing demand for AI), energy refining and exports, advanced manufacturing and logistics in our service territories; regulatory approvals related to Indiana Electric’s generation transition plan and our ability to obtain such approvals; the ability to execute anticipated divestitures, portfolio optimizations or other strategic transactions; interconnection delays in the footprints of regional transmission organizations and/or interconnection costs; cost and affordability of customer rates and related concerns; customer demand for GHG emission free or lower GHG emissions energy; impacts of regulations, legislation or other governmental action, including those related to our operation of certain generating facilities (including the U.S. Department of Energy’s December 2025 emergency 202(c) order directing Indiana Electric to continue operating F.B. Culley Unit 2 through March 23, 2026), the environment and tax (including the effects of the OBBBA, Executive Order 14315, the IRA and any further changes to or the repeal of the renewable energy tax credits enacted in the IRA); federal and state executive, legislative and regulatory actions (including regulatory uncertainty resulting from changes in federal energy policy) and support for certain types of generation; impacts of future carbon pricing regulation or legislation, including a future carbon tax; price, availability and regulation of carbon offsets; price of fuel, such as natural gas; cost and technological development/innovation, adoption and commercialization of energy generation technologies, such as wind and solar, natural gas and storage solutions, and alternative energy, including electric vehicles; our ability to implement our modernization plans for pipelines and facilities; the ability to complete and timely implement and maintain system reliability during and after transitioning to generation alternatives to 28 Indiana Electric’s coal generation; execution of the retirement or fuel conversion of Indiana Electric’s coal facilities on anticipated timelines or at all; the ability to construct and/or permit new natural gas pipelines; the ability to procure resources needed to build at a reasonable cost, the lack of or scarcity of resources and labor, any project cancellations, construction delays or overruns (including as a result of changes in U.S. or foreign trade policies) and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; changes in applicable standards, metrics, methodologies or frameworks; and enhancement of energy efficiencies. Our businesses have in the past and may in the future face increased scrutiny from investors, governmental authorities and other stakeholders related to our sustainability practices, including our human capital management activities, as well as the goals, targets, and objectives we announce, our methodologies and timelines for pursuing them, our progress towards achieving them and related disclosures. We could also face challenges with managing conflicting requirements and our various stakeholders’ expectations. We may be unable to satisfy all of our stakeholders, and to the extent our sustainability practices (including our human capital management activities) do not align with investor or other stakeholder expectations and standards, which continue to evolve, vary, and sometimes conflict, our businesses, including our reputation, ability to attract or retain employees, and attractiveness as an investment or business partner could be negatively affected and we could be exposed to enforcement actions and litigation. Similarly, our failure or perceived failure to pursue, fulfill or demonstrate meaningful progress towards our sustainability-focused goals, targets and objectives, to comply with or otherwise meet ethical, environmental or other standards, regulations or expectations, which may be varied or conflicting, or to satisfy various reporting standards with respect to these matters (including if there are real or perceived inaccuracies in the data and information we report or if we are exposed to allegations that certain public statements regarding sustainability-related matters are false and misleading “greenwashing” campaigns), within the timelines we announce, or at all, could adversely affect our business or reputation, as well as expose us to government enforcement actions and litigation. Developing and implementing plans for compliance with voluntary climate commitments can lead to additional capital, personnel and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects. To the extent that we believe any of these costs are recoverable in rates, cost recovery could be resisted by our regulators and the public, and our regulators might attempt to deny or defer timely recovery of these costs. Moreover, we cannot predict the ultimate impact of achieving our emissions reduction goals, or the various implementation aspects, on our system reliability or our business, financial condition, results of operations and cash flows. We are subject to extensive regulation, which could result in higher costs for system improvements, as well as fines or other sanctions. In the planning and management of our operations, we must address existing and proposed laws and regulations regarding safety, reliability and other matters, as well as potential changes in regulatory frameworks, including reinterpretation of such regulations, initiatives by federal and state legislatures, regional transmission organizations (e.g., ERCOT and MISO), utility regulators, and taxing authorities, and actions by local jurisdictions regarding such matters. As has occurred in the past, if it were determined that we failed to comply with applicable laws and regulations or with applicable tariff provisions regarding such matters, we could become subject to fines, penalties, refund or disgorgement orders, or disallowed costs, or be required to implement additional compliance or remediation programs, the cost of which could be material. We cannot predict the impact of new laws, rules, regulations, tariffs, principles, or practices by federal or state agencies or regional transmission operators, or challenges or changes to present laws, rules, regulations, tariffs, principles, or practices and the interpretation of any adoption or change. Significant changes in the nature of the regulation of our businesses, including expiration or discontinuation of, or significant changes to, existing regulatory mechanisms, and the current federal administration’s approach to U.S. energy policy and resultant changes in regulatory enforcement priorities, and/or evolving interpretations of existing regulatory requirements, could require changes to our business planning, strategy and management of our businesses and could adversely affect our business, financial condition, results of operations and cash flows. Houston Electric and Indiana Electric are members of ERCOT and MISO, respectively, which serve the electric transmission needs of their applicable regions. As a result of their respective participation in ERCOT and MISO, Houston Electric and Indiana Electric do not have sole operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. FERC has designated NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. FERC has approved the delegation by NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation, and for reliability in the portion of MISO that includes Indiana Electric to Reliability First Corporation, a Delaware non-profit corporation. Compliance with mandatory reliability standards may subject Houston Electric and Indiana Electric to higher operating costs and may result in increased capital expenditures, which may not be fully recoverable in rates. Houston Electric 29 and Indiana Electric have received fines in the past for noncompliance. If Houston Electric or Indiana Electric were to be found to be in noncompliance with applicable mandatory reliability standards again, they would be subject to additional sanctions, including monetary penalties, which could range as high as over a million dollars per violation per day, and non-monetary penalties, such as having to file a mitigation plan to prevent recurrence of a similar violation and having certain milestones in such plan tracked. Additionally, compliance with existing and potential new regulations related to CERC’s operation and maintenance of natural gas infrastructure could result in significant costs. PHMSA is responsible for administering the DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum and other hazardous materials by pipelines. PHMSA continues to develop regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance and emergency response of natural gas pipeline infrastructure. We have programs in place to comply with regulations related to CERC’s operation and maintenance of natural gas infrastructure, such as leak detection surveys and corrosion and critical valve inspections, and we systematically monitor and renew infrastructure over time; however, CERC has failed to maintain compliance with applicable regulations in the past and has received fines for past noncompliance. A significant incident or material finding of non-compliance in the future could result in enforcement action, penalties, higher costs of operations and adverse impacts on our regulatory proceedings, any of which could have an adverse effect on our business, financial condition, results of operations and cash flows. Our businesses may be adversely affected by the intentional misconduct of our employees, consultants, contractors, suppliers and vendors. We are committed to living our core values of safety, integrity, accountability, initiative and respect and complying with all applicable laws and regulations. Despite that commitment and efforts to prevent misconduct, it is possible for employees, consultants, contractors, suppliers and vendors to engage in intentional misconduct, fail to uphold our core values, and violate laws and regulations for individual gain through contract or procurement fraud, misappropriation, bribery or corruption, fraudulent related-party transactions and serious breaches of our Ethics and Compliance Codes and other policies. If such intentional misconduct by employees, consultants, contractors, suppliers and vendors should occur, it could result in substantial liability, higher costs, increased regulatory scrutiny and negative public perceptions, any of which could have an adverse effect on our business, financial condition, results of operations and cash flows. From time to time, including as part of our Ethics and Compliance program’s efforts to detect misconduct, we become aware of and expect to continue to become aware of instances of misconduct by employees, consultants, contractors, suppliers and vendors, which we investigate, remediate and disclose as appropriate and proportionate to the incident. Risk Factors Affecting Financial, Economic and Market Risks Disruptions to the global supply chain, inflation, labor shortages and scarcity of certain materials may impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our business, financial condition, results of operations and cash flows. The global supply chain has experienced and may continue to experience significant disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and policy instability, tariffs and changes in U.S. and foreign trade policy, changes in laws (including tax laws), executive orders, the COVID-19 pandemic, labor shortages, resource availability, long lead times, manufacturer production limitations, delivery delays, inflation, severe weather events and disruptions to internal or international shipping, including as a result of armed conflicts, and these disruptions have adversely impacted the utility industry. We, as well as other companies in our industry, have experienced supply chain disruptions, and we may continue to experience this in the future. Moreover, inflation and high interest rates have contributed, and may continue to contribute, to increased prices for materials and services experienced by us and other companies in our industry. We have also faced, and may continue to face, a shortage of experienced and qualified personnel in certain positions, which has resulted in increased competition for skilled labor and wage inflation. Additionally, increased demand for materials necessary for our business has resulted, and may continue to result, in greater competition for and scarcity of such materials. For example, the increase in demand for electricity across the United States has contributed to large demand increases for transformers, which has caused and may continue to cause supply shortages for transformers. Examples of materials necessary for our business that we and our industry have experienced difficulties in procuring include transformers, wires, cables, meters, poles, electronic components, steel, aluminum and solar panels. If the supply chain disruption, inflation, labor shortages and scarcity of certain materials persist or worsen, we and the third parties that we contract with may experience difficulties in procuring the resources and labor necessary to operate our businesses in a timely and cost-efficient manner or at all, which could adversely impact, among other things, our ability to perform storm restoration activities, execute on our 10-year capital plan, execute Indiana Electric’s generation transition plan and/or achieve our energy transition goals. Even if we are able to procure the necessary resources and labor, we might not be able to do so at a reasonable cost or in a timely manner, which could result in project 30 cancellations or scope changes, delays, cost overruns, under-recovery of costs, customer affordability concerns and challenges to our ability to remain in compliance with applicable laws, regulations and policies. If we are unable to fully execute on capital plans, our business, financial condition, results of operations and cash flows may be adversely affected. If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures and operations or refinance outstanding indebtedness could be limited. Our businesses are capital intensive, with significant and increasing capital spending expected in future periods. We rely on various sources to finance our capital expenditures and operations. For example, we depend on (i) long-term debt, (ii) borrowings through our revolving credit facilities and, for CenterPoint Energy and CERC, commercial paper programs and (iii) if market conditions permit, issuances of additional shares of common stock or shares of preferred stock by CenterPoint Energy, including through our at-the-market program. We may also use such sources to refinance any outstanding indebtedness as it matures. Additionally, from time to time, our operating subsidiaries, including Houston Electric and CERC, may rely on intercompany borrowings from CenterPoint Energy that may be sourced from CenterPoint Energy’s external financings. These arrangements could expose us to risks, including exposure to losses upon the occurrence of certain events related to the development, construction, operation or financing of applicable projects. As of December 31, 2025, CenterPoint Energy had nearly $23 billion of outstanding indebtedness on a consolidated basis, which included $714 million of non-recourse Securitization Bonds. For information on outstanding indebtedness of CenterPoint Energy, Houston Electric and CERC as well as future maturities, see Note 12 to the consolidated financial statements. In addition, external sources of capital may not be adequate or available on reasonable terms. If we are unable to arrange future financings on acceptable terms, our ability to finance our operations and capital expenditures, including our 10-year capital plan announced in 2025 and increased in February 2026 (through which CenterPoint Energy plans to invest at least $65.5 billion through 2035), or refinance our outstanding indebtedness could be limited. Any of these outcomes could have a material adverse effect on our business, financial condition, results of operations and cash flows. Our future financing activities may be significantly affected by, among other things: • general economic and capital market conditions, including inflation and recession; • credit availability from financial institutions and other lenders; • investor confidence in us, our regulatory environment, our industry and the markets in which we operate; • the future performance of our businesses; • maintenance of acceptable credit ratings; • actions from the Federal Reserve, including changes in interest rates and unanticipated actions; • market expectations regarding our future earnings and cash flows; • investor willingness to invest in companies associated with fossil fuels; • our ability to access capital markets on reasonable terms; • acceleration of payments or decreased credit lines • timing and adequacy of future cost recovery, including securitizations, by jurisdictions in which we operate; • changes in regulation, governmental policy (including tax and trade policy, such as tariffs) or governmental programs (including tax incentives or tax credits, loans, grants, guarantees and other subsidies); and • provisions of relevant securities laws and our ability to obtain required regulatory authorization for issuances of securities. The Registrants’ current credit ratings and any changes in credit ratings in 2025 and to date in 2026 are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Other Matters — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of Part II of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be reduced or withdrawn by a rating agency. The Registrants note these credit ratings are not recommendations to buy, sell or hold their securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of the Registrants’ credit ratings could have an adverse impact on their ability to access capital on acceptable terms. For example, if CERC’s credit rating were to decline, it may have an adverse impact on the cost of borrowings and, in extraordinary market conditions, it may limit the ability to access the debt capital markets. Additionally, CERC might be required to post collateral under its shipping arrangements or to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC’s business, financial condition, results of operations and cash flows could be adversely affected. 31 Changes in U.S. or foreign trade policies, including the imposition of tariffs and other trade actions, and other factors beyond our control may adversely impact our business, financial condition, results of operations and cash flows. The U.S. government has taken executive action and proposed additional measures intended to alter the U.S. approach to international trade policy, the terms of certain existing bilateral or multi‐lateral trade agreements and trading arrangements with foreign countries. Such changes to U.S. international trade policy, and retaliatory trade measures that foreign governments have taken and may take in the future in response, including the imposition of tariffs, bans, sanctions, export or import controls, or other measures that restrict international trade, or the threat of such actions, and uncertainties about tariffs and their effects on trading relationships, may affect, and in some cases have affected, the Registrants’ ability to access the capital markets, contribute to inflation in the markets in which the Registrants operate, increase costs and cost volatility, impact availability of goods, materials and services (including those necessary for our business and capital plan), further extend lead times or otherwise negatively impact the global supply chain. While the U.S. government has announced various trade deals, many such agreements are preliminary and may be subject to change. Further, any future disagreement between the U.S. government and other countries over the implementation of trade deals or any failure to obtain required governmental approvals or otherwise reach a final agreement could result in prolonged uncertainty regarding the scope and duration of such trade actions by the U.S. government and other countries. Such announcements, rescissions of tariffs on foreign jurisdictions and other trade actions have increased uncertainty regarding the ultimate effects of the tariffs on economic conditions. In addition, related geopolitical and domestic political developments, such as existing and potential trade wars, uncertainty regarding changes in trade policy and other events beyond our control, have increased and may continue to increase levels of political and economic unpredictability globally and the volatility of global financial markets. Such developments could adversely affect our business, financial condition, results of operations and cash flows. CenterPoint Energy is a holding company that derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. As a result, CenterPoint Energy depends on the performance of and distributions from its subsidiaries to meet its payment obligations and to pay dividends on its common stock, and provisions of applicable law or contractual restrictions could limit the amount of those distributions. CenterPoint Energy derives all of its operating income from, and holds substantially all of its assets through, its subsidiaries. Similarly, CERC derives a significant portion of its operating income from and holds a significant portion of its assets through its subsidiaries, including Indiana Gas and CEOH. As a result, CenterPoint Energy, and to a lesser extent, CERC, depend on the performance of and distributions from their respective subsidiaries to meet their respective payment obligations and to pay dividends on their respective common stock. In general, CenterPoint Energy’s and CERC’s subsidiaries are separate and distinct legal entities and have no obligation to provide them with funds for their respective payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit CenterPoint Energy’s and CERC’s respective subsidiaries’ ability to make payments or other distributions to CenterPoint Energy or CERC, and their respective subsidiaries could agree to contractual restrictions on their ability to make payments or other distributions. Further, ring-fencing measures, such as those adopted by Houston Electric in connection with its 2019 base rate case, could be imposed on subsidiaries of CenterPoint Energy and CERC in the future through legislation or state commission rules or orders. The imposition of any additional measures impacting CenterPoint Energy’s or CERC’s ability to receive dividends from their respective subsidiaries could adversely affect CenterPoint Energy’s credit quality, business, financial condition, results of operations and cash flows. Any such adverse effect on CenterPoint Energy could also adversely affect Houston Electric’s and/or CERC’s credit quality, business, financial condition, results of operations and cash flows as CenterPoint Energy may not be able to financially support Houston Electric and/or CERC if and when necessary. CenterPoint Energy’s right to receive assets of any subsidiary, and therefore the right of its creditors to participate in those assets, are structurally subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if CenterPoint Energy were a creditor of any subsidiary, its rights as a creditor would likely be effectively subordinated to any security interest in the assets of that subsidiary and any senior indebtedness of the subsidiary. CenterPoint Energy’s previously owned Energy Systems Group business has performance and warranty obligations, some of which are guaranteed by CenterPoint Energy. On June 30, 2023, CenterPoint Energy closed the sale of its Energy Systems Group business. Prior to June 30, 2023 and as part of the normal course of its business, Energy Systems Group issued performance bonds and other forms of assurance that committed it to operate facilities, pay vendors or subcontractors and support warranty obligations. As the parent company prior to the closing of the sale, CenterPoint Energy or Vectren guaranteed certain of its subsidiaries’ commitments. When Energy Systems Group was wholly owned by CenterPoint Energy, these guarantees did not represent incremental consolidated obligations, but rather, these guarantees represented guarantees of Energy Systems Group’s obligations to allow it to conduct business without posting other forms of assurance. Neither CenterPoint Energy nor Vectren has been called upon to satisfy any 32 obligations pursuant to these parental guarantees to date but may be required to do so in the future. For further information, see Note 14(b) to the consolidated financial statements. An impairment of goodwill, long-lived assets or equity method investments or a fair value adjustment could reduce our earnings. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is tested for impairment at least annually, as well as when events or changes in circumstances indicates the carrying value may not be recoverable. While CenterPoint Energy has identified and recorded goodwill impairments in the past, no impairments to goodwill were recorded during the years ended December 31, 2025, 2024, and 2023. See Note 6 to the consolidated financial statements for further information. Should the annual goodwill impairment test or another periodic impairment test or an observable transaction indicate the fair value of our assets is less than the carrying value, we would be required to take a non-cash charge to earnings with a correlative effect on equity, increasing balance sheet leverage as measured by debt to total capitalization. A non-cash impairment charge or fair value adjustment could adversely impact our business, financial condition, results of operations and cash flows. If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments may result in significant cash payments, which would adversely impact its cash flows and liquidity. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows and liquidity. CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2025. CenterPoint Energy owns shares of ZENS-Related Securities equal to approximately 100% of the reference shares used to calculate its obligation to the holders of the ZENS. CenterPoint Energy may redeem all of the ZENS at any time at a redemption amount per ZENS equal to the higher of the contingent principal amount of less than $0.1 million in the aggregate, or less than $0.01 per ZENS, as of December 31, 2025, or the sum of the current market value of the reference shares attributable to one ZENS at the time of redemption. In the event CenterPoint Energy redeems the ZENS, in addition to the redemption amount, it would be required to pay deferred taxes related to the ZENS, to the extent such taxes were not currently offset by net operating loss carryforwards or CAMT carryforwards. CenterPoint Energy’s ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2025, deferred taxes of approximately $897 million would have been payable in 2025, based on 2025 tax rates in effect, and disregarding the availability of net operating loss carryforwards and CAMT carryforwards. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2025 to fund the aggregate redemption amount, capital gains taxes of approximately $72 million would have been payable in 2025, disregarding the availability of net operating loss carryforwards and CAMT carryforwards. As of December 31, 2025, CenterPoint Energy had both net operating loss carryforwards and CAMT carryforwards available from its filed 2024 federal income tax return that can be applied to largely offset the cash tax outflow that would result from a retirement or exchange of ZENS. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows and liquidity, subject to the availability of net operating loss carryforwards or CAMT carryforwards. This could happen if CenterPoint Energy’s creditworthiness were to drop, the market for the ZENS were to become illiquid, or for some other reason. While funds for the payment of cash upon exchange of ZENS could be obtained from the sale of the shares of ZENS-Related Securities CenterPoint Energy owns or from other sources, ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and ZENS-Related Securities shares would typically be reversed when ZENS are exchanged and ZENS-Related Securities shares are sold, subject to the availability of net operating loss carryforwards or CAMT carryforwards to reduce the cash taxes payable in the year of exchange or sale. Our potential business strategies and strategic initiatives, including merger and acquisition activities and the disposition of assets or businesses, may not be completed or perform as expected, adversely affecting our business, financial condition, results of operations and cash flows. Our business, financial condition, results of operations and cash flows depend, in part, on our management’s ability to implement our business strategies successfully and realize the anticipated benefits therefrom. In 2025, we announced our strategic goals for CenterPoint Energy, including our new 10-year capital plan. Our strategic goals are subject to the risks described in this section and various assumptions. These assumptions may require updating or we may not be able to execute on these strategic goals in a timely manner or at all. If we are unable to execute on our strategic goals, including our 10-year capital plan, the benefits therefrom may not be fully realized, if at all, and our reputation may be adversely affected. From time to time we have made, and may continue to make, acquisitions or divestitures of, or other similar transactions involving, businesses and assets, such as our announced sale of our Ohio natural gas LDC business, Houston Electric’s release 33 of its large TEEEF units to the San Antonio area and other potential future releasing and subleasing of TEEEF, form joint ventures or undertake restructurings, such as the Restructuring. However, suitable acquisition candidates or potential buyers may not continue to be available on terms and conditions we find acceptable, or the expected benefits of completed acquisitions, dispositions or similar transactions may not be realized fully or at all or may not be realized in the anticipated timeframe. If we are unable to make acquisitions, or if those acquisitions do not perform as anticipated, our future growth may be adversely affected. Further, any completed or future acquisitions, dispositions or other strategic transactions involve substantial risks, including the following: • acquired businesses or assets, or other business strategies and strategic initiatives may not produce revenues, earnings or cash flow at anticipated levels; • acquired businesses or assets, or other business strategies and strategic initiatives could have environmental, permitting or other problems for which contractual protections prove inadequate; • we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited; • we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; • acquisitions, dispositions or other strategic transactions, or the pursuit of such transactions, including any separation or disentanglement efforts or requirements, such as the provision of transition services, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain current business standards, controls and procedures; • we may not receive regulatory approvals necessary to complete an acquisition, disposition or similar transaction in a timely manner or at all; and • shifting governmental policies may impact governmental support for strategic transactions. On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement to sell its Ohio natural gas LDC business. The transaction is expected to close in the fourth quarter of 2026, subject to the satisfaction of customary closing conditions. For further information, see Note 4 to the consolidated financial statements. We can make no assurances regarding the completion of this sale, which could be subject to delays or may not ultimately be consummated. Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our business, financial condition, results of operations and cash flows. CenterPoint Energy and its subsidiaries maintain qualified defined benefit pension plans covering certain of its employees. Costs associated with these plans are dependent upon a number of factors including the investment returns on plan assets, the level of interest rates used to calculate the funded status of the plan, contributions to the plan, the number of plan participants and government regulations with respect to funding requirements and the calculation of plan liabilities. Funding requirements may increase and CenterPoint Energy may be required to make unplanned contributions in the event of a decline in the market value of plan assets, a decline in the interest rates used to calculate the present value of future plan obligations, or government regulations that increase minimum funding requirements or the pension liability. See Note 8 to the consolidated financial statements for further information. In addition to affecting CenterPoint Energy’s funding requirements, these factors could adversely affect our business, financial condition, results of operations and cash flows. We may be significantly affected by changes in federal income tax laws and regulations, including any comprehensive federal tax reform legislation. Our businesses are impacted by U.S. federal income tax policy. The TCJA, CARES Act, the IRA and OBBBA significantly changed the U.S. Internal Revenue Code, including taxation of U.S. corporations, by among other things, reducing the federal corporate income tax rate, altering the expensing of capital expenditures, enacting a new CAMT, and phasing out previously expanded federal tax credits for cleaner energy production. Based on guidance available as of the date of the filing of this Form 10-K, the Registrants will continue to be subject to the CAMT included in the IRA. The interpretive guidance issued by the IRS and state tax authorities, as well as related federal executive orders, may be inconsistent with our interpretation and the legislation could be subject to amendments, which could lessen or increase certain impacts of the legislation. In addition, while certain regulators have allowed the Registrants to recover certain costs associated with the CAMT in the past, the regulatory treatment of the expanded tax credits and CAMT could impact the Registrants’ future 34 cash flows, and this legislation could result in unintended consequences not yet identified that could have an adverse impact on the Registrants’ financial results and future cash flows. Further changes in federal tax legislation or guidance, or uncertainties regarding the repeal, continuation or interpretation of such tax legislation or guidance, could significantly change the federal income tax laws applicable to domestic businesses, including changes that may impact investment incentives and deductions for depreciation and interest, among other deductions. Additional new federal tax reform legislation and the implementation of new or increased tariffs could lead to increases in market interest rates, a decrease in U.S. economic growth, and/or recession. In addition, interpretations, regulations, amendments, or technical corrections that affect the amount and timing of income tax payments could adversely affect our liquidity. While CenterPoint Energy and its subsidiaries cannot assess the overall impact of any such potential legislation or other actions on our businesses, it is possible that our business, financial condition, results of operations and cash flows could be negatively impacted. Furthermore, with any enacted federal tax reform legislation, it is uncertain how state commissions and local municipalities may require us to respond to the effects of such tax legislation, including determining the treatment of EDIT and other increases and decreases in our revenue requirements. As such, potential regulatory actions in response to any enacted tax legislation could adversely affect our business, financial condition, results of operations and cash flows. Risk Factors Affecting Safety and Security Risks The Registrants’ businesses have safety risks. The Registrants’ facilities and distribution and transmission systems have been and may in the future be involved in incidents that result in injury, death, or property loss to employees, customers, third parties (including vendors, suppliers and contractors), or the public. Although the Registrants have insurance coverage for many potential incidents, depending upon the nature and severity of any incident, they have in the past and could in the future experience financial loss, claims and litigation, damage to their reputation, and negative consequences from regulatory authorities or other public authorities. Further, certain CenterPoint Energy employees who work in the field have experienced threats of violence during the performance of their work. Threats of violence, actual violence and other concerns may result in employees and third parties supporting the work of the Registrants sustaining serious injuries and being unable or unwilling to complete critical functions, which could adversely affect our businesses, financial condition, results of operations and cash flows, and could make it harder to, among other things, recruit and retain certain employees. Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our business, financial condition, results of operations and cash flows. We are subject to cyber and physical security risks related to our information technology systems, operational technology, network infrastructure and other technology and facilities used to conduct almost all of our businesses. The operation of our electric transmission, distribution and generation systems is dependent on the physical interconnection of our facilities, as well as communications among the various components of our systems and the systems of supply chain stakeholders (such as vendors, contractors and suppliers). Further, certain of the various internal systems we use to conduct our businesses are highly integrated. Consequently, a cyberattack or unauthorized access in any one of these systems could potentially impact the other systems. Similarly, our business operations, including our transmission systems and natural gas pipelines, are part of an interconnected system. Disruption of those systems, or our ability to communicate with those systems, whether caused by physical disruption such as storms or other natural disasters, by failure of equipment or technology or by man-made events, such as cyberattacks or acts of terrorism, may disrupt our ability to conduct operations and control assets, lead to operational interruptions and negatively impact our business. The sophistication of cybersecurity threats, including those leveraging AI, continues to increase, and the controls and preventative actions we take to reduce the risk of cybersecurity incidents and protect our systems, including the regular testing of our cybersecurity incident response plan, may be insufficient. In addition, new technology that could result in greater operational efficiency, such as AI and cloud-based infrastructure, may further expose our computer systems to the risk of cybersecurity incidents. Also, remote working arrangements could increase our data security risks, including loss of data related to sensitive customer, employee, financial and operating system information, through insider or outsider actions. Cyberattacks, including deep fakes (which are increasingly more difficult to identify as fake), phishing, smishing, vishing or quishing attacks and threats from the use of malware, ransomware and viruses or malicious code, and unauthorized access could also result in the loss, or unauthorized use, of confidential, proprietary or critical infrastructure data or security breaches of other information technology systems that could disrupt operations and critical business functions, adversely affect our reputation, impact our customers, increase costs and subject us to possible legal claims and liability. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from such 35 attacks, our cybersecurity program does not prevent all breaches or cyberattack incidents. Publicly known vulnerabilities in our information technology and operational technology environments may not be remediated before an adversary could discover or exploit them. Attackers can also exploit new, unknown vulnerabilities (e.g., zero-day vulnerabilities) and vulnerabilities where a patch or other remediation measure is not yet available. The data that we disclose to, and services we receive from, third parties may be subject to cybersecurity risks associated with threats to third-party systems. These risks include security compromises, vulnerabilities or failures related to the technologies and systems used by service providers, other supply chain stakeholders and/or governmental entities. The potential impact of such threats depends in part on the criticality of the third-party services and/or extent of access these third parties have to our confidential information and/or systems. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. We have also experienced, and expect to continue to experience, cyber intrusions and attacks to our information systems and those of third parties, including supply chain stakeholders and government entities who perform certain services for us or administer and maintain our sensitive information. These prior intrusions and attacks have not had a material impact on our business, financial condition, results of operations and cash flows. Because technology is increasingly complex and cyberattacks are increasingly sophisticated and more frequent, there is a risk such incidents could have an adverse effect on us in the future. The risk of a disruption or breach of our operational technology systems, or the compromise of the data processed in connection with our operations, through a cybersecurity breach or ransomware attack, has increased as attempted attacks have advanced in sophistication and number around the world. Although CenterPoint Energy currently maintains cybersecurity insurance, this insurance is limited in scope and subject to exceptions, conditions and coverage limitations and may not cover the costs associated with potential cybersecurity incidents, and there is no guarantee that the insurance that CenterPoint Energy currently maintains will continue to be available at rates we believe are reasonable. Our continued efforts to integrate, consolidate and streamline our operations have also resulted in increased reliance on current and recently completed projects for technology systems and may increase potential vulnerabilities and points of failure in our information and operations systems. A failure to maintain and enhance existing information technology systems, or the failure of new technology systems to be implemented as designed, could adversely affect our operations. Procedures we implement to protect our systems may be insufficient to protect and safeguard against unauthorized access to secured data. A failure of our technologies or procedures, or our inability to support and integrate these technologies across our subsidiaries, could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks and subject us to possible financial liability or increased regulation or litigation. We depend on the secure operations of our physical assets to transport the energy we deliver and our information technology to process, transmit and store electronic information, including information and operational technology we use to safely operate our energy transportation systems. Companies in our industry face a heightened risk of exposure to and have experienced acts of terrorism and vandalism. Our electric and gas physical infrastructure may be targets of physical security threats or terrorist activities. Further, recent escalation with respect to geopolitical conflicts may increase the likelihood that facilities within the United States, including natural gas distribution systems or electric transmission, distribution or generation systems that we own or on which we rely, will be targeted by strikes, acts of terrorism or cyberattacks. Security breaches, attacks on our infrastructure and facilities, including against the Registrants or as a means to harm a third party by disrupting the transmission and distribution of energy, acts of terrorism, including by foreign or domestic actors, and vandalism could expose our business to a risk of loss, misuse or interruption of critical physical assets or information and functions that affect our operations, as well as potential data privacy breaches and loss of protected personal information and other sensitive information, such as Critical Energy Infrastructure Information. Such losses could result in operational impacts, damage to our assets, public or personal safety incidents, impacts to our customers, damage to the environment, reputational harm, competitive disadvantage, increased regulation and regulatory enforcement actions, litigation and a potential adverse effect on our business, financial condition, results of operations and cash flows. There is no certainty that costs incurred related to actual or thwarted cyberattacks, or for the safeguarding against such security threats, will be recoverable through rates. Compliance with and changes in cybersecurity laws and regulations have a cost and operational impact on our business, and failure to comply with such requirements could adversely impact our business, financial condition, results of operations and cash flows. Regulators have adopted numerous rules and regulations regarding cybersecurity. As a result, CenterPoint Energy continues to take measures to comply with the TSA pipeline security directive requirements applicable to critical pipeline owners and operators. These security directives require CenterPoint Energy to establish, implement and assess a TSA-approved Cybersecurity Implementation Plan that describes the security measures maintained to comply with relevant provisions of the security directives. CenterPoint Energy is also subject to standards enacted by NERC and enforced by FERC regarding protection of critical infrastructure assets required for operating North America's bulk electric system. We may be required to expend significant additional resources and costs to respond to cyberattacks, to continue to modify or enhance our protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. There is no certainty that 36 such costs incurred will be recovered through rates. We also face increasing and evolving disclosure and reporting obligations related to cybersecurity events, and there is no certainty that we will be able to meet existing or future disclosure obligations and avoid the risk of potentially having our disclosures misinterpreted when made. National security or public safety considerations may further affect, or in some instances prevent, our public disclosure of a cybersecurity incident in certain circumstances. Any failure to remain in compliance with these government regulations or failure in our cybersecurity protective measures may result in enforcement actions which may have an adverse effect on our business, financial condition, results of operations and cash flows. Failure to maintain the security of personal information could adversely affect us. In connection with our businesses, we and supply chain stakeholders collect and retain personal information (for example, information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such supply chain stakeholders will adequately protect that information. The regulatory environment surrounding information security and data privacy continues to evolve and is increasingly demanding. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and elevate our costs. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant costs, fines and penalties and liabilities for us. The systems we have implemented to protect our information technology, operational technology and data systems from attacks cannot prevent all security breaches, and the systems we have implemented to manage and protect personal information cannot prevent all privacy breaches. We and some supply chain stakeholders that maintain personal information have experienced, and expect to continue to experience, data privacy incidents and breaches; however, to date, we have not experienced a material data privacy incident or breach. A significant theft, loss or fraudulent use of the personal information we maintain, or failure of our vendors, suppliers and contractors to use or maintain such data in accordance with contractual provisions and other legal requirements, could adversely impact our reputation and could result in significant costs, fines and penalties and liabilities for us. We may not be successful in our adoption, development and deployment of AI, which could adversely affect our business, reputation, or financial results. We are using and exploring the further use of AI, including generative AI, and its ability to enhance the services we offer to the communities we serve. There are significant risks involved in developing and deploying AI, and ineffective or inadequate development or deployment of AI practices by us or supply chain stakeholders could result in unintended consequences. We contract with supply chain stakeholders that use AI in products and services they provide, and we may not have full control or visibility over the quality, performance, security or compliance of the products and services that incorporate AI-related technology. Additionally, the use of AI may not enhance our services or be beneficial to our business, including with respect to the efficiency and resiliency of our systems. For example, AI-related efforts by us or supply chain stakeholders may give rise to risks related to harmful content, accuracy, bias, discrimination, intellectual property infringement or misappropriation, defamation, data privacy, and cybersecurity, among others, which could lead to operational interruptions or otherwise adversely affect our business, reputation or financial results. 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 (which may be conflicting), litigation, ethical concerns, negative consumer perceptions as to automation and AI, or other complications that could adversely affect our business, reputation, or financial results. Developing, testing and deploying resource-intensive AI systems may also require additional investment and increase costs. We may not be able to recover our investments in AI technology through our regulatory proceedings, and our use of, or supply chain stakeholders’ use of, AI may subject us to legal liability. 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 our AI initiatives. General and Other Risks Our revenues and results of operations are seasonal. Our revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity and natural gas usage, as applicable. Houston Electric’s revenues are generally higher during the warmer months. As in certain past years, unusually mild weather in the warmer months could diminish Houston Electric’s results of operations and harm its business, financial condition and cash flows. Conversely, as in certain past years, extreme warm weather conditions could increase Houston Electric’s results of operations in a manner that would not likely be annually recurring. A significant portion of Indiana Electric’s sales are for space heating and cooling. Consequently, as in certain past years, Indiana Electric’s results of operations may be adversely affected by warmer-than-normal heating season weather or colder-than-normal cooling season weather, while, as has occurred in certain past years, more extreme seasonal weather conditions could increase Indiana 37 Electric’s results of operations in a manner that would not likely be annually recurring. Revenues in our Natural Gas reportable segment are customarily higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish our results of operations and harm our business, financial condition, results of operations and cash flows. Conversely, as occurred in certain past years, extreme cold weather conditions could increase our results of operations in a manner that would not likely be annually recurring. Severe weather events, natural disasters and other climate-related impacts could adversely impact our businesses, financial condition, results of operations and cash flows. A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories and our business. Our facilities and operations face physical risks from severe weather events, natural disasters and other climate-related conditions, which have become more frequent, unpredictable and severe as a result of climate change or other factors. Severe weather events, natural disasters and other climate-related conditions impact our service territories, primarily when hurricanes and remnants of hurricanes, tornadoes, floods, severe winter weather conditions, including ice storms, wildfires, thunderstorms, high winds, hail, derecho events, microbursts, drought, excess humidity or extreme temperatures (high heating/cooling days) occur, which can impact our operations and our ability to serve our customers, including resulting in operational interruptions and large-scale and/or prolonged outages. To the extent the frequency and severity of extreme weather events, natural disasters and climate-related conditions such as rising sea level and coastal erosion continue to increase, our costs of providing service may increase, including the costs and availability of procuring insurance related to such impacts, and those costs may not be recoverable. In addition, our insurance may not be sufficient or effective under all circumstances and against all related hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could adversely affect our business, financial condition, results of operations and cash flows. A delay or failure in recovering amounts for storm restoration costs incurred, inability to securitize future storm restoration costs, or loss of revenues as a result of severe weather could have a material impact on us, including lower credit ratings and, thus, higher costs for future debt issuances, as well as limitations on our ability to fund other investments to address customer needs. The implementation of budget and spending cuts to federal government agencies and programs could also impact our operations and our ability to serve customers when such weather events, natural disasters and other climate conditions occur, including increasing our costs. Further, events of extreme weather and natural disasters could make it unsafe or hinder the effectiveness of our employees to fix, maintain and restore power to affected areas and could harm our reputation. Since certain of our facilities are located along or near the Texas Gulf Coast, increased or more severe hurricanes, tornadoes or derecho events could increase our costs to repair damaged facilities and restore service to our customers. Our electric and natural gas operations in our service territories have both been impacted by severe weather events, including the February 2021 Winter Storm Event, the May 2024 Storm Event and Hurricane Beryl, and could experience similar events in the future, which could have an adverse impact on our business, financial condition, results of operations and cash flows. Further, if climate changes occur that result in fewer heating degree days than normal in our service territories, which has occurred in certain past years, financial results from our businesses could be adversely impacted. For example, where natural gas is used to heat homes and businesses, warmer weather might result in less natural gas being used, adversely affecting us. Severe weather events, natural disasters and the effects of climate change have increased the duration of wildfire season and may further exacerbate the possibility of wildfires and the risks related thereto, including that we may be held liable for damages incurred as a result of wildfires, reputational harm, damage to our network, facilities and systems resulting therefrom. While we proactively take steps to mitigate wildfire risk in the areas of our electrical and natural gas assets, wildfire risk is always present. We could be held liable for damages incurred as a result of wildfires or incur reputational harm if it was determined that they were caused by or enhanced due to any fault of CenterPoint Energy. Wildfires could also jeopardize our electric and natural gas infrastructure, including Houston Electric’s and Indiana Electric’s vast network of electric transmission and distribution lines and facilities and CERC’s natural gas distribution systems, and third-party property and result in temporary or prolonged power outages and shortages in our service territories. Wildfires also have the potential to negatively affect communities in our service territories and the surrounding areas, and the continued expansion of the wildland-urban interface has increased this wildfire risk. In addition, while we maintain wildfire insurance, our insurance may not be sufficient to cover all losses we may incur as a result of wildfires. Wildfires could also lead to significant financial distress, credit rating downgrades and further increased costs for wildfire insurance or lack of availability thereof. Insufficient wildfire insurance coverage, increased wildfire insurance costs and a lack of wildfire insurance availability could adversely impact our business, financial condition, results of operations and cash flows. Furthermore, any damage caused to our assets, loss of service to our customers, liability imposed, credit rating downgrades or regulatory recovery risk occurring as a result of wildfires could negatively impact our business, financial condition, results of operations and cash flows. We are subject to transition risk relating to climate change, as well. In the long term, climate change could cause shifts in population, including customers moving away from our service territories. When we cannot deliver electricity or natural gas to 38 customers or our customers cannot receive our services, our financial results are impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs. To the extent we are unable to recover those costs or recover in a timely manner, or if recovery of such costs results in higher rates and reduced demand for our services, our future financial results may be adversely impacted. Similarly, public and private efforts to address climate change, such as by legislation, regulation, actions by private interest groups, and litigation, could impact our ability to continue operating our businesses as we do today, significant aspects of which rely on fossil fuels. These initiatives could have a significant impact on us and our operations as well as on our third-party suppliers, vendors and partners, which could impact us by among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to us. We also may be subject to climate change litigation, which could result in substantial fines, penalties or damages and restrictions on our operations. The utility industry has already faced such litigation, challenging its marketing and use of fossil fuels and attributing climate change to emissions resulting from the use of fossil fuels. While we have pursued and executed, and continue to pursue and execute, on plans to accelerate investments to enhance the resiliency of our systems to better withstand severe weather, natural disasters, and other climate-related impacts, these plans are generally subject to approval by regulators and may not be approved in full or at all. Certain accelerated resilience plans of the Registrants have received regulatory approval for a limited scope and duration, generally at levels less than those proposed to the regulators. We may not be able to successfully execute such plans and projects in the time and manner planned and there are risks regarding the ability to demonstrate the efficacy of the accelerated resilience investments in mitigating storm impacts, as well as in seeking and obtaining regulatory approval for additional accelerated resilience plans and projects that may be necessary. The need for this investment and these expenditures could cause execution, liquidity, capital or other financing-related risks as well as result in upward pressure on our customer rates, which, particularly when combined with upward pressure resulting from the recovery of the costs of recent and future storms, may result in adverse actions by applicable regulators or effectively limit our ability to make other planned capital or other investments. The occurrence of extreme weather events, including winter storms and record hot temperatures, or other causes could also lead to additional reforms to the Texas electric market, some measure of which, if implemented, could have an adverse impact on Houston Electric. For example, during and in the aftermath of the February 2021 Winter Storm Event, the Texas legislature revised applicable statutes and granted the PUCT and ERCOT additional regulatory authority, both oversight and enforcement, that focuses on ensuring ERCOT market participants, including Houston Electric, have adopted sufficient winterization standards and protection. If any additional protections are required in the future as a result of additional extreme weather events or other causes, complying with these new protections may increase the cost of electricity, which could adversely affect Houston Electric’s business, financial condition, results of operations and cash flows. We are exposed to risks related to changes in demand and energy consumption that could adversely impact our business, financial condition, results of operations and cash flows. Our businesses are also affected by new customers and load growth. We anticipate a high level of load growth and an increase in demand for electric power in certain of our service territories, including from the expansion of data centers (associated with, among other things, increasing demand for AI), energy refining and exports, advanced manufacturing and logistics, and a significant portion of the planned investments in our 10-year capital plan is intended to support such expected growth. Nevertheless, significant uncertainty exists. We are subject to potential challenges in accurately forecasting such load growth and predicting future electric power needs due to, among other things, rapidly changing technology and market dynamics, changes in industry practice and the possibility that new large customers will be transitory and exit our service territory or otherwise delay or cancel their planned projects. We are subject to potential challenges in capitalizing on opportunities presented by these developments (including if such opportunities do not materialize to the degree expected), managing the potential power demand, generation sources, and transmission capabilities to meet potential load growth, financing the capital investment needed to build and maintain the necessary infrastructure to support such development on satisfactory terms and conditions and consistent with the maintenance of satisfactory credit ratings, executing on such build and maintenance of the necessary infrastructure to support such development on acceptable timelines and in a cost-effective manner while maintaining affordability for customers, managing the possible environmental impact of the potential increased power demand, achieving our energy transition goals on expected timelines and evaluating and complying with evolving regulations related to such development. These challenges, and our efforts to predict and address them, could have a material impact on us, including if we fail to capitalize on the opportunities relating to these developments or fully realize anticipated benefits from significant capital investments and expenditures made to address such development, which could adversely affect our ability to execute our 10-year capital plan, cause us to incur additional expenses to terminate or redeploy any underutilized assets or infrastructure, or fail to fully recover our capital expenditures, all of which could have an adverse effect on our business, financial condition, results of operations and cash flows. For example, our failure to capitalize on the opportunities presented by these developments or potential large load customers delaying or cancelling their planned projects could lead to delays or the cancellation of projects included in our 10-year capital plan. Further, regulators may investigate the prudence of costs in our rates and examine, among other things, the reasonableness or prudence of our level of expenditures (including costs associated with our capital projects supporting new customers and load growth). In addition, volatility in stock prices of perceived significant energy customers, such as technology companies involved with data centers, AI or cryptocurrency, or other 39 significant developments with such companies, could cause increased volatility in stock prices of certain companies in our industry. Higher electric power demand and load growth could also significantly increase the prices of energy and capacity, which could in turn affect customer rates or be perceived to affect customer rates and raise affordability concerns, as well as raise resource adequacy and reliability concerns, particularly if that increased demand outpaces the addition of firm generation capacity and in transmission constrained zones. For example, there has been increasing media attention and public claims regarding the link between large load customers such as data centers and increased customer bills. Increased customer rates or the perception that customer rates are increasing to address large load customers could attract political and regulatory scrutiny, increase regulatory uncertainty for our capital investment plans and programs and present reputational risks. Additionally, 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. This resource adequacy challenge presents reliability concerns, as well as potential for increasing energy and capacity prices that could place pressure on customer bills, attract political and regulatory scrutiny, increase regulatory uncertainty for our capital investment plans and programs and present reputational risks. These matters could have an adverse effect on our business, financial condition, results of operations and cash flows. Our businesses are also affected by reduction in energy consumption due to factors including economic, climate and market conditions in our service territories, energy efficiency/reduction initiatives, advances in technology and use of alternative technologies and changes in our customers’ perceptions regarding natural gas usage as a result of incidents of other utilities involving natural gas pipelines, which could impact our ability to grow our customer base and our rate of growth. Growth in customer accounts and growth of customer usage each directly influence demand for electricity and natural gas and the need for additional delivery facilities. Customer growth and customer usage are affected by a number of factors outside our control, such as energy efficiency/reduction initiatives, bans on or further regulation of natural gas-fired appliances, demand-side management goals, technological advances (e.g., distributed generation resources, energy storage devices and more energy efficient buildings and products) and economic and demographic conditions, including population changes, job and income growth, housing starts, changes in rate designs, new business formation and the overall level of economic activity. For example, certain regulatory and legislative bodies have introduced or are considering requirements and incentives to reduce energy consumption by certain dates. Declines in demand for electricity and natural gas in our service territories due to pipeline incidents of other utilities, increased electricity and natural gas prices as experienced during the February 2021 Winter Storm Event and during periods of persisting high inflation or economic downturns, among other factors, could reduce overall usage and lessen cash flows, especially as industrial customers reduce production and, therefore, consumption of electricity and natural gas. Although Houston Electric’s and Indiana Electric’s transmission and distribution businesses are subject to regulated allowable rates of return and recovery of certain costs under periodic adjustment clauses, overall declines in electricity delivered and used as a result of economic downturn or recession could reduce revenues and cash flows, thereby diminishing results of operations. A reduction in the rate of economic, employment and/or population growth could result in lower growth and reduced demand for and usage of electricity and natural gas in such service territories. Additionally, certain laws in our service territories allow municipalities to create, own, and operate utilities. If one or more municipalities in our service territories create new or supplemental utilities, or impair the franchises under which we serve customers in the applicable municipalities, it could result in lower growth and reduced demand for and usage of electricity and natural gas in such service territories. Further, deregulation or other changes in law in our service territories could allow third-party suppliers to contract directly with customers for their natural gas and electric supply requirements. In addition, legislation or regulation that supports distributed energy technologies or that allows third party sales from such technologies could result in further competition. Some or all of these factors could result in a lack of growth or decline in customer demand for electricity or natural gas or number of customers and may result in our failure to fully realize anticipated benefits from significant capital investments and expenditures, which could have an adverse effect on our business, financial condition, results of operations and cash flows. Aging infrastructure may lead to increased costs and disruptions in operations that could negatively impact our financial results. We have risks associated with aging infrastructure assets, including the failure of equipment or processes and potential breakdowns due to such aging. These risks have in the past and may continue to be driven by threats such as, but not limited to, electrical faults, mechanical failure, internal and external corrosion, ground movement and stress corrosion and/or cracking. The age of certain of our assets, including each of Indiana Electric’s coal generating facilities, which were constructed in 1973 and 1966, respectively, have in the past resulted and may continue to result in a need for replacement, higher level of maintenance costs, reduced generation output and unscheduled outages because of, among other things, our risk-based federal and state compliant integrity management programs. The failure to operate our assets as desired could result in interruption of service, safety concerns, major component failure at generating facilities and electric substations, events such as gas leaks, and an inability to meet service and compliance obligations, which could adversely impact revenues, and could also result in increased 40 capital expenditures and maintenance costs. As part of our capital plan and various plans and projects thereunder, we continue to make upgrades to our aging infrastructure assets to enhance the reliability of our infrastructure. Failure to achieve timely and full recovery of expenses associated with our aging infrastructure could adversely impact revenues and could result in increased capital expenditures or expenses. In addition, the nature of information available on aging infrastructure assets, which in some cases is incomplete, may make operation of the infrastructure, inspections, maintenance, upgrading and replacement of the assets particularly challenging. Missing or incorrect infrastructure data may lead to difficulty properly locating facilities, which can result in excavator damage and operational or emergency response issues; configuration and control risks associated with the modification of system operating pressures in connection with turning off or turning on service to customers, which can result in unintended outages or operating pressures; and other potential risks related to missing or incorrect infrastructure data. Also, additional maintenance and inspections are required in some instances to improve infrastructure information and records and address emerging regulatory or risk management requirements, resulting in increased costs. Our ability to successfully maintain or replace our aging infrastructure has been and may continue to be delayed or be at a greater cost than anticipated due to supply chain issues or governmental actions. For example, while Indiana Electric’s 2025 IRP (similar to previous IRPs) preferred portfolios included the retirement of F.B. Culley Unit 2 by the end of 2025, a coal-fired generation unit, the U.S. Department of Energy issued emergency order 202(c) in December 2025 directing Indiana Electric to continue operating the unit through March 23, 2026. Additionally, with respect to our natural gas operations, if certain pipeline replacements (for example, cast-iron or bare steel pipe) are not completed timely or successfully, government agencies and private parties might allege the uncompleted replacements caused events such as fires, explosions or leaks. Although we maintain insurance for certain of our facilities, our insurance coverage may not be sufficient in the event a catastrophic loss is alleged to have been caused by a failure to timely complete equipment replacements. Insufficient insurance coverage and increased insurance costs could adversely impact our business, financial condition, results of operations and cash flows. Finally, aging infrastructure may complicate our utility operations ability to address severe weather, natural disaster and climate change concerns and efforts to enhance resiliency and reliability. Our business, financial condition, results of operations and cash flows may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions. Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks inherent in the transmission, distribution and generation of electricity and in the delivery of natural gas that could result in substantial losses or other damages. From time to time, we have and may in the future experience various risks associated with the operations of our facilities, including, but not limited to, the following: • operator error or failure of equipment or processes, including natural gas ignition events or associated incidents, pipeline high-pressure or over-pressure events or ruptures, or failure to follow appropriate safety protocols for, among others, the transmission and distribution of electricity and in the delivery of natural gas, including operations of our storage and peak shaving facilities; • the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage; • the inability to maintain the reliability of our utility services or meet generation capacity obligations; • operating limitations that may be imposed by environmental or other regulatory requirements; • labor disputes; • information technology or financial and billing system failures, including those due to the implementation and integration or failure of new technology (including AI technology), that impair our information technology infrastructure, reporting systems or disrupt normal business operations, affect our ability to access customer information or cause us to lose confidential or proprietary data that adversely affects our reputation or exposes us to legal claims; • regulatory noncompliance, compliance mandates and penalties from our regulators; • failure to obtain in a timely manner and at reasonable prices the necessary fuel, such as coal and natural gas, building materials or other items needed to operate our facilities; and • catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornados, derecho events, ice storms, terrorism, cybersecurity incidents, wildfires, public health emergencies (including pandemics), acts of war, military invasions, civil unrest, geopolitical conflict or other similar occurrences, including any environmental impacts related thereto, which catastrophic events may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts, and for which our emergency preparedness plans may not be adequate or we may not respond effectively, which could result in public or employee harm. 41 Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities, environmental or property damage, delays in cash collections, harm to our reputation, legal proceedings, less favorable legislative and regulatory outcomes, changes to policies, laws and regulations or increased regulatory oversight, any of which could have an adverse effect on our business, financial condition, results of operations and cash flows. Such events have and may in the future result in the imposition of regulatory or environmental fines and increased litigation. Our businesses will continue to have to adapt to, integrate and implement technological change and may not be successful implementing such technological change as designed or may have to make significant investments to adapt to and integrate technological change. We operate businesses that require sophisticated data collection, processing systems, software and other technology. Some of the technologies supporting the industries we serve are changing rapidly and increasing in complexity. New technologies will emerge or evolve that may deliver superior capabilities to, or may not be compatible with, some of our existing technologies, and may require us to make significant investments so that we can continue to provide cost-effective and reliable technology solutions to support energy production and delivery. Our future success will depend, in part, on our ability to anticipate, adapt to, integrate and implement technological changes in a timely and cost-effective manner, to offer, on a timely basis, reliable services that meet customer demands and evolving industry standards and to recover all, or a significant portion of, any unrecovered investment, including obsolete assets. Accordingly, we periodically implement new or enhanced technology, including information systems. Implementation of such new technology, including information systems, can, and pursuant to certain projects included in our 10-year capital plan, will, require the commitment of significant, sufficiently skilled personnel, engagement of third parties, substantial capital investment and additional administration and operating expenses, and entails risks to our business operations. If the integration or implementation of technology, including information systems, as designed is delayed or unsuccessful, we may not realize anticipated productivity improvements or cost efficiencies and may experience interruptions in service and operational difficulties, which could adversely affect our business, financial condition, results of operations and cash flows. Our 10-year capital plan additionally calls for the rapid integration and implementation of new technologies such as advanced grid infrastructure, which increases exposure to potential grid instability and technology obsolescence. If we fail to successfully adapt to, integrate and implement a technological change, fail to obtain access to important technologies, incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, our regulatory recovery could be negatively impacted and our businesses, financial condition, results of operations and cash flows could be adversely affected. Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our business, financial condition, results of operations and cash flows. We currently have insurance in place, such as general liability, excess liability and property insurance, to cover, among other things, certain of our facilities and third-party bodily injury in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage premiums continue to increase, and insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to fully cover or restore the loss or damage without negative impact on our business, financial condition, results of operations and cash flows. Certain types of damages, expenses or claimed costs, such as fines and penalties, have been in the past and may in the future be excluded under the policies. In addition, insurers providing insurance to us have in the past and may in the future dispute and raise defenses to coverage under the terms and conditions of the respective insurance policies, which can result in a denial of coverage or limit the amount of insurance proceeds available to us. Any losses for which we are not fully insured or that are not covered by insurance at all could adversely affect our business, financial condition, results of operations and cash flows. Costs, damages and other liabilities related to recent events and incidents that affected other utilities, such as wildfires, winter storms and explosions, among other things, have exceeded or could exceed such utilities’ insurance coverage. Further, as a result of these recent events and incidents, the marketplace for insurance coverage to utility companies may be unavailable or limited in capacity or any such available coverage may be deemed by us to be cost prohibitive under current conditions. Insurance premiums for any such coverage, if available, may not be eligible for recovery, whether in full or in part, by us through the rates charged by our utility businesses. In common with other companies in its line of business that serve coastal regions, Houston Electric does not have insurance covering its transmission and distribution system, other than substations, because Houston Electric believes it to be cost prohibitive and insurance capacity to be limited. Historically, Houston Electric has been able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise. In the future, any such recovery may not be granted. For 42 example, Houston Electric is seeking to recover the system restoration costs associated with Hurricane Beryl and certain other significant storms through the issuance and sale of non-recourse system restoration bonds. Although Houston Electric expects to receive the net proceeds from its offering of system restoration bonds on February 26, 2026, there can be no assurance that the system restoration costs will be recovered in the amounts expected or on the expected timeline. Therefore, Houston Electric may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its business, financial condition, results of operations and cash flows. Global or regional health pandemics, epidemics or similar public health threats could negatively impact our business, financial condition, results of operations and cash flows. Public health threats, including pandemics and epidemics, and any third-party actions taken to contain the spread and mitigate the public health threats, have had and may in the future have widespread impacts on the global economy, our supply chain and our employees, customers and supply chain stakeholders. Any future health threat could have potentially material impacts on our business, financial condition, results of operations and cash flows. The ultimate impact of public health threats on our business depends on factors beyond our knowledge or control and we might not be able to predict or respond to all impacts on a timely basis to prevent near- or long-term adverse impacts to our business, financial condition, results of operations and cash flows. Failure to attract, motivate and retain an appropriately qualified workforce, identify and develop top talent to succeed senior management and maintain good labor relations could adversely impact the operations of our facilities and our business, financial condition, results of operations and cash flows. Our businesses and ability to implement our strategies are dependent on recruiting, retaining and motivating employees, including senior executive officers and other key personnel. Like many companies in the utilities industry and other industries, we have experienced higher than normal turnover of employees as a result of a number of factors, including a tightening labor market, remote working opportunities, employees shifting industries, individuals deciding not to work and a maturing workforce. Of our employee population, not including employees of Energy Systems Group prior to its divestiture on June 30, 2023 or temporary employees, 17.1%, 18.2%, and 18.7% were retirement eligible as of December 31, 2025, 2024, and 2023, respectively. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, increased turnover or the unavailability of contract resources, may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs to replace employees, productivity costs, health care costs and safety costs, may rise and may not be recoverable in rates. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of sufficiently skilled contract labor may lead to safety concerns and adversely affect the ability to manage and operate our businesses, particularly the specialized skills and knowledge required to construct and operate generation facilities, a technology-enabled power grid and transmission and distribution infrastructure, among other facilities. Additionally, further tightening of the labor market and increasing wages may adversely affect our ability to attract, transition and retain key personnel, which could, in turn, negatively impact our ability to identify, motivate and develop talent to succeed senior management. If we are unable to successfully attract and retain an appropriately qualified workforce and conduct appropriate senior management succession planning, our ability to execute on our 10-year capital plan and our business, financial condition, results of operations and cash flows could be negatively affected. Furthermore, the operations of our facilities depend on good labor relations with our employees, and several of our businesses have in place collective bargaining agreements with various labor unions, comprising approximately 42% of our workforce. We have several separate bargaining units, each with a unique collective bargaining agreement described further in Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with IBEW Locals 1393 and USW Locals 12213 & 7441 related to Indiana Gas employees, as well as with IBEW Local 66 related to Houston Electric employees, are scheduled to expire in December 2026 (IBEW Local 1393 & USW Locals 12213 & 7441) and May 2026 (IBEW Local 66), and negotiations of these agreements are expected to be completed before the respective expirations. The collective bargaining agreement with OPEIU Local 12 related primarily to CERC employees in Minnesota expired in December 2025 and negotiations are ongoing. Any failure to reach an agreement on new labor contracts or to negotiate these labor contracts might result in strikes, boycotts or other labor disruptions. These potential labor disruptions could have an adverse effect on our businesses, financial condition, results of operations and cash flows. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have an adverse effect on our businesses, financial condition, results of operations and cash flows. 43 Item 1B. Unresolved Staff Comments None. Item 1C. Cybersecurity Our processes for assessing, identifying, and managing material risks from cybersecurity threats are part of our overall enterprise risk management system and processes. Enterprise risks, including cybersecurity risks, and their associated mitigations are reviewed at least annually by senior management and the Board. Throughout the year, we regularly assess our cybersecurity program and continue to invest in hardening and maturing our cybersecurity measures as further described below. Risk Management Strategy and Processes We maintain a cybersecurity program to help us assess, identify, and manage cybersecurity risks to our systems and data, including to help us defend against and mitigate emerging and existing cybersecurity threats to our information technology and operational technology systems. Our strategies and processes for managing cybersecurity risks are informed by relevant industry frameworks and laws, regulations and standards applicable to us in the jurisdictions in which we do business, including those applicable to utilities that operate bulk electric systems or critical pipeline facilities. We maintain various policies, procedures, technologies and other controls to help prevent, detect, mitigate and manage cybersecurity threats and incidents. We also use third-party consultants and service providers to support our risk management efforts, such as services for cybersecurity intelligence, monitoring, testing and assessments. Key aspects of our risk management processes include: • Threat Monitoring . We receive information on emerging cybersecurity threats and vulnerabilities from different sources, including vendors, cybersecurity organizations and U.S. government agencies, to help support our ability to detect and defend against threats to the security of our information technology and operational technology systems. We maintain several cybersecurity monitoring tools and services to help us detect unauthorized activities involving our systems and potential cybersecurity threats and vulnerabilities to our systems. • Incident Response . We maintain a Cybersecurity Operations Center that is dedicated to monitoring for cybersecurity threats to our systems and responding to potential cybersecurity incidents. We also maintain cybersecurity incident response plans that establish a cross-functional incident response team and processes to guide our response to cybersecurity incidents, including processes for reporting and escalating cybersecurity incidents to senior management and the Audit Committee or the Board, as appropriate. We conduct tabletop exercises regularly to test our incident response processes. • Assessments, Testing and Audits . We conduct different types of security assessments, testing and audits to help us proactively identify and mitigate potential cybersecurity threats and vulnerabilities to our information technology and operational technology systems. For example, we conduct security-related risk assessments on proposed software, hardware and third-party technology solutions used by CenterPoint Energy prior to deployment in our network. We also undergo periodic vulnerability assessments, penetration tests and cybersecurity reviews of our systems and security controls. We engage third parties to support certain of these assessments and tests and to provide guidance and support to our cybersecurity management team. Our internal audit team also conducts audits of certain CenterPoint Energy systems and data security controls. • Third-Party Risk Management . We maintain a vendor risk management program, a component of which assesses the cybersecurity and data privacy practices of certain third-party service providers to help us assess and manage cybersecurity risks associated with third-party access to our systems and data. To help identify and mitigate third-party cybersecurity risks, we conduct vendor security reviews and privacy impact assessments when deemed appropriate based on the nature of the systems and data that will be accessed by the third-party. We also impose contractual obligations on certain of our service providers related to data privacy, confidentiality and security based on, among other factors, their extent of access to our data and systems and the nature and sensitivity of the data and systems to which they have access. • Training and Awareness . We hold regular employee trainings on privacy, cybersecurity, AI and records and information management, conduct simulated phishing tests, and generally seek to promote awareness of cybersecurity risk through communication and education of our employee population. 44 As described in Item 1A “Risk Factors,” our operations rely on the secure processing, storage, and transmission of confidential, sensitive and other information within our computer systems and networks. Computer viruses, threat actors, employee or vendor incidents and other external hazards could expose our information systems, and those of third parties who process our data, provide access to systems or that have access to our systems, to security breaches, cybersecurity incidents or other disruptions, any of which could materially and adversely affect our business, reputation, results of operations and financial condition, and subject us to possible legal claims and liability. While we have experienced cybersecurity incidents in the past, as of the date of the filing of this Form 10-K, CenterPoint Energy has not identified any cybersecurity threats that have materially affected or are reasonably anticipated to have a material effect on us, including our business strategy, results of operations, or financial condition. Governance Board of Directors Oversight Our Audit Committee, comprised of independent directors from our Board, oversees the Board’s responsibilities relating to CenterPoint Energy’s cybersecurity, data privacy and AI programs, including cybersecurity and AI risk management and cybersecurity disclosures required by applicable securities laws or regulations, as appropriate. As part of its risk oversight responsibilities, the Audit Committee receives quarterly reports from our Executive Vice President and General Counsel, Chief Security Officer (CSO) or other representatives from our cybersecurity or data privacy groups and periodic reports from our third-party consultants. These reports include updates on certain cybersecurity or data privacy matters, including, among other items, CenterPoint Energy’s progress in maturing its cybersecurity program, results of cybersecurity assessments and testing, the cybersecurity landscape and emerging threats, status of ongoing initiatives and strategies, incident reports and learnings from any cybersecurity events, compliance with regulatory requirements and industry standards, data privacy matters, and the cybersecurity budget. Risk Management Personnel CenterPoint Energy’s Executive Vice President and General Counsel is responsible for overseeing our cybersecurity and data privacy programs. CenterPoint Energy’s CSO is responsible for the day-to-day management of our cybersecurity program and reports directly to the Executive Vice President and General Counsel. CenterPoint Energy’s Senior Vice President, Deputy General Counsel, and Chief Ethics & Compliance Officer (CECO) is responsible for day-to-day management of our data privacy program and also reports directly to the Executive Vice President and General Counsel. Our cybersecurity and data privacy teams, which report directly to our CSO and CECO, respectively, are tasked with implementing our programs in support of cybersecurity and data privacy risk management. We also have management-level teams and committees, which include and/or collaborate with our CSO and CECO, that support, among other things, our processes to assess and manage cybersecurity risk. These teams and committees provide summary reports on their activities and initiatives to appropriate senior executives, including the Executive Vice President and General Counsel and the Audit Committee or the Board, as appropriate. CenterPoint Energy’s CSO joined CenterPoint Energy in September 2025 and has over two decades of experience in cybersecurity and risk management across diverse industries, and most recently served in senior leadership roles, including Chief Information Security Officer, for a global engineering, procurement, consulting and construction company. Our Executive Vice President and General Counsel has significant risk management, governance and litigation experience, which we believe are important leadership skills to help incorporate risk management, legal, disclosure and governance perspectives into the design of our cybersecurity program and in evaluating and responding to potential cybersecurity incidents. Item 2. Properties The following discussion is based on the Registrants’ businesses as of December 31, 2025. Character of Ownership We lease or own our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and natural gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others. 45 Electric (CenterPoint Energy and Houston Electric) Properties All of Houston Electric’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires, telecommunications networks and meters. Most of Houston Electric’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law. All real and tangible properties of Houston Electric, subject to certain exclusions, are currently subject to the lien of the M&DOT and the lien of the General Mortgage, which is junior to the lien of the M&DOT. No first mortgage bonds are outstanding under the M&DOT and Houston Electric is contractually obligated to not issue any additional first mortgage bonds under the M&DOT. Houston Electric is undertaking actions to release the lien of the M&DOT and terminate the M&DOT. For information related to debt outstanding under the General Mortgage, see Note 12 to the consolidated financial statements. Indiana Electric’s properties are primarily located in Indiana. They consist of transmission lines in Indiana and Kentucky, distribution lines, substations, service centers, coal-fired generating facilities, gas-fired turbine peaking units, a landfill gas electric generation facility and solar generation facilities. All real and tangible properties of Indiana Electric, subject to certain exclusions, are currently subject to the lien of the Amended and Restated Mortgage Indenture dated as of January 1, 2023, between SIGECO (Indiana Electric) and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as Trustee. For information related to debt outstanding under the Amended and Restated Mortgage Indenture, see Note 12 to the consolidated financial statements. Electric Lines - Transmission and Distribution. As of December 31, 2025, Houston Electric and Indiana Electric owned and operated the following electric transmission and distribution lines: Houston Electric Indiana Electric Description Overhead Lines Underground Lines Indiana Kentucky (1) Transmission lines: (in Circuit Miles) 69 kV 101 2 565 — 138 kV 2,352 24 417 9 345 kV 1,446 — 48 16 Total 3,899 26 1,030 25 Distribution lines 29,718 29,841 7,174 — (1) These assets interconnect with Louisville Gas and Electric Company’s transmission system at Cloverport, Kentucky and with Big Rivers Electric Cooperative at Sebree, Kentucky. 46 Generating Capacity. As of December 31, 2025, Indiana Electric had 1,228 MW of installed generating capacity, as set forth in the following table: Generation Source Unit No. Location Date in Service Capacity (MW) Coal F.B. Culley (1) 2 Warrick County, Indiana 1966 90 F.B. Culley 3 Warrick County, Indiana 1973 270 Total Coal Capacity 360 Gas Brown (2) 3 Posey County, Indiana 1991 80 Brown 4 Posey County, Indiana 2002 80 Brown 5 Posey County, Indiana 2025 230 Brown 6 Posey County, Indiana 2025 230 Renewable Landfill Gas Pike County, Indiana 2009 3 Total Gas Capacity 623 Solar Oak Hill Evansville, Indiana 2018 2 Volkman Evansville, Indiana 2018 2 Troy Spencer County, Indiana 2021 50 Posey Posey County, Indiana 2025 191 Total Solar Capacity 245 Total Generating Capacity (3) 1,228 (1) While Indiana Electric’s 2025 IRP (similar to previous IRPs) preferred portfolios included the retirement of F.B. Culley Unit 2, a coal-fired generation unit, by the end of 2025, the U.S. Department of Energy issued an emergency 202(c) order in December 2025 directing Indiana Electric to continue operating the unit through March 23, 2026. For further information about F.B. Culley 2, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. (2) Brown Unit 3 is also equipped to burn oil. (3) Excludes 1.5% participation in OVEC. See Item 1. Business for more details. Natural Gas Combustion Turbines. In 2022, Indiana Electric received approval from the IURC for a CPCN seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. In the second quarter of 2025, 230 MW of the facility was placed in service, and due to a transformer manufacturing issue, the remaining 230 MW of the facility was placed in service in the third quarter of 2025. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. Solar. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve an amended BTA to purchase the 191 MW Posey Solar project. On September 6, 2023, the IURC issued an order approving the CPCN. On March 7, 2025, SIGECO completed the acquisition of Posey Solar. The Posey Solar project was placed in service in the second quarter of 2025. For further information about Indiana Electric’s BTAs, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. TEEEF. As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric entered into leases for 15 large (27 MW to 32 MW) and five medium (5.7 MW) TEEEF. In June 2025, Houston Electric entered into the ERCOT Transaction, subject to PUCT approval, to release its large TEEEF units to ERCOT at CPS Energy facilities to serve the greater San Antonio region until March 2027 unless terminated earlier pursuant to the provisions of the ERCOT Transaction, reduce its TEEEF fleet capacity and reduce its rates to reflect the removal of the large TEEEF units from its fleet. In November 2025, Houston Electric also proposed to release the five medium (5.7 MW) TEEEF units from its TEEEF fleet and remove the associated lease costs effective January 1, 2026. On February 13, 2026, Houston Electric requested continued abatement until February 27, 2026 due to continued settlement discussions. As of December 31, 2025, Houston Electric leased 519 MW of TEEEF on a long-term basis. For more information, see Note 7 and Note 19 to the consolidated financial statements. 47 Substations. A substation is a facility that transforms electricity from a higher voltage to a lower voltage or vice versa. Generally, this facility is the interface between the transmission system and the distribution grid. The following table presents certain information related to CenterPoint Energy’s substations as of December 31, 2025: Number of Substations Transformer Capacity (in Mva) Houston Electric 246 74,665 Indiana Electric 109 7,027 Total CenterPoint Energy 355 81,692 Service Centers. Service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity. The following table presents certain information related to CenterPoint Energy’s service centers as of December 31, 2025: Number of Service Centers Acres of Land Houston Electric 13 362 Indiana Electric 6 69 Total CenterPoint Energy 19 431 Natural Gas (CenterPoint Energy and CERC) CenterPoint Energy’s and CERC’s natural gas distribution businesses use various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather. CenterPoint Energy’s and CERC’s natural gas distribution businesses may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production. As of December 31, 2025, CenterPoint Energy’s and CERC’s natural gas distribution businesses owned and operated the following natural gas facilities: No. of Assets Storage Capacity (Bcf) Working Capacity (Bcf) Maximum Daily Withdrawal Rate (MMcf) CenterPoint Energy Underground Natural Gas Storage Facility 8 43 14 305 CERC Underground Natural Gas Storage Facility 5 32 9 205 On-site Storage Capacity No. of Assets Daily Production Rate (Dth) Millions of Gallons Dth CenterPoint Energy and CERC Propane Air-Gas Manufacturing Plant 15 247,000 14 1,228,000 LNG Plant Facility 1 72,000 12 1,010,000 The table below reflects CenterPoint Energy’s and CERC’s natural gas distribution businesses contracted upstream storage services as of December 31, 2025: Storage Capacity (Bcf) Maximum Peak Daily Delivery (MMcf) Upstream Storage Service 100 2,209 48 The table below reflects the approximate total linear miles of distribution and transmission mains owned by CenterPoint Energy’s and CERC’s natural gas distribution businesses as of December 31, 2025: CenterPoint Energy CERC All Locations 72,000 69,000 Indiana and Ohio (1) 23,000 20,000 (1) Linear miles of distribution and transmission mains attributable to CEOH were approximately 6,000 miles. CenterPoint Energy’s and CERC’s natural gas distribution businesses owned mains varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s and CERC’s natural gas distribution businesses in Indiana and Ohio own mains that are located in Indiana and Ohio except for, in the case of CenterPoint Energy, pipeline facilities extending from points in northern Kentucky to points in southern Indiana so that gas may be transported to Indiana and sold or transported to customers in Indiana. Generally, in each of the cities, towns and rural areas served by CenterPoint Energy’s and CERC’s natural gas distribution businesses, CenterPoint Energy and CERC own the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s natural gas distribution businesses receive gas are owned, operated and maintained by others, and their distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers. As of December 31, 2025, CenterPoint Energy and CERC, through CEIP, owned and operated over 208 miles of intrastate pipeline in Texas. On March 31, 2025, CenterPoint Energy, through its subsidiary CERC Corp., completed the sale of its Louisiana and Mississippi natural gas LDC businesses, which included the intrastate pipelines owned by CEIP in Louisiana. On October 20, 2025, CenterPoint Energy, through CERC Corp., entered into the Ohio Securities Purchase Agreement to sell all of the issued and outstanding equity interests in CEOH. The transaction is expected to close in the fourth quarter of 2026, subject to the satisfaction of customary closing conditions. For further information, see Note 4 to the consolidated financial statements. Item 3. Legal Proceedings For a discussion of material legal and regulatory proceedings, including environmental legal proceedings that involve a governmental authority as a party and that the Registrants reasonably believe would result in $1,000,000 or more of monetary sanctions, exclusive of interest and costs, under federal, state and local laws that have been enacted or adopted regulating the discharge of materials into the environment or primarily for the purpose of protecting the environment, affecting the Registrants, read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report and Note 14(c) to the consolidated financial statements, which information is incorporated herein by reference. Item 4. Mine Safety Disclosures Not applicable. 49 PART II This combined Form 10-K is filed separately by three registrants: CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp. Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities CenterPoint Energy As of February 13, 2026, CenterPoint Energy’s common stock was held by approximately 20,378 shareholders of record. CenterPoint Energy’s common stock is listed on the NYSE and NYSE Texas and is traded under the symbol “CNP.” The amount of future cash dividends will be subject to determination based upon CenterPoint Energy’s financial condition and results of operations, future business prospects, any applicable contractual restrictions and other factors that the Board considers relevant and will be declared at the discretion of the Board. For further information on CenterPoint Energy’s dividends, see Note 11 to the consolidated financial statements. Repurchases of Equity Securities During the quarter ended December 31, 2025, none of CenterPoint Energy’s equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, were purchased by or on behalf of CenterPoint Energy or any “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended. Houston Electric As of February 13, 2026, all of Houston Electric’s 1,000 outstanding common shares were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy. CERC As of February 13, 2026, all of CERC Corp.’s 1,000 outstanding shares of common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy. Item 6. [Reserved] Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. The discussion of CenterPoint Energy’s consolidated financial information includes the results of CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp., which, along with CenterPoint Energy, Inc., are collectively referred to as the Registrants. Where appropriate, information relating to a specific Registrant has been segregated and labeled as such. Unless the context indicates otherwise, specific references to Houston Electric and CERC also pertain to CenterPoint Energy. In this combined Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries, including Houston Electric and CERC, unless otherwise stated. No Registrant makes any representation as to the information relating to the other Registrants or the subsidiaries of CenterPoint Energy, Inc. other than itself or its subsidiaries. OVERVIEW Background CenterPoint Energy is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation facilities and natural gas distribution systems. For a detailed description of CenterPoint Energy’s operating subsidiaries, see Note 1 to the consolidated financial statements. Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy, which provides electric transmission service to transmission service customers in the ERCOT region and distribution service to REPs serving the Texas Gulf Coast area that includes the city of Houston. 50 CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, which (i) directly owns and operates natural gas distribution systems in Minnesota and Texas, (ii) indirectly, through Indiana Gas and CEOH, owns and operates natural gas distribution systems in Indiana and Ohio, respectively, and (iii) owns and operates permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP. On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement to sell all of the issued and outstanding equity interests in CEOH. The transaction is expected to close in the fourth quarter of 2026, subject to the satisfaction of customary closing conditions. For further information, see Note 4 to the consolidated financial statements. Reportable Segments We discuss our operating results on a consolidated basis and individually for each of our reportable segments. We are first and foremost an energy delivery company and it is our intention to remain focused on these regulated segments. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject, among other factors. Below is a summary of CenterPoint Energy’s reportable segments as of December 31, 2025. For a detailed description of each reportable segment, as well as the assets included in each reportable segment, see Part I, Item 1. Business and Item 2. Properties. • The Electric reportable segment consisted of electric transmission and distribution services in the Texas Gulf Coast area in the ERCOT region and electric transmission and distribution services primarily to southwestern Indiana and includes power generation and wholesale power operations in the MISO region. • The Natural Gas reportable segment consisted of (i) intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial and industrial customers in Indiana, Minnesota, Ohio and Texas; (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; (iii) residential appliance repair and maintenance services along with HVAC equipment sales to customers in Minnesota; and (iv) home repair protection plans to natural gas customers in Indiana, Ohio and Texas through a third party. The Louisiana and Mississippi natural gas LDC businesses were included in the Natural Gas reportable segment through March 31, 2025. See Note 4 for additional detail. • The Corporate and Other reportable segment consisted of (i) energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group; (ii) corporate support operations that support all of CenterPoint Energy’s business operations; and (iii) office buildings and other real estate used for business operations. Houston Electric and CERC each consist of a single reportable segment. EXECUTIVE SUMMARY We expect our businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. Factors Influencing Our Businesses and Industry Trends We are an energy delivery company with electric transmission, distribution and generation operations and natural gas distribution operations that serve more than seven million metered customers across four states. The majority of our revenues are generated from the transmission and delivery of electricity and the sale of natural gas by our subsidiaries. We continue to execute on our strategic goals for our businesses that were set in September 2025. Pursuant to this business strategy and in light of the nature of our businesses, significant capital investments are reflected in our new 10-year capital plan. In September 2025, we announced our new 10-year capital plan to invest $65 billion from 2026 through 2035, inclusive of a $2 billion increase in previously planned capital expenditures through 2030, and in February 2026, we announced an additional increase to reflect total expenditures of approximately $65.5 billion. Our 10-year capital plan is intended to advance economic 51 growth, improve the experience of our customers through enhancing the safety, reliability and resiliency of our systems and deliver consistent value for stakeholders across the jurisdictions in which we operate. These investments are not only intended to meet our customers’ current needs, but are also in anticipation of future organic growth from a diverse set of economic drivers. This organic growth is anticipated to result in rapid load growth in our service territories (as further discussed below). To fund these capital investments, we rely on internally-generated cash, borrowings under our credit facilities, proceeds from commercial paper, cash proceeds from strategic transactions (such as our Energy Systems Group divestiture in 2023, the sale of our Louisiana and Mississippi natural gas LDC businesses in 2025 and the announced sale of our Ohio natural gas LDC business, which is expected to close in the fourth quarter of 2026) and issuances of equity and debt securities in the capital markets, including the issuance of non-recourse system restoration bonds at Houston Electric to recover costs incurred primarily during the year ended December 31, 2024 due to the May 2024 Storm Events, as well as Hurricane Beryl and other significant storms. We strive to maintain investment grade ratings for our debt securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would result in an increase in our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets along with high or rising interest rates can also affect the availability of external financing on terms we consider attractive. In those circumstances, we may not be able to obtain certain types of external financing or may be required to accept terms less favorable than we would otherwise accept which, among other things, would negatively impact our ability to finance our capital plan. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt. Approximately 85% of our rate base has been subject to a rate case since the beginning of 2023, which supports clarity and stability through 2029 with final orders improving enterprise weighted average returns on equity. Additionally, approximately 85% of CenterPoint Energy’s projected consolidated investments are expected to be recovered through interim capital recovery trackers or rate cases based on a forward test year. For additional detail, see “—Liquidity and Capital Resources —Regulatory Matters” below. To assess our financial performance, our management primarily monitors the recovery of costs and return on investments by evaluating net income and capital expenditures, among other metrics, from our regulated service territories within our reportable segments. Within these broader financial measures, we monitor margins, natural gas and fuel costs, interest expense, capital spend, working capital requirements and operation and maintenance expense, among other significant metrics. In addition to these financial measures, we also monitor a number of variables that management considers important to gauge the performance of our reportable segments, including the number of customers, throughput, commodity prices, heating and cooling degree days, safety factors, system reliability and customer satisfaction. CenterPoint Energy and CERC have weather normalization or other rate mechanisms that largely mitigate the impact of weather on their natural gas distribution businesses in Indiana, Minnesota and Ohio, as applicable. CenterPoint Energy’s and CERC’s natural gas distribution businesses in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s natural gas distribution business’ results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories. Management anticipates significant growth in electric demand over the next decade, especially in our Houston Electric territory where we forecast a nearly 50% increase in peak electric load demand to over 30 GW by 2029 and the demand nearly doubling by the mid 2030s, as compared to 2024. It is expected that the significant forecasted growth in this service territory will be driven by a diverse set of economic drivers, including data centers, energy refining and exports, advanced manufacturing and logistics. Management additionally believes that there are increased electric demand opportunities in our Indiana Electric jurisdiction; accordingly, Indiana Electric’s 2025 IRP included a large load scenario with a corresponding alternative preferred portfolio. Additionally, management expects residential meter growth for Houston Electric to remain in line with long-term trends at approximately 2% annually. As discussed above, a significant portion of the planned investments in our new 10-year capital plan are intended to support this growth. There is significant uncertainty with respect to the forecasted load growth and our ability to capitalize on the opportunities presented by these developments. For more information regarding such risks, see Part I, Item 1A. “Risk Factors — General and Other Risks — We are exposed to risks related to changes in demand and energy consumption...” Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1% annually. Management expects residential meter growth for CERC to remain in line with long-term trends at approximately 1% annually. Nevertheless, this expected growth may be partially offset by adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, which may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities. Long-term national trends indicate residential customers have reduced their energy consumption, which could adversely affect 52 our results. To the extent population growth is affected by lower energy prices and there is financial pressure on some of our customers who operate within the energy industry, there may be an impact on the growth rate of our customer base and overall demand for our services. Macroeconomic and geopolitical developments, including high rates of inflation, supply chain disruptions, labor market constraints, tariffs, high interest rates, general economic slowdown and escalating global conflicts can impact our business, financial condition, results of operations and cash flow, including adversely impacting our ability to execute on our 10-year capital plan. Inflation and high interest rates have contributed, and may continue to contribute, to increased prices for materials and services experienced by us and other companies in our industry. Further, the global supply chain has experienced and may continue to experience significant disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and policy instability, tariffs and other changes in U.S. and foreign trade policy, changes in laws (including tax laws), executive orders, labor shortages, resource availability, long lead times, manufacturer production limitations, delivery delays, inflation, severe weather events and disruptions to internal or international shipping, including as a result of armed conflicts. We have also faced, and may continue to face, a shortage of experienced and qualified personnel in certain positions, which has resulted in increased competition for skilled labor and wage inflation. Additionally, increased demand for materials necessary for our business has resulted, and may continue to result, in greater competition for and scarcity of such materials. In 2025 and 2026, the U.S. government threatened, announced and, in certain cases, rescinded, tariffs on several foreign jurisdictions and imports (including steel) into the United States, which led, and may continue to lead, to the imposition of retaliatory tariffs and other measures taken by foreign jurisdictions. There is significant uncertainty as to the scope and durability of existing and future tariff measures, as well as the ultimate effects of the tariffs on economic conditions. These macroeconomic and geopolitical developments have adversely impacted the utility industry, and like many of our peers, we have experienced disruptions to our supply chain, as well as increased prices and scarcity of resources and labor, and we may continue to experience this in the future. These developments have impacted our financial results for the year ended December 31, 2025. We have taken actions across multiple vectors to reduce the impact of such developments on our results of operations, but if such conditions continue, they could negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and 10-year capital plan at a reasonable cost in a timely manner, result in project cancellations or scope changes, delays, cost overruns, and under-recovery of costs and challenges to our ability to remain in compliance with applicable laws, regulations and policies, which could adversely affect our business, financial condition, results of operations and cash flows. For more information regarding such risk, see Part I, Item 1A. “Risk Factors — Risk Factors Affecting Financial, Economic and Market Risks — Disruptions to the global supply chain...” and “— Changes in U.S. or foreign trade policies.” The utility industry has experienced a period of rising costs and investments and an upward trend in spending, especially with respect to infrastructure investments. As noted above, we are making, and plan to continue to make, significant capital investments in our service territories under our 10-year capital plan to help operate and maintain safer, more reliable and growing electric and natural gas systems and support the electric demand growth that management is forecasting over the next decade. Rising costs and investments and the upward trend in spending are likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. Increased rates and impacts on customer bills or the perceived potential for such impacts, particularly in the current economic environment, has caused and could continue to cause customer affordability concerns, resistance from customers and other stakeholders and increased political, regulatory, community and other scrutiny and pressures. For example, in consideration of customer affordability concerns, Indiana Electric cancelled nearly $1 billion in renewable energy generation projects in 2025. These matters could impact our ability to execute our 10-year capital plan, result in adverse ratemaking and cost recovery determinations, increased financing needs and otherwise adversely affect our business, financial condition, results of operations and cash flows. For more information regarding such risk, see Part I, Item 1A. “Risk Factors.” Significant Events Updated 10-Year Capital Plan. On September 29, 2025, CenterPoint Energy announced a new 10-year capital plan to invest $65 billion from 2026 through 2035, inclusive of a $2 billion increase in previously planned capital expenditures through 2030. On February 19, 2026, CenterPoint Energy announced an additional increase of $500 million to reflect total capital expenditures of approximately $65.5 billion through 2035. The plan is expected to advance economic growth, enhance the experience of the Registrants’ customers and deliver consistent value for stakeholders across the Registrants’ jurisdictions. Treasury Notice 2026-7. On February 18, 2026, Treasury Notice 2026-7 was issued. This notice clarifies the computation of AFSI by including an adjustment to deduct certain repair and maintenance costs that are capitalized in the applicable financial statement. While CenterPoint Energy is still evaluating this guidance, it expects a prospective reduction to its annual CAMT liability. Additionally, CenterPoint Energy expects to be able to amend prior year tax returns to claim a refund of CAMT paid. 53 TEEEF. In June 2025, Houston Electric entered into the ERCOT Transaction, subject to PUCT approval, to release its 15 large (27 MW to 32 MW) TEEEF units to ERCOT at CPS Energy facilities to serve the greater San Antonio region until March 2027 unless terminated earlier pursuant to the provisions of the ERCOT Transaction, reduce its TEEEF fleet capacity and reduce its rates to reflect removal of the large TEEEF units from its fleet. Following the completion of service in the San Antonio area, Houston Electric anticipates that it would complete one or more future transactions involving its large TEEEF units. As the large TEEEF units would not be available to serve Houston Electric customers during such time, Houston Electric plans to continue to not charge customers for these units for any future periods. In November 2025, Houston Electric proposed to release its five medium (5.7 MW) TEEEF units and to remove the associated lease costs from its rates effective January 1, 2026. On February 13, 2026, Houston Electric requested continued abatement until February 27, 2026 due to continued settlement discussions. For additional information, see Note 7 to the consolidated financial statements. Debt Transactions. In 2025, CenterPoint Energy issued or borrowed a combined $3.7 billion of new debt, including: (i) SIGECO’s issuance of $515 million aggregate principal amount of its first mortgage bonds; (ii) Houston Electric’s issuance of $1.1 billion aggregate principal amount of its general mortgage bonds; (iii) Restoration Bond Company II’s issuance of approximately $401.5 million aggregate principal amount of its securitization bonds; (iv) CenterPoint Energy’s issuance of $1.0 billion aggregate principal amount of its convertible senior notes due 2028; and (v) CenterPoint Energy’s issuance of $700 million aggregate principal amount of its junior subordinated notes. During 2025, CenterPoint Energy repaid or redeemed a combined $61 million of outstanding debt, including $41 million of SIGECO’s first mortgage bonds and $20 million of Indiana Gas’s senior notes. In addition, CenterPoint Energy repurchased a combined of approximately $1.5 billion of outstanding debt in connection with settlement of its tender offers, including: (i) approximately $963 million of its senior notes; (ii) approximately $415 million of CERC’s senior notes; and (iii) approximately $234 million of Houston Electric’s general mortgage bonds. For further information about debt transactions in 2025, see Note 12 to the consolidated financial statements. In January 2026, CERC Corp. entered into a delayed draw term loan agreement pursuant to which the banks party thereto have committed to provide term loans in an aggregate principal amount of up to $800 million by March 30, 2026 in up to three separate borrowings, subject to the satisfaction or waiver of certain customary conditions. If not fully utilized, the term loan commitments expire on March 31, 2026. CERC Corp. borrowed $500 million on January 20, 2026, and expects to borrow the remaining $300 million during the first quarter of 2026. For further information, see Note 20 to the consolidated financial statements. Assets Held for Sale. On October 20, 2025, CenterPoint Energy, through its subsidiary CERC Corp., entered into the Ohio Securities Purchase Agreement, pursuant to which CERC Corp. has agreed to sell all of the issued and outstanding equity interests in CEOH. The purchase price is $2.62 billion, which is comprised of the following: (i) $1.42 billion in cash payable to CERC Corp. upon closing of the transaction, subject to adjustments as set forth in the Ohio Securities Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing of the transaction; and (ii) a 364-day seller promissory note, in the original principal amount of $1.2 billion, to be issued by NFGC at the closing of the transaction and payable to CERC Corp. as provided by the terms and conditions of the Seller Note Agreement. The transaction is not subject to a financing condition and is expected to close in the fourth quarter of 2026, subject to satisfaction of customary closing conditions. As of December 31, 2025, the assets included approximately 6,000 miles of transmission and distribution pipeline in Ohio serving approximately 337,000 metered customers. CEOH is reflected in CenterPoint Energy’s Natural Gas reportable segment and CERC’s single reportable segment, as applicable. For further information, see Note 4 to the consolidated financial statements. CenterPoint Energy Board Leadership Structure Changes. On October 8, 2025, the Board unanimously appointed Jason P. Wells, Chief Executive Officer and President of CenterPoint Energy, to serve as Chair of the Board, effective immediately. Mr. Wells has served as a director on the Board since January 5, 2024. In addition, the Board approved the creation of a Lead Independent Director of the Board position and the independent directors of the Board unanimously appointed independent director Christopher H. Franklin to serve as the Lead Independent Director of the Board, effective immediately. CenterPoint Energy Appointment of Chief Operating Officer. On July 21, 2025, CenterPoint Energy announced the appointment of Jesus Soto, Jr. to the position of Executive Vice President and Chief Operating Officer of CenterPoint Energy, effective August 11, 2025. OBBBA and Executive Order 14315. On July 4, 2025, the OBBBA was signed into law. The OBBBA includes significant provisions, such as the permanent extension of certain expiring provisions of the TCJA and numerous changes to the energy tax credits initially introduced and expanded under the IRA. The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. Additionally, on July 7, 2025, President Trump issued Executive Order 14315, which relates to the implementation of such changes to energy tax credits. The Registrants have assessed the potential effects of the OBBBA and Executive Order 14315 and concluded that neither is expected to have a material impact on their 54 future financial results because the Registrants have limited generation activities qualifying for tax credits under the IRA. The Registrants will consider the impacts of the OBBBA and Executive Order 14315, as well as related guidance, on any future generation projects, including any BTAs or PPAs, as applicable. Equity Transactions. In April 2025, Centerpoint Energy entered into forward sales agreements pursuant to the Equity Distribution Agreement with certain of the ATM Forward Purchasers. In May 2025, CenterPoint Energy entered into separate forward sale agreements with certain financial institutions. For further information about forward sales in 2025, see Note 11 to the consolidated financial statements. Regulatory Proceedings. In 2024, Houston Electric filed an Application for Determination of System Restoration Costs and a Financing Order with the PUCT for the May 2024 Storm Events, which were settled in 2025. In 2025, Houston Electric filed an Application for Determination of System Restoration Costs and a Financing Order with the PUCT for Hurricane Beryl and subsequent storm events, which were settled in 2025. For further information, see Note 7 to the consolidated financial statements. For information related to our pending and completed regulatory proceedings in 2025 and to date in 2026, see “—Liquidity and Capital Resources —Regulatory Matters” below. CERTAIN FACTORS AFFECTING FUTURE EARNINGS 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 that apply to all Registrants unless otherwise indicated including: • The business strategies and strategic initiatives, restructurings, joint ventures and acquisitions or dispositions of assets or businesses involving us or our industry, including the ability to successfully complete such strategies, initiatives, transactions or plans on the timelines we expect or at all, such as the announced sale of our Ohio natural gas LDC business, which we cannot assure will have the anticipated benefits to us; • industrial, commercial and residential growth in our service territories and changes in market demand and energy consumption, including in relation to the expansion of data centers (associated with, among other things, increasing demand for AI), energy refining and exports, advanced manufacturing and logistics, as well as the effects of energy efficiency measures, technological advances and demographic patterns, and our ability to appropriately estimate/forecast and effectively manage such demand and the business opportunities relating to such matters; • our ability to fund and invest planned capital and the timely recovery of our investments, including the timing of and amounts sought for those related to our 10-year capital plan; • our ability to execute and complete our planned capital projects and programs, including those within our 10-year capital plan, in a timely and cost-effective manner and within budget, obtain the anticipated benefits of such projects, and manage costs and impacts of such projects on customer affordability; • our ability to successfully construct, operate, repair, maintain, replace and restart electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities, as applicable, including in the event of an outage and in relation to complying with applicable environmental, reliability and safety standards; • timely and appropriate rate actions that allow and authorize timely recovery of costs and a reasonable return on investment, including the timing of and amounts sought for recovery of Houston Electric’s applicable TEEEF leases and restoration costs relating to, among other things, Hurricane Beryl, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings or interim rate mechanisms; • the timing and success of, and our ability to obtain approval for matters relating to, Houston Electric’s release of its large TEEEF units to the San Antonio area, proposed release of its medium TEEEF units, reduction of its TEEEF fleet capacity and reduction of rates to reflect the removal of the large and medium TEEEF units from Houston Electric’s TEEEF fleet, as well as Houston Electric’s ability to complete one or more other future transactions involving the large and medium TEEEF units on acceptable terms and conditions within the anticipated timeframe; • economic conditions in regional and national markets, including economic uncertainty and volatility, potential for recession, changes to and increases in inflation and interest rates, and their effect on sales, prices and costs; • severe weather events, natural disasters and other climate-related impacts, including the impact of severe weather events on operations, capital, legislation and/or regulations, such as seen in connection with the February 2021 Winter Storm Event, the May 2024 Storm Events and Hurricane Beryl; • volatility in the markets for natural gas as a result of, among other factors, inflation, adverse weather conditions, supply and demand changes, availability of competitively priced alternative energy sources, political and geopolitical instability, commodity production levels and storage capacity, energy and environmental legislation and regulation and economic and financial market conditions; 55 • non-payment for our services due to financial distress of our customers and the ability of our customers, including REPs, to satisfy their obligations to CenterPoint Energy, Houston Electric and CERC, and the negative impact on such ability related to adverse economic conditions and severe weather events; • public health threats, and their effect on our operations, business and financial condition, our industries and the communities we serve, U.S. and world financial markets and supply chains, potential regulatory actions and changes in customer and stakeholder behavior relating thereto; • federal, state and local legislative, executive and regulatory actions or developments affecting various aspects of our businesses, including, among others, any actions resulting from Hurricane Beryl, energy deregulation or re-regulation, pipeline integrity and safety, actions relating to our facilities and changes in regulation, legislation and governmental action pertaining to the utility model, trade (including tariffs, bans, retaliatory trade measures taken against the United States or related governmental action), the implementation of budget and spending cuts to federal government agencies and programs, effects of government shutdowns, policies incentivizing or disincentivizing the development or utilization of alternative sources of generation (including distributed generation), health care, finance and actions regarding the rates charged by our regulated businesses; • disruptions to the global supply chain, inflation, labor shortages and scarcity of certain materials, including as a result of changes in U.S. and foreign trade policy, geopolitical and economic uncertainty, regulatory and policy instability, severe weather and other catastrophic events, changes in laws, executive orders, legislation and other governmental action, increased competition for skilled labor and increases in demand for electricity, that could prevent CenterPoint Energy from securing the resources and labor needed to, among other things, fully execute on its strategy and 10-year capital plan, and otherwise impact the affordability of our rates for our customers; • operations and maintenance costs, our ability to control such costs and cost-related impacts on the affordability of our rates for our customers; • our ability to timely obtain and maintain necessary licenses, permits, easements and approvals from local, federal and other regulatory authorities on acceptable terms and resolve third-party challenges to such licenses, permits or approvals as applicable; • direct or indirect effects on our facilities, resources, operations, reputation and financial condition resulting from terrorism, vandalism, cyberattacks or intrusions, data security breaches or other security incidents, threats or attempts to disrupt our businesses or the businesses of supply chain stakeholders (including by foreign actors), or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, derecho events, ice storms and other severe weather events, wildfires, pandemic health events, geopolitical conflict, civil unrest or other occurrences; • the impact of negative opinions of us or our utility services that our customers, investors, legislators, regulators, creditors, rating agencies or other stakeholders may have or develop, which could result from a variety of factors, including actual or perceived failures in system reliability and safety, the speed of our response to service interruptions, rates and customer affordability, our ability to successfully execute our capital plan, media coverage and actions by third parties; • damages to our network, facilities and systems, including as a result of wildfires, as well as to third-party property resulting in outages or shortages in our service territories, and losses in excess of insurance liability coverage; • tax legislation and guidance and any changes in tax laws under the current or future administrations, including any further changes to or clarification of the IRA or the OBBBA, and any potential changes to tax rates, CAMT imposed, tax credits and/or interest deductibility, as well as uncertainties involving state commissions’ and local municipalities’ regulatory requirements and determinations regarding the treatment of EDIT and our rates; • our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms; • actions by credit rating agencies, including any potential downgrades to credit ratings; • local, state and federal legislative, executive and regulatory actions or developments relating to the environment, including, among others, those related to global climate risk, air emissions, GHG emissions, carbon emissions, wastewater discharges and the handling and disposal of CCR that could impact operations, cost recovery of generation plant costs and related assets, and CenterPoint Energy’s energy transition goals; • the impact of unplanned facility outages or other closures; • the sufficiency of our insurance coverage, including availability, cost, coverage and terms and ability to recover claims; • impacts from CenterPoint Energy’s pension and postretirement benefit plans, such as the investment performance and increases to net periodic costs as a result of plan settlements and changes in assumptions, including discount rates; • changes in interest rates and their impact on costs of borrowing and the valuation of CenterPoint Energy’s pension benefit obligation; 56 • commercial bank and financial market conditions, including disruptions in the banking industry, our access to capital, the cost of such capital, the results of our financing and refinancing efforts, including availability of funds in the capital markets, and impacts on our vendors, customers and suppliers; • inability of various counterparties to meet their obligations to us; • the extent and effectiveness of our risk management activities; • timely and appropriate regulatory actions, which include actions allowing requested securitization for any hurricanes or other severe weather events, such as Hurricane Beryl, or natural disasters or other amounts sought for recovery of costs, including stranded coal-fired generation asset costs; • our ability to attract, effectively transition, motivate and retain an appropriately qualified workforce, identify and develop top talent to succeed management and maintain good labor relations; • changes in technology, including with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation, and their adoption by consumers, and our ability to anticipate, adapt to and implement technological changes; • advances in AI and our success in timely adopting, developing and deploying AI; • the timing and outcome of any audits, disputes and other proceedings related to taxes; • the recording of impairment charges; • political and economic developments and actions, including energy and environmental policies under the current administration; • CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including energy transition goals and operations and maintenance expenditure goals; • the outcome of litigation, including litigation related to the February 2021 Winter Storm Event and Hurricane Beryl; • the effect of changes in and application of accounting standards and pronouncements; and • other factors discussed in “Risk Factors” in Part I, Item 1A of this report and in other reports that the Registrants file from time to time with the SEC. 57 CENTERPOINT ENERGY CONSOLIDATED RESULTS OF OPERATIONS CenterPoint Energy’s results of operations are affected by seasonal fluctuations in the demand for electricity and natural gas. CenterPoint Energy’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates its subsidiaries charge, debt service costs, income tax expense, its subsidiaries ability to collect receivables from REPs and customers and its ability to recover its regulatory assets. For information regarding factors that may affect the future results of our consolidated operations, see “Risk Factors” in Part I, Item 1A of this report. Net income (loss) available to common shareholders was as follows for the periods presented: Year Ended December 31, Favorable (Unfavorable) 2025 2024 2023 2025 to 2024 2024 to 2023 (in millions) Electric $ 705 $ 671 $ 654 $ 34 $ 17 Natural Gas (1) 570 566 533 4 33 Corporate & Other (2) (223) (218) (320) (5) 102 Total CenterPoint Energy $ 1,052 $ 1,019 $ 867 $ 33 $ 152 (1) Includes results of operations from Louisiana and Mississippi natural gas LDC businesses through the date of the sale on March 31, 2025. (2) Includes energy performance contracting and sustainable infrastructure services through Energy Systems Group through the date of sale on June 30, 2023, unallocated corporate costs, interest income and interest expense, intercompany eliminations and the reduction of income allocated to preferred shareholders through September 1, 2023, the date of the redemption of all of the outstanding shares of the Series A Preferred Stock. 2025 Compared to 2024 Net income available to common shareholders increased $33 million primarily due to the following items: • an increase in income available to common shareholders of $34 million for the Electric reportable segment, as further discussed below; • an increase in income available to common shareholders of $4 million for the Natural Gas reportable segment, as further discussed below; and • a decrease in income available to common shareholders of $5 million for the Corporate and Other reportable segment, primarily due to increased borrowing costs of approximately $37 million, offset by a $21 million gain on early extinguishment of debt using proceeds from the divestiture of the Louisiana and Mississippi natural gas LDCs, and a $20 million gain on early extinguishment of debt associated with the October 2025 tender offer, which is further discussed in Note 12 to the consolidated financial statements. The remaining variance is primarily driven by an increase in other corporate expenses, including expenses associated with proposed divestitures. 2024 Compared to 2023 Net income available to common shareholders increased $152 million primarily due to the following items: • an increase in income available to common shareholders of $17 million for the Electric reportable segment, as further discussed below; • an increase in income available to common shareholders of $33 million for the Natural Gas reportable segment, as further discussed below; and • an increase in income available to common shareholders of $102 million for the Corporate and Other reportable segment, primarily due to $50 million of income allocated to holders of Series A Preferred Stock in 2023 prior to the redemption of all outstanding shares of Series A Preferred Stock in September 2023 as discussed in Note 11 to the consolidated financial statements, a loss on sale of $13 million and current tax expense of $32 million related to the divestiture of Energy Systems Group recorded in 2023 further discussed in Note 4 to the consolidated financial statements, $19 million due to remeasurement of deferred income tax balances recorded during 2023, as well as $8 million due to lower state income taxes. The remaining variance is due largely to an increase in borrowing costs. Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. 58 CENTERPOINT ENERGY’S RESULTS OF OPERATIONS BY REPORTABLE SEGMENT CenterPoint Energy’s CODM views net income as the measure of profit or loss for the reportable segments. Segment results include inter-segment interest income and expense, which may result in inter-segment profit and loss. The following discussion of CenterPoint Energy’s results of operations is separated into two reportable segments, Electric and Natural Gas. Electric (CenterPoint Energy) The following table provides summary data of CenterPoint Energy’s Electric reportable segment for the periods presented: Year Ended December 31, Favorable (Unfavorable) 2025 2024 2023 2025 to 2024 2024 to 2023 (in millions, except throughput, weather and customer data) Revenues $ 4,866 $ 4,590 $ 4,290 $ 276 $ 300 Expenses: Utility natural gas, fuel and purchased power 270 198 176 (72) (22) Operation and maintenance 2,084 2,072 1,880 (12) (192) Depreciation and amortization 946 877 872 (69) (5) Taxes other than income taxes 321 304 272 (17) (32) Total expenses 3,621 3,451 3,200 (170) (251) Operating Income 1,245 1,139 1,090 106 49 Other Income (Expense): Interest expense and other finance charges (445) (372) (303) (73) (69) Other income, net 77 61 56 16 5 Income Before Income Taxes 877 828 843 49 (15) Income tax expense 172 157 189 (15) 32 Net Income $ 705 $ 671 $ 654 $ 34 $ 17 Throughput (in GWh): Residential 35,547 34,190 35,166 4 % (3) % Total 116,076 110,831 108,766 5 % 2 % Weather (percentage of normal weather for service area): Cooling degree days 112 % 115 % 114 % (3) % 1 % Heating degree days 98 % 76 % 90 % 22 % (14) % Number of metered customers at end of period: Residential 2,679,575 2,640,150 2,588,510 1 % 2 % Total 3,013,715 2,971,730 2,916,028 1 % 2 % 59 The following table provides variance explanations by major income statement caption for the Electric reportable segment: Favorable (Unfavorable) 2025 to 2024 2024 to 2023 (in millions) Revenues Customer rates and impact of the change in rate design $ 109 $ 143 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 88 217 Customer growth 26 26 Energy efficiency, partially offset in operation and maintenance below 29 5 Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (18) (20) Pass-through revenues, offset in operation and maintenance below 3 (5) Miscellaneous revenues, including service connections and off-system sales (11) 1 Lost revenues as a result of outages associated with Hurricane Beryl in 2024 10 (10) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (62) (70) Weather, efficiency improvements and other usage impacts 40 (9) Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below 62 22 Total $ 276 $ 300 Utility natural gas, fuel and purchased power Cost of purchased power, offset in revenues above $ (53) $ (87) Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above (19) 65 Total $ (72) $ (22) Operation and maintenance Transmission costs billed by transmission providers, offset in revenues above $ (40) $ (124) Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl in 2024 112 (112) Contract services (34) 16 Energy efficiency, and other pass-through, offset in revenues above (3) (1) Corporate support services (28) — Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 3 — Labor and benefits (9) 4 All other operation and maintenance expense, including materials and supplies and insurance (13) 25 Total $ (12) $ (192) Depreciation and amortization Ongoing additions to plant-in-service $ (74) $ (79) Lease expense associated with TEEEF units no longer eligible for regulatory deferral (59) — Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 64 74 Total $ (69) $ (5) Taxes other than income taxes Incremental capital projects placed in service, and the impact of updated property tax rates $ (17) $ (26) Franchise fees and other taxes — (6) Total $ (17) $ (32) Interest expense and other finance charges Changes in outstanding debt $ (90) $ (63) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (2) (4) Other, primarily AFUDC and impacts of regulatory deferrals 19 (2) Total $ (73) $ (69) Other income (expense), net Other income, including AFUDC - equity $ 19 $ 5 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (3) — Total $ 16 $ 5 Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements. 60 Natural Gas (CenterPoint Energy) The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment for the periods presented: Year Ended December 31, Favorable (Unfavorable) 2025 2024 2023 2025 to 2024 2024 to 2023 (in millions, except throughput, weather and customer data) Revenues $ 4,486 $ 4,050 $ 4,279 $ 436 $ (229) Expenses: Utility natural gas and fuel 1,846 1,520 1,888 (326) 368 Non-utility cost of revenues, including natural gas 4 3 3 (1) — Operation and maintenance 931 881 949 (50) 68 Depreciation and amortization 563 542 513 (21) (29) Taxes other than income taxes 245 237 245 (8) 8 Total expenses 3,589 3,183 3,598 (406) 415 Operating Income 897 867 681 30 186 Other Income (Expense): Loss on sale (49) — — (49) — Interest expense and other finance charges (208) (207) (188) (1) (19) Other income (expense), net 27 14 15 13 (1) Income Before Income Taxes 667 674 508 (7) 166 Income tax expense (benefit) 97 108 (25) 11 (133) Net Income $ 570 $ 566 $ 533 $ 4 $ 33 Throughput (in Bcf): Residential 220 189 199 16 % (5) % Commercial and industrial 423 426 418 (1) % 2 % Total Throughput 643 615 617 5 % — % Weather (percentage of 10-year average for service area): Heating degree days 96 % 78 % 86 % 18 % (8) % Number of metered customers at end of period: Residential 3,739,919 4,063,928 4,010,113 (8) % 1 % Commercial and industrial 289,166 304,606 303,841 (5) % — % Total (1) 4,029,085 4,368,534 4,313,954 (8) % 1 % (1) Decrease in number of metered customers from 2024 to 2025 is primarily attributable to customer accounts associated with the divestiture of the Louisiana and Mississippi natural gas LDCs in March 2025. See Note 4 for additional detail. 61 The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment: Favorable (Unfavorable) 2025 to 2024 2024 to 2023 (in millions) Revenues Cost of natural gas, offset in utility natural gas and fuel below $ 384 $ (368) Gross receipts tax, offset in taxes other than income taxes below 14 1 Weather and usage 12 (11) Non-volumetric and miscellaneous revenue 10 (5) Energy efficiency and other pass-through, offset in operation and maintenance below 40 (20) Non-utility revenues 2 15 Customer growth 14 14 Customer rates and impact of the change in rate design 142 145 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (182) $ — Total $ 436 $ (229) Utility natural gas and fuel Cost of natural gas, offset in revenues above $ (384) $ 368 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 58 — Total $ (326) $ 368 Non-utility costs of revenues, including natural gas Non-utility cost of revenues, including natural gas $ (1) $ — Total $ (1) $ — Operation and maintenance All other operations and maintenance expenses, including bad debt expense $ (15) $ 23 Energy efficiency and other pass-through, offset in revenues above (40) 20 Contract services (10) (6) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 53 — Labor and benefits (25) 8 Corporate support services (13) 23 Total $ (50) $ 68 Depreciation and amortization Ongoing additions to plant-in-service $ (60) $ (29) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 39 — Total $ (21) $ (29) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (14) $ (1) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 15 — Incremental capital projects placed in service, and the impact of updated property tax rates (9) 9 Total $ (8) $ 8 Loss on Sale Loss on sale of Louisiana and Mississippi natural gas LDC businesses $ (49) $ — Total $ (49) $ — Interest expense and other finance charges Changes in outstanding debt $ (6) $ (12) Other, primarily AFUDC and impacts of regulatory deferrals (5) (7) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 10 — Total $ (1) $ (19) Other income (expense), net Changes to non-service benefit cost $ 4 $ 3 Other income, including interest income from affiliated companies and AFUDC - Equity 10 (4) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (1) — Total $ 13 $ (1) Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 13 to the consolidated financial statements. 62 HOUSTON ELECTRIC CONSOLIDATED RESULTS OF OPERATIONS Houston Electric’s CODM views net income as the measure of profit or loss for its reportable segment. Houston Electric consists of a single reportable segment. Houston Electric’s results of operations are affected by seasonal fluctuations in the demand for electricity. Houston Electric’s results of operations are also affected by, among other things, the actions of various governmental authorities having jurisdiction over rates Houston Electric charges, debt service costs, income tax expense, Houston Electric’s ability to collect receivables from REPs and Houston Electric’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of Houston Electric’s consolidated operations, see “Risk Factors” in Item 1A of Part I of this report. The following table provides summary data of Houston Electric’s single reportable segment for the periods presented: Year Ended December 31, Favorable (Unfavorable) 2025 2024 2023 2025 to 2024 2024 to 2023 (in millions, except throughput, weather and customer data) Revenues: TDU $ 4,067 $ 3,862 $ 3,514 $ 205 $ 348 Bond Companies 17 77 163 (60) (86) Total revenues 4,084 3,939 3,677 145 262 Expenses: Operation and maintenance, excluding Bond Companies 1,913 1,923 1,669 10 (254) Depreciation and amortization, excluding Bond Companies 795 688 593 (107) (95) Taxes other than income taxes 312 295 262 (17) (33) Bond Companies 12 78 159 66 81 Total expenses 3,032 2,984 2,683 (48) (301) Operating Income 1,052 955 994 97 (39) Other Income (Expense): Interest expense and other finance charges (369) (311) (259) (58) (52) Interest expense on Securitization Bonds (6) (3) (8) (3) 5 Other income, net 48 43 34 5 9 Income Before Income Taxes 725 684 761 41 (77) Income tax expense 147 138 168 (9) 30 Net Income $ 578 $ 546 $ 593 $ 32 $ (47) Throughput (in GWh): Residential 34,101 32,769 33,830 4 % (3) % Total 111,083 106,014 103,862 5 % 2 % Weather (percentage of 10-year average for service area): Cooling degree days 114 % 115 % 114 % (1) % 1 % Heating degree days 94 % 92 % 92 % 2 % — % Number of metered customers at end of period: Residential 2,544,880 2,506,284 2,455,309 2 % 2 % Total 2,859,313 2,818,343 2,763,535 1 % 2 % 63 The following table provides variance explanations by major income statement caption for Houston Electric: Favorable (Unfavorable) 2025 to 2024 2024 to 2023 (in millions) Revenues Customer rates and impact of the change in rate design $ 34 $ 153 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 88 217 Customer growth 22 25 Energy efficiency, partially offset in operation and maintenance below 29 5 Miscellaneous revenues 13 1 Lost revenues as a result of outages associated with Hurricane Beryl in 2024 10 (10) Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (18) (19) Weather, efficiency improvements and other usage impacts 27 (24) Bond Companies, offset in other line items below (60) (86) Total $ 145 $ 262 Operation and maintenance, excluding Bond Companies Transmission costs billed by transmission providers, offset in revenues above $ (40) $ (124) Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl in 2024 112 (112) Contract services (29) 7 Energy efficiency, offset in revenues above (3) (6) Corporate support services (23) (2) Labor and benefits (8) 1 All other operation and maintenance expense, including materials and supplies and insurance 1 (18) Total $ 10 $ (254) Depreciation and amortization, excluding Bond Companies Ongoing additions to plant-in-service $ (47) $ (95) Lease expense associated with TEEEF units no longer eligible for regulatory deferral (60) — Total $ (107) $ (95) Taxes other than income taxes Incremental capital projects placed in service, and the impact of changes to tax rates $ (17) $ (26) Franchise fees and other taxes — (7) Total $ (17) $ (33) Bond Companies Operations and maintenance and depreciation expense, offset in revenues above $ 66 $ 81 Total $ 66 $ 81 Interest expense and other finance charges Changes in outstanding debt $ (75) $ (55) Other, primarily AFUDC and impacts of regulatory deferrals 17 3 Total $ (58) $ (52) Interest expense on Securitization Bonds Change in outstanding principal balance, offset in revenues above $ (3) $ 5 Total $ (3) $ 5 Other income, net Other income, including AFUDC - equity $ 7 $ 9 Bond Companies interest income, offset in other line items (2) — Total $ 5 $ 9 Income Tax Expense. For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. 64 CERC CONSOLIDATED RESULTS OF OPERATIONS CERC’s CODM views net income as the measure of profit or loss for its reportable segment. CERC consists of a single reportable segment. CERC’s results of operations are affected by seasonal fluctuations in the demand for natural gas. CERC’s results of operations are also affected by, among other things, the actions of various federal, state and local governmental authorities having jurisdiction over rates CERC charges, debt service costs and income tax expense, CERC’s ability to collect receivables from customers and CERC’s ability to recover its regulatory assets. For information regarding factors that may affect the future results of CERC’s consolidated operations, see “Risk Factors” in Item 1A of Part I of this report. The following table provides summary data of CERC’s single reportable segment for the periods presented: Year Ended December 31, Favorable (Unfavorable) 2025 2024 2023 2025 to 2024 2024 to 2023 (in millions, except throughput, weather and customer data) Revenues $ 4,344 $ 3,925 $ 4,149 $ 419 $ (224) Expenses: Utility natural gas 1,803 1,489 1,856 (314) 367 Non-utility cost of revenues, including natural gas 4 3 3 (1) — Operation and maintenance 895 848 904 (47) 56 Depreciation and amortization 541 522 493 (19) (29) Taxes other than income taxes 242 234 243 (8) 9 Total expenses 3,485 3,096 3,499 (389) 403 Operating Income 859 829 650 30 179 Other Income (Expense): Gain on sale 46 — — 46 — Interest expense and other finance charges (194) (197) (178) 3 (19) Other income (expense), net 25 12 14 13 (2) Income Before Income Taxes 736 644 486 92 158 Income tax expense (benefit) 97 104 (26) 7 (130) Net Income $ 639 $ 540 $ 512 $ 99 $ 28 Throughput (in BCF): Residential 214 184 194 16 % (5) % Commercial and Industrial 379 390 386 (3) % 1 % Total Throughput 593 574 580 3 % (1) % Weather (percentage of 10-year average for service area): Heating degree days 96 % 78 % 86 % 18 % (8) % Number of metered customers at end of period: Residential 3,634,422 3,958,584 3,905,388 (8) % 1 % Commercial and Industrial 278,500 293,959 293,235 (5) % — % Total (1) 3,912,922 4,252,543 4,198,623 (8) % 1 % (1) Decrease in number of metered customers is primarily attributable to customer accounts associated with the divestiture of the Louisiana and Mississippi natural gas LDCs in March 2025. See Note 4 for additional detail. 65 The following table provides variance explanations by major income statement caption for CERC: Favorable (Unfavorable) 2025 to 2024 2024 to 2023 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ 372 $ (367) Gross receipts tax, offset in taxes other than income taxes below 14 1 Weather and usage 12 (9) Energy efficiency and other pass-through, offset in operation and maintenance below 39 (10) Non-volumetric and miscellaneous revenue 11 (6) Non-utility revenues 2 15 Customer growth 14 13 Customer rates 137 139 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 (182) — Total $ 419 $ (224) Utility natural gas Cost of natural gas, offset in revenues above $ (372) $ 367 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 58 — Total $ (314) $ 367 Operation and maintenance All other operations and maintenance expenses, including bad debt expense $ (12) $ 21 Energy efficiency and other pass-through, offset in revenues above (39) 10 Contract services (12) (6) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 53 — Labor and benefits (25) 8 Corporate support services (12) 23 Total $ (47) $ 56 Depreciation and amortization Ongoing additions to plant-in-service $ (58) $ (29) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 39 — Total $ (19) $ (29) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (14) $ (1) Incremental capital projects placed in service, and the impact of updated property tax rates (9) 10 Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 15 — Total $ (8) $ 9 Gain on sale Gain on sale of Louisiana and Mississippi natural gas LDC businesses $ 46 $ — Total $ 46 $ — Interest expense and other finance charges Changes in outstanding debt $ (3) $ (11) Other, primarily AFUDC and impacts of regulatory deferrals (4) (8) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 $ 10 $ — Total $ 3 $ (19) Other income (expense), net Changes to non-service benefit cost $ 4 $ 3 Other income, including interest income from affiliated companies and AFUDC - Equity 10 (5) Impact of divestiture of Louisiana and Mississippi natural gas LDCs on March 31, 2025 $ (1) $ — Total $ 13 $ (2) Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. 66 LIQUIDITY AND CAPITAL RESOURCES Cash Flows The following table summarizes the Registrants’ cash flows by category for the periods presented: Year Ended December 31, 2025 2024 2023 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Cash provided by (used in): Operating activities $ 2,486 $ 1,177 $ 1,262 $ 2,139 $ 960 $ 1,068 $ 3,877 $ 1,401 $ 2,312 Investing activities (4,016) (2,349) (361) (4,489) (2,767) (1,419) (4,233) (2,503) (1,643) Financing activities 1,549 1,187 (903) 2,271 1,732 352 374 1,103 (668) Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities: 2025 compared to 2024 2024 compared to 2023 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Changes in net income after adjusting for non-cash items $ 76 $ 97 $ 25 $ 315 $ (132) $ 153 Changes in working capital (1) (231) (275) 48 (1,372) 191 (1,266) Other non-current assets 511 370 274 (580) (500) (135) Other non-current liabilities 189 52 (142) (57) (15) 49 Higher pension contribution (100) — — 2 — — Other (98) (27) (11) (46) 15 (45) $ 347 $ 217 $ 194 $ (1,738) $ (441) $ (1,244) (1) This change is primarily related to the receipt of proceeds at CenterPoint Energy and CERC from the issuance of customer rate relief bonds Texas by the Natural Gas Securitization Finance Corporation in 2023. For further details, see Note 7 to the consolidated financial statements. Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities: 2025 compared to 2024 2024 compared to 2023 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Payment for asset acquisition $ (357) $ — $ — $ — $ — $ — Net change in capital expenditures (357) (189) (88) $ (112) $ (363) $ 180 Net change in notes receivable from affiliated companies — 498 (1) — 108 2 Proceeds from divestitures 1,219 — 1,219 (144) — — Other (32) 109 (72) — (9) 42 $ 473 $ 418 $ 1,058 $ (256) $ (264) $ 224 67 Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities: 2025 compared to 2024 2024 compared to 2023 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Net changes in commercial paper outstanding $ 537 $ — $ (155) $ 516 $ — $ 436 Net changes in proceeds from issuance of Common Stock (494) — — 494 — — Net changes in long-term debt and term loans outstanding, excluding commercial paper (770) 63 (819) 51 (6) 725 Net changes in debt and equity issuance costs (11) (10) 3 20 5 11 Net changes in short-term borrowings 1 — 1 6 — 6 Redemption of Series A Preferred Stock — — — 800 — — Increased payment of Common Stock dividends (52) — — (37) — — Decreased payment of preferred stock dividends — — — 50 — — Net change in notes payable from affiliated companies — 54 291 — 642 — Change in dividend to parent — 41 (288) — 28 54 Change in contribution from parent — (750) (290) — (41) (210) Other 67 57 2 (3) 1 (2) $ (722) $ (545) $ (1,255) $ 1,897 $ 629 $ 1,020 Future Sources and Uses of Cash Material Current and Long-term Cash Requirements . The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, storm restoration costs, debt service requirements, tax payments, working capital needs and various regulatory actions. Future capital expenditures are expected to primarily relate to investments in infrastructure. These capital expenditures are anticipated to enhance the safety, reliability and resiliency of our systems and deliver consistent value for stakeholders across the Registrants’ jurisdictions. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2026 include the following: CenterPoint Energy Houston Electric CERC (in millions) Estimated capital expenditures $ 6,695 $ 4,031 $ 2,198 Scheduled principal payments on Securitization Bonds 40 27 — Scheduled principal payments on debt instruments, excluding Securitization Bonds 2,377 800 60 Expected contributions to pension plans and other postretirement plans 86 — 5 The Registrants expect that anticipated cash needs for 2026 will be met with available cash flows from operations, proceeds from the sale of our Ohio natural gas LDC business, as well as cash flows from financing (such as issuances of debt securities and equity securities upon physical settlement of outstanding forward sale agreements and borrowings under credit facilities, commercial paper issuances or other sources). The issuances of securities in the capital markets and borrowings under additional credit facilities and term loans may not, however, be available on acceptable terms. The Registrants may, from time to time, redeem, repurchase or otherwise acquire their outstanding debt securities through open market purchases, tender offers or pursuant to the terms of such securities. 68 The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for the periods presented. See Note 16 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2025. 2026 2027 2028 2029 2030 CenterPoint Energy (in millions) Electric $ 4,388 $ 4,736 $ 4,936 $ 3,777 $ 4,358 Natural Gas 2,288 2,163 2,122 1,924 2,024 Corporate and Other 19 20 20 20 20 Total $ 6,695 $ 6,919 $ 7,078 $ 5,721 $ 6,402 Houston Electric (1) $ 4,031 $ 4,326 $ 4,474 $ 3,440 $ 4,076 CERC (1) $ 2,198 $ 2,047 $ 1,994 $ 1,826 $ 1,899 (1) Houston Electric and CERC each consist of a single reportable segment. The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2025: 2026 2027 2028 2029 2030 Thereafter Total (in millions) CenterPoint Energy Short-term borrowings $ 500 $ — $ — $ — $ — $ — $ 500 Securitization Bonds (1) 40 37 39 41 43 514 714 Other long-term debt (1) (2) 1,877 326 3,941 870 1,469 13,470 21,953 Interest payments — Securitization Bonds (3) 38 32 30 28 26 134 288 Interest payments — other long-term debt (3) 1,024 956 914 749 3,170 8,223 15,036 Commodity and other commitments (4) 978 946 781 630 681 2,919 6,935 Total cash requirements $ 4,457 $ 2,297 $ 5,705 $ 2,318 $ 5,389 $ 25,260 $ 45,426 Houston Electric Short-term borrowings $ 500 $ — $ — $ — $ — $ — $ 500 Securitization Bonds (1) 27 23 24 25 26 277 402 Other long-term debt (1) 300 300 500 — 500 7,679 9,279 Interest payments — Securitization Bonds (3) 22 17 16 14 13 62 144 Interest payments — other long-term debt (3) 401 383 379 353 2,659 3,466 7,641 Total cash requirements $ 1,250 $ 723 $ 919 $ 392 $ 3,198 $ 11,484 $ 17,966 CERC Long-term debt (1) $ 60 $ 26 $ 1,779 $ 30 $ 500 $ 2,345 $ 4,740 Interest payments — long-term debt (3) 227 224 191 136 133 799 1,710 Commodity and other commitments (4) 684 587 542 522 480 1,322 4,137 Total cash requirements $ 971 $ 837 $ 2,512 $ 688 $ 1,113 $ 4,466 $ 10,587 (1) Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 12 to the consolidated financial statements for additional information. (2) ZENS obligations are included in the 2029 column at their contingent principal amount of less than $0.1 million as of December 31, 2025. These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($507 million as of December 31, 2025), as discussed in Note 10 to the consolidated financial statements. (3) The Registrants calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, the Registrants calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, the Registrants used interest rates in place as of December 31, 2025. The Registrants typically expect to settle such interest payments with cash flows from operations and short-term borrowings. (4) For a discussion of commodity and other commitments, see Note 14(a) to the consolidated financial statements. The table above does not include the following: • estimated future payments for expected future AROs primarily estimated to be incurred after 2030. See Note 3(c) to the consolidated financial statements for further information. 69 • expected contributions to pension plans and other postretirement plans in 2026 and expected benefit payments to be paid by the pension and postretirement benefit plans. See Note 8(g) to the consolidated financial statements for further information. • operating leases. See Note 19 to the consolidated financial statements for further information. Off-Balance Sheet Arrangements Other than Houston Electric’s general mortgage bonds issued as collateral for tax-exempt long-term debt of CenterPoint Energy as discussed in Note 12 and guarantees as discussed in Note 14(b) to the consolidated financial statements and short-term leases, the Registrants have no off-balance sheet arrangements. 70 Regulatory Matters TEEEF (CenterPoint Energy and Houston Electric) For information about TEEEF, see Note 7 to the consolidated financial statements. Hurricane Beryl (CenterPoint Energy and Houston Electric) For information about Hurricane Beryl, see Note 7 to the consolidated financial statements. May 2024 Storm Events (CenterPoint Energy and Houston Electric) For information about May 2024 Storm Events, see Note 7 to the consolidated financial statements. February 2021 Winter Storm Event (CenterPoint Energy, Houston Electric and CERC) For information about the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements. Indiana Electric Securitization of Generation Retirements (CenterPoint Energy) For further information about the issuance of SIGECO Securitization Bonds, see Note 7 to the consolidated financial statements. Indiana Electric CPCN (CenterPoint Energy) BTAs Indiana Electric pursued PTCs for solar projects following the passage of the IRA. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve an amended BTA to purchase the 191 MW Posey Solar project. Indiana Electric requested that project costs, net of PTCs, be recovered in rate base rather than a levelized rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. On September 6, 2023, the IURC issued an order approving the CPCN. On March 7, 2025, SIGECO completed the acquisition of Posey Solar from Arevon for a purchase price of approximately $357 million. The Posey Solar project was placed in service in the second quarter of 2025 and is currently being recovered through base rates. In the applicable rate case, the IURC approved Indiana Electric’s request to convey PTCs to customers through the new tax adjustment rider. For further information, see Note 4 to the consolidated financial statements. On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility located in the central region of MISO through a BTA, and on June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing Indiana Electric to purchase the wind generating facility. In August 2025, due to changing project considerations and concerns about customer affordability, Indiana Electric exited negotiations relating to this wind energy generating facility. On December 4, 2025, Indiana Electric filed a Notice of Termination in this proceeding. PPAs Indiana Electric sought approval in February 2021 for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which would provide equivalent equity return to offset imputed debt during the 25-year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera LLC and Indiana Electric renegotiated the terms of the agreement to increase the PPA price and Indiana Electric subsequently filed a request with the IURC to amend the previously approved PPA with certain modifications. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays and estimated interconnection cost increases, on April 24, 2025, Indiana Electric provided notice that it was exercising its right to terminate the PPA, which terminated all further obligations of Indiana Electric with respect to the project. On August 25, 2021, Indiana Electric filed with the IURC seeking approval to purchase 185 MW of solar power, under a 15-year PPA, from Oriden , which is developing a solar project in Vermillion County, Indiana, and 150 MW of solar power, under a 20-year PPA, from Origis, which is developing a solar project in Knox County, Indiana. On May 4, 2022, the IURC issued an order approving Indiana Electric to enter into both PPAs. In March 2022, when the results of the MISO 71 interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased largely due to escalating commodity and supply chain costs impacting manufacturers worldwide. In August 2022, Indiana Electric and Origis entered into an amended PPA, which reiterated the terms contained in the 2021 PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date has been delayed from 2024 to 2026. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2028. On May 9, 2025, Indiana Electric and Oriden terminated the PPA. On May 1, 2024, Indiana Electric filed with the IURC seeking approval to purchase 147 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Knox County, Illinois. On November 6, 2024, the IURC approved the Knox County wind PPA, which provided for the recovery of the purchase power costs through the fuel adjustment clause proceedings over the term of the PPA. The facility is targeted to be in operation in late 2026. On April 14, 2025, Indiana Electric filed with the IURC seeking approval to purchase 170 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Tama County, Iowa. On June 3, 2025, an amendment to the PPA was filed with the IURC requesting an extension of the PPA’s term from 25 to 27 years. Indiana Electric received a final order from the IURC on November 5, 2025. The facility became operational on December 9, 2025. The power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA. Indiana Electric 2025 IRP (CenterPoint Energy) On December 5, 2025, Indiana Electric submitted its 2025 IRP with the IURC pursuant to applicable Indiana law requiring electric utilities to develop and submit to the IURC every three years (unless extended) an IRP that uses economic modeling to consider the costs and risks associated with available generation resource options to provide reliable, cost effective electric service for the next 20-year period. Indiana Electric’s 2025 IRP was developed following a series of public meetings and stakeholder discussions occurring in 2025 and identified both a preferred portfolio, which assumes the status quo for Indiana Electric’s service territory, and an alternative preferred portfolio, which includes a potential large load addition. Due to the phasing out of IRA renewable energy tax incentives pursuant to the OBBBA, declining accreditation from MISO for renewable energy and increased price pressure on resources due to, among other things, tariffs and ongoing supply chain issues, the 2025 IRP extends the timing for Indiana Electric’s generation transition plan. Accordingly, both the preferred portfolio and the alternative portfolio call for using the interconnection at F.B. Culley unit 2 for a 90 MW battery storage unit by 2028 and the conversion of the A.B. Brown units 5 and 6 gas turbines to a combined cycle gas turbine unit in the near- to mid-term, depending on load conditions. Decisions around F.B. Culley 3 will be reevaluated in the next IRP in 2028. The 2025 IRP includes the cancellation of nearly $1 billion in non-economical renewable projects. For more information regarding the risks associated with Indiana Electric’s execution of its generation transition plan and its IRP, see “Risk Factors - Risk Factors Affecting Operations - Indiana Electric’s execution of its generation transition plan...” F.B. Culley Unit 2 (CenterPoint Energy) While Indiana Electric’s 2025 IRP (similar to previous IRPs) preferred portfolios included the retirement of F.B. Culley Unit 2, a coal-fired generation unit, by the end of 2025, the U.S. Department of Energy issued an emergency 202(c) order in December 2025 directing Indiana Electric to continue operating the unit through March 23, 2026. Indiana Electric has filed a complaint with the FERC to request creation of a cost recovery/cost allocation mechanism. If created, a separate filing will be made at a later date with the FERC to seek recovery of all costs incurred to comply with the U.S. Department of Energy’s emergency 202(c) order. Indiana Electric has also filed an application with the IURC in Cause No. 46350 to recover any compliance costs associated with the emergency 202(c) order that are not recovered through the FERC proceedings. Natural Gas Combustion Turbines (CenterPoint Energy) On June 17, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The $287 million turbine facility was constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana. Indiana Electric received approval for depreciation expense and post in-service carrying costs to be deferred in a regulatory asset until the date Indiana Electric’s base rates include a return on and recovery of depreciation expense on the facility. A new approximately 23.5-mile pipeline was constructed and is operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. FERC granted a certificate to construct the pipeline on October 20, 2022. On January 7, 2025, the United States Court of Appeals for the D.C. Circuit affirmed FERC’s order granting the certificate. Indiana Electric granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. In the second quarter of 2025, 230 MW of the facility was 72 placed in service, and, due to a transformer manufacturing issue, the remaining 230 MW of the facility was placed in service in the third quarter of 2025. Indiana Electric received approval from the IURC on February 3, 2025, to recover for each combustion turbine by adjusting base rates as they are placed in service. The first turbine and second turbine are currently being recovered in base rates that were updated on June 17, 2025 and October 1, 2025, respectively. Stewart-West Bay Transmission Project (CenterPoint Energy and Houston Electric) On April 30, 2025, Houston Electric filed a CCN application with the PUCT for approval to replace a portion of a 138 kV double circuit transmission line in Galveston County, Texas that connects Houston Electric’s Stewart and West Bay substations. On June 27, 2025, an order was issued dismissing all opposing parties from the proceeding. On August 11, 2025, a notice of approval of Houston Electric’s application was issued. The project is estimated to cost approximately $105 million, but the actual capital cost of the project will depend on construction costs and other factors. Completion of construction and energization of the line is anticipated to occur in the third quarter of 2027. Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric) On December 17, 2020, Houston Electric filed a CCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer, EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first quarter of 2027. Kilgore Transmission Project (CenterPoint Energy and Houston Electric) On August 30, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Chambers County, Texas that will loop the existing 138 kV Chevron to Langston circuit number 86 on Houston Electric’s transmission system to Houston Electric’s planned Kilgore substation. On March 7, 2024, the PUCT issued a final order approving a route that was estimated to cost $60 million, including substation costs. The actual capital costs of the project, including the transmission line and the planned Kilgore substation, will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the fourth quarter of 2026. Mill Creek Transmission Project (CenterPoint Energy and Houston Electric) On November 17, 2023, Houston Electric filed a CCN application with the PUCT for approval to build a 138 kV double circuit transmission line in Harris and Montgomery Counties, Texas that will connect Houston Electric’s transmission system to Houston Electric’s planned Mill Creek substation. On November 21, 2024, the PUCT issued a final order approving a route estimated to cost $68 million. The actual capital costs of the project will depend on actual land acquisition costs, construction costs, and other factors. Completion of construction and energization of the line and substation is anticipated to occur in the second quarter of 2027. Indiana Legislation (CenterPoint Energy) Indiana Electric is evaluating legislation filed in Indiana’s 124th General Assembly, including House Bill 1002, a multi-faceted bill aimed at improving the affordability of electric rates. House Bill 1002 would do the following: • beginning in 2026, require an electric utility to file a multi-year rate plan according to a prescribed schedule; • apply a customer affordability performance metric and a service restoration performance metric to each year of the multi-year rate plan and use such metric to provide financial rewards or penalties based on the electricity supplier’s measured performance of the metric; • require an electric utility to offer a low income customer assistance program by July 1, 2026 to be funded by at least 0.2% of jurisdictional revenues for residential customers and allow the utility to seek recovery of eligible program costs; • prohibit an electric utility from terminating service to any customer on a day forecasted by the National Weather Service to have a heat index of at least 95 degrees Fahrenheit; • modify the IURC’s authority related to use of emergency powers; 73 • apply a levelized billing plan to residential customers who are eligible and have applied for the Low Income Housing Energy Assistance Program; and • require an electric utility to report certain residential customer data to the Office of the Utility Consumer Counselor on a quarterly basis. There are other bills moving through the 124th General Assembly, including legislation regarding surplus interconnection service, nuclear facility permits, and a bill on land use and developments that includes siting of battery energy storage systems. Texas Legislation (CenterPoint Energy, Houston Electric and CERC) The Registrants are evaluating the effects of certain legislation passed in 2025 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 89th Texas Legislature: • House Bill 4384, effective June 20, 2025, allows LDCs to recover post in-service carrying costs (PISCC) in GRIP filings. This allows LDCs to defer for future recovery as a regulatory asset PISCC, depreciation expense and ad valorem taxes associated with unrecovered gross plant. • Senate Bill 231, effective June 20, 2025, provides that, on or after the effective date, TDUs may only enter into, renew or extend leases for TEEEF units with a maximum generation capacity 5 or fewer MW and that are rapidly deployable, and that they may enter into leases without prior PUCT preapproval (as required by the TEEEF Rule) in the case of an emergency or if the lease includes a provision allowing for the alteration of the lease based on applicable PUCT orders or rules. • Senate Bill 1963, effective September 1, 2025, allows ERCOT utilities to securitize system restoration costs using a third-party government agency, which may allow for the debt to be off balance sheet and an abbreviated proceeding timeline. This bill also lowered the system restoration costs threshold from $100 million to $50 million, provided the effectiveness tests are met. • Senate Bill 482, effective September 1, 2025, results in increased penalties for assaulting a utility worker to a third-degree felony, equal to assaulting a first responder, and for harassing a utility worker to a Class A misdemeanor. Transmission and Distribution System Resiliency Plans (CenterPoint Energy and Houston Electric) Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed a revised SRP with the PUCT on January 31, 2025 for review and approval. The filed SRP proposed to invest approximately $5.75 billion over a three-year period from 2026 to 2028 for transmission and distribution infrastructure, information technology and cybersecurity assets and event response capability. This plan proposed 39 resiliency-enhancing measures and a microgrid pilot program to be implemented over the three-year period. The SRP as filed had an estimated capital cost of approximately $5.54 billion and an estimated operations and maintenance expense of approximately $211 million. Approximately $2.17 billion of such cost was for transmission-related investments, and approximately $3.58 billion was for distribution-related investments. Intervenor testimony was filed on April 8, 2025, and PUCT staff testimony was filed on April 15, 2025. On June 12, 2025, Houston Electric announced that it had reached a settlement agreement with parties to its SRP, which provides for approximately $3.18 billion in distribution-related investments. The proposed transmission investments were removed from the SRP and Houston Electric intends to implement such investments, as appropriate, outside of the SRP process. The agreement also includes the deferral of more than $240 million of the approximate $3.18 billion in SRP costs until the second half of 2029, which is intended to help reduce the bill impact for customers by spreading costs over a four-year period instead of three years. Once approved, and while some cost recovery would be deferred into 2029, it is expected that all SRP work agreed upon in the settlement agreement will be completed in the proposed 2025 to 2028 timeframe. At its November 14, 2025 open meeting, the PUCT approved the SRP. The final order issued on November 19, 2025 includes twenty-seven resiliency measures totaling approximately $2.68 billion in capital investments and an estimated $185 million in operations and maintenance expense. The approved SRP also includes the deferral of $217 million of the approximate $2.87 billion in SRP costs until the second half of 2029. Rate Change Applications The Registrants are routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Registrants are periodically involved in proceedings to adjust their capital tracking mechanisms (e.g., CSIA, DCRF, DRR, GRIP, TCOS, ECA, CECA and TDSIC), their decoupling mechanisms (e.g., decoupling and SRC), and their energy efficiency cost trackers (e.g., CIP, DSMA, EECRF, EEFC and EEFR). Minnesota Gas Rate Case. On November 1, 2023, CERC filed an application with the MPUC requesting an adjustment to delivery charges in 2024 and 2025 for the natural gas business in Minnesota. The requested increase was for approximately 74 6.5% or $85 million for 2024 and an additional approximately 3.7% or $52 million for 2025. The need for a rate change was primarily driven by continuing investment in the safety and reliability of the natural gas system, including new Intelis natural gas meters that feature an integrated safety shutoff valve, changes to depreciation rates that better reflect the actual life and salvage characteristics of assets and changes in other costs to serve customers. The request reflected a proposed 10.3% ROE on a 52.5% equity ratio. Interim rates for 2024 of $69 million, subject to refund, were implemented as of January 1, 2024. A request for interim rates of $33 million for 2025 was filed on September 30, 2024, approved at the December 3, 2024 hearing and approved by an order issued December 20, 2024. A unanimous settlement agreement was filed on November 25, 2024 and provided for an increase of $60.8 million for 2024 and an additional $42.7 million for 2025. The parties agreed to an overall cost of capital of 7.07% for 2024 and 2025. The ALJ filed a report on February 13, 2025 recommending that the MPUC approve the settlement agreement. As required by the December 20, 2024 order, the difference between 2024 interim rates and the settled amount of $60.8 million was refunded to customers in March 2025. Exceptions to the ALJ report were filed on April 18, 2025. On May 29, 2025, the MPUC approved the settlement agreement. A final order approving the settlement agreement was issued by the MPUC on June 27, 2025 and final rates were implemented on September 1, 2025. Indiana Electric Rate Case. On December 5, 2023, Indiana Electric filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase was approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase was primarily driven by the continuing investment in the safety and reliability of the system and normal increases in operating expenses. The initial filing of the rate case reflected a proposed 10.4% ROE on a forecasted 55% equity ratio. Indiana Electric reached a settlement agreement with less than all parties and submitted the agreement to the IURC on May 20, 2024. The settlement reflected a proposed 9.8% ROE on a forecasted 55% equity ratio. The requested increase was lowered to $80 million, an 11% increase. Indiana Electric received a final order on February 3, 2025 approving the settlement with one modification that effectively capped the residential increase to 1.15% of the total increase, allocating the difference to other commercial and industrial customers. The final order approved the 9.8% ROE on a forecasted 55% equity ratio and increases revenues by $80 million. Houston Electric Rate Case. On March 6, 2024, Houston Electric filed an application with the PUCT requesting authority to change rates and charges for electric transmission and distribution service. The requested increase was approximately $17 million (1%) for retail customers and $43 million (6.6%) for wholesale transmission service, excluding TCRF and rate case expenses. The need for a rate increase was primarily driven by continuing investment that has been made to support customer growth and to bolster the safety and reliability of Houston Electric’s transmission and distribution system. The request reflected a proposed 10.4% ROE and a 45% equity ratio. Errata testimony was filed t