CENTERPOINT ENERGY INC 10-K

cnp-20241231 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 , 2024 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 Chicago 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, 2024 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) $ 19,797,614,936 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 10, 2025: CenterPoint Energy, Inc. 651,729,244 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 2025 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2024, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K. TABLE OF CONTENTS PART I Page Item 1. Business 1 Item 1A. Risk Factors 18 Item 1B. Unresolved Staff Comments 43 Item 1C. Cybersecurity 43 Item 2. Properties 45 Item 3. Legal Proceedings 48 Item 4. Mine Safety Disclosures 48 PART II Item 5. Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 48 Item 6. [Reserved] 49 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 49 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 88 Item 8. Financial Statements and Supplementary Data 91 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 181 Item 9A. Controls and Procedures 181 Item 9B. Other Information 184 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 184 PART III Item 10. Directors, Executive Officers and Corporate Governance 184 Item 11. Executive Compensation 184 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 184 Item 13. Certain Relationships and Related Transactions, and Director Independence 184 Item 14. Principal Accounting Fees and Services 184 PART IV Item 15. Exhibits and Financial Statement Schedules 186 Item 16. Form 10-K Summary 186 i GLOSSARY AFUDC Allowance for funds used during construction AGC Alcoa Generating Corporation, a subsidiary of Alcoa, Inc. 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 AROK Asset Purchase Agreement Asset Purchase Agreement, dated as of April 29, 2021, by and between CERC Corp. and Southern Col Midco, LLC, a Delaware limited liability company and an affiliate of Summit Utilities, Inc. 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 August Junior Subordinated Notes Junior Subordinated Series A Notes and Junior Subordinated Series B Notes Bcf Billion cubic feet Board CenterPoint Energy’s Board of Directors Bond Companies Bond Company IV and Restoration Bond Company, each a wholly-owned, bankruptcy remote entity formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds Bond Company IV CenterPoint Energy Transition Bond Company IV, LLC, a wholly-owned subsidiary of Houston Electric 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 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 ii GLOSSARY 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. 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 CNP Midstream CenterPoint Energy Midstream, Inc., a wholly-owned subsidiary of CenterPoint Energy 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 COVID-19 ERP COVID-19 Electricity Relief Program Credit Agreements The CenterPoint Energy Credit Agreement, Houston Electric Credit Agreement, CERC Credit Agreement and SIGECO Credit Agreement CSIA Compliance and System Improvement Adjustment DA Distribution Automation 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 Energy Transfer Energy Transfer LP, a Delaware limited partnership Energy Transfer Common Units Energy Transfer common units, representing limited partner interests in Energy Transfer Energy Transfer GP LE GP, LLC, a Delaware limited liability company and sole general partner of Energy Transfer Energy Transfer Series G Preferred Units Energy Transfer Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Energy Transfer 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 iii GLOSSARY 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 ESPC Energy Savings Performance Contract 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 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 GHRI The Greater Houston Resiliency Initiative, which was announced by Houston Electric in August 2024 and includes targeted actions to improve the resiliency of Houston Electric’s electric grid, as well as improve customer communications and community partnerships 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 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 Infrastructure Services Provided underground pipeline construction and repair services through VISCO and its wholly-owned subsidiaries, Miller Pipeline, LLC and Minnesota Limited, LLC IRA Inflation Reduction Act of 2022 iv GLOSSARY 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 Interest Reset Period Each five-year period following February 15, 2030 Junior Subordinated Series A Notes 7.000% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series A, due 2055 Junior Subordinated Series B Interest Reset Period Each five-year period following February 15, 2035 Junior Subordinated Series B Notes 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes, Series B, due 2055 Junior Subordinated Series C Interest Reset Period Each five-year period following May 15, 2030 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 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 LIBOR London Interbank Offered Rate LNG Liquefied natural gas Load Shed Curtailing the amount of electricity a TDU can transmit and distribute to its customers LPSC Louisiana Public Service Commission LTIPs Long-term incentive plans 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 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 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. MP2017 2017 pension mortality improvement scale developed annually by the Society of Actuaries MP2018 2018 pension mortality improvement scale developed annually by the Society of Actuaries MP2019 2019 pension mortality improvement scale developed annually by the Society of Actuaries MPSC Mississippi Public Service Commission MPUC Minnesota Public Utilities Commission Mva Megavolt amperes MW Megawatts NAV Net asset value Natural Gas Natural gas distribution businesses NECA National Electrical Contractors Association NERC North American Electric Reliability Corporation NGA Natural Gas Act of 1938 NGLs Natural gas liquids v GLOSSARY 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 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 Railroad Commission Railroad Commission of Texas RCRA Resource Conservation and Recovery Act of 1976 Registrants CenterPoint Energy, Inc., CenterPoint Energy Houston Electric, LLC and CenterPoint Energy Resources Corp., collectively Reliant Energy Reliant Energy, Incorporated REP Retail electric provider Restoration Bond Company CenterPoint Energy Restoration Bond Company, LLC, a wholly-owned subsidiary of Houston Electric Restructuring CERC Corp.’s common control acquisition of Indiana Gas and VEDO from VUH on June 30, 2022 ROE Return on equity ROU Right of use RRA Rate Regulation Adjustment RSP Rate Stabilization Plan 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 Securitization Bonds Transition and system restoration bonds issued by the Bond Companies and SIGECO Securitization Bonds issued by the SIGECO Securitization Subsidiary 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 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 vi GLOSSARY 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 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 Texas RE Texas Reliability Entity 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 VEDO Vectren Energy Delivery of Ohio, LLC, which converted its corporate structure from Vectren Energy Delivery of Ohio, Inc. to a limited liability company on June 13, 2022, formerly a wholly-owned subsidiary of Vectren, acquired by CERC on June 30, 2022 VIE Variable interest entity VISCO Vectren Infrastructure Services Corporation, formerly a wholly-owned subsidiary of Vectren Vistra Energy Corp. Texas-based energy company focused on the competitive energy and power generation markets. VRP Voluntary Remediation Program VUH Vectren Utility Holdings, LLC, which converted its corporate structure from Vectren Utility Holdings, Inc. to a limited liability company on June 30, 2022, a wholly-owned subsidiary of Vectren WBD Common Warner Bros. Discovery, Inc. Series A common stock Winter Storm Elliott From December 21 to 26, 2022, a historic extratropical cyclone created winter storm conditions, including blizzards, high winds, snowfall and record cold temperatures across the majority of the United States and parts of Canada. ZENS 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 ZENS-Related Securities As of December 31, 2023 and December 31, 2022, consisted of AT&T Common, Charter Common and WBD Common 2023 Form 10-K Annual Report on Form 10-K for the fiscal year ended December 31, 2023 2022 Annuity Purchase The irrevocable group annuity contract purchased in December 2022 from an insurance company to transfer $138 million of CenterPoint Energy’s pension plan’s outstanding benefit obligation vii 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 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 Generation, Transmission and Distribution (CenterPoint Energy and Houston Electric) • Disruptions at power generation facilities, generation inadequacy or directives issued by regulatory authorities could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and adversely affect their reputation, financial condition, results of operations and cash flows. • Indiana Electric’s execution of its generation transition plan, including its IRP, 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 financial condition, results of operations and cash flows. • Houston Electric’s use of TEEEF is subject to various risks, including failure to obtain and deploy sufficient TEEEF resources, 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. • The occurrence of extreme weather events, including winter storms and record hot temperatures, or other causes could lead to additional reforms to the Texas electric market, some measure of which, if implemented, could have an adverse impact on Houston Electric. viii Natural Gas (CenterPoint Energy and CERC) • Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for Natural Gas’ customers. • Natural Gas is subject to fluctuations in natural gas prices, which could affect the ability of its suppliers and customers to meet their obligations or may impact its operations, which could adversely affect CERC’s financial condition, results of operations and cash flows. • Natural Gas must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on CenterPoint Energy’s and CERC’s financial condition, results of operations and cash flows. Risk Factors Affecting Regulatory, Environmental and Legal Risks • Rate regulation of Registrants’ Electric and Natural Gas businesses may delay or deny their ability to earn an expected return and fully and timely recover their costs. • 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 and creditors relating to actual or perceived system reliability, the speed of our response to service interruptions, rates, 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, results of operations, cash flows and financial condition. For example, Hurricane Beryl caused severe disruptions to our operations, customers and markets in certain of our service territories and potential results arising from governmental and regulatory inquiries and investigations, as well as associated litigation, could have a material adverse impact on our financial condition, results of operations, cash flows and liquidity. • 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. • 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 GHG emissions reduction goals. Risk Factors Affecting Financial, Economic and Market Risks • Disruptions to the global supply chain may lead to higher prices for goods and services and impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our 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 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 would 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 reputation, 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. General and Other Risks • Our revenues and results of operations are seasonal. • Climate change and other weather and natural disaster impacts could adversely impact financial results from our businesses and our results of operations. ix • We are exposed to risks related to changes in demand and energy consumption that could adversely impact financial results from our businesses and our results of operations. • 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 technological change and may not be successful or may have to incur significant expenditures to adapt to technological change. x 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. Each registrant makes no representation as to information relating exclusively 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 stated otherwise. 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, 2024, CenterPoint Energy’s indirect, wholly-owned 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. Bond Company IV is a wholly-owned, bankruptcy-remote entity formed solely for the purpose of purchasing and owning transition property through the issuance of Securitization Bonds; • CERC Corp., which (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi 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, 2024, 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 June 30, 2023, CenterPoint Energy completed the sale of its indirect subsidiary, Energy Systems Group, to an unaffiliated third party. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 4 to the consolidated financial statements. The Registrants’ principal executive offices are located at 1111 Louisiana, Houston, Texas 77002 (telephone number: 713-207-1111). 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 1 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, Human Capital and Compensation, Governance, Environmental and Sustainability, and Safety and Operations committees of our Board of Directors. 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 leased 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. Temporary Generation. As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric is leasing TEEEF that can aid in restoring power to customers during certain significant power outages that are 2 impacting its distribution system. On December 19, 2024, Houston Electric announced a proposal to release certain of Houston Electric’s TEEEF to the San Antonio area prior to the summer of 2025 for a period of up to two years, during which Houston Electric would not receive revenue or profit from ERCOT and would not charge Houston-area customers for these TEEEF units. As of December 31, 2024, Houston Electric leased 505 MW of TEEEF. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Executive Summary — Significant Events — May 2024 Storm Events and Hurricane Beryl” in Item 7 of Part II of this report, as well as Note 7 and Note 19 to the consolidated financial statements. Bond Companies Houston Electric has special purpose subsidiaries consisting of the Bond Companies, which it consolidates. These consolidated special purpose subsidiaries are wholly-owned, bankruptcy-remote entities that were formed solely for the purpose of purchasing and owning transition or system restoration property through the issuance of Securitization Bonds, and conducting activities incidental thereto. The Securitization Bonds issued by Bond Company IV were repaid through charges imposed on customers in Houston Electric’s service territory. Restoration Bond Company repaid in full its last outstanding system restoration bonds at maturity on August 15, 2022, and was subsequently dissolved in 2024. On October 15, 2024, Bond Company IV repaid in full its last outstanding transition bonds at maturity. For further discussion of the Securitization Bonds issued by Bond Company IV and the outstanding balances as of December 31, 2024 and 2023, 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, 2024: REPs Residential Commercial/ Industrial Total Customers Texas Gulf Coast 67 2,506,284 312,059 2,818,343 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. 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 3 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, 2024: Residential Commercial/Industrial Total Customers Southwestern Indiana 133,866 19,541 153,407 System Load Total load and the related reserve margin at the time of the system summer peak on August 29, 2024, is presented below in MW, except for reserve margin at peak: 2024 Total load at peak 1,062 Generating capability 720 Purchase supply (effective capacity) (1) 698 Interruptible contracts & direct load control 15 Total power supply capacity 1,433 Reserve margin at peak 35 % (1) Indiana Electric procured bi-lateral capacity contracts starting in the 2023-2024 MISO planning year. These contracts were procured before MISO moved to a seasonal construct, which allowed several generating units to receive accreditation in the summer season that would not have received any accreditation under MISO's previous annual construct. This resulted in a reserve margin that is higher than normal in the summer, but was limited to the summer season. The winter peak load for the 2023-2024 season of approximately 835 MW occurred on January 16, 2024. 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 Expected Date in Service Capacity (MW) Term (in Years) Solar Clenera, LLC Warrick County, Indiana 2026 100 25 Solar Oriden Vermillion County, Indiana 2026 185 15 Solar Origis Knox County, Indiana 2026 150 20 Wind NextEra Energy, Inc. Knox County, Illinois 2026 147 25 582 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 4 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, 2024, Sunrise LLC accounted for 88% of Indiana Electric’s coal purchases, with the remaining 12% being purchased from other suppliers. The table below presents information related to coal purchases during the year ended December 31, 2024 and coal inventory as of December 31, 2024: (In tons, except average cost per ton) Coal purchased for generating electricity 883,308 Coal inventory as of December 31, 2024 263,321 Average cost of coal per ton $54.41 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 2024 (in GWh) Coal OVEC (1) Indiana and Ohio 2040 32 178 Wind Benton County Wind Farm, LLC Benton County, Indiana 2028 30 83 Wind Fowler Ridge II Wind Farm, LLC Benton/Tippecanoe Counties, Indiana 2029 50 134 112 395 (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, 2024 was as follows: In GWh Net purchases (1) 2,406 Net sales (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. Net sales were insignificant during 2024 primarily due to the retirement of SIGECO’s A.B. Brown coal generating facilities in 2023 and SIGECO’s exit from joint operations in the Warrick 4 coal generating facility on January 1, 2024. Interconnections As of December 31, 2024, 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 645 MW during peak load periods. Indiana Electric, as required as a member of the MISO, has turned over operational control of the interchange facilities 5 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. SIGECO Securitization Subsidiary SIGECO has a special purpose subsidiary, SIGECO Securitization Subsidiary, which it consolidates. This consolidated special purpose subsidiary is a wholly-owned, bankruptcy-remote 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, 2024, 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 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 provide permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP. CenterPoint Energy’s and CERC’s Natural Gas also provided services in Minnesota consisting of residential appliance repair and maintenance services along with HVAC equipment sales and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party as of December 31, 2024. 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 February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction was approved by final orders issued by the MPSC on December 3, 2024 and by the LPSC on December 17, 2024. The transaction is expected to close in the first quarter of 2025. 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 customers by state as of December 31, 2024: Residential Commercial/ Industrial/Transportation Total Customers Indiana (Indiana Gas) 606,536 55,745 662,281 Louisiana 231,962 16,214 248,176 Minnesota 859,065 72,890 931,955 Mississippi 123,175 13,152 136,327 Ohio 310,541 24,589 335,130 Texas 1,827,305 111,369 1,938,674 Total CERC Natural Gas 3,958,584 293,959 4,252,543 Indiana (SIGECO) 105,344 10,647 115,991 Total CenterPoint Energy Natural Gas 4,063,928 304,606 4,368,534 The largest metropolitan areas served in each state were Houston, Texas; Minneapolis, Minnesota; Shreveport, Louisiana; Biloxi, Mississippi; Evansville, Indiana; and Dayton, Ohio. The table below reflects the percentage of total throughput by customer type for the year ended December 31, 2024: CenterPoint Energy CERC Residential 31 % 32 % Commercial/Industrial and Transportation 69 % 68 % 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 2024, approximately 64% and 65% of CenterPoint Energy’s and CERC’s Natural Gas total throughput occurred in the first and fourth quarters, respectively. These patterns reflect the higher demand for natural gas for heating purposes during the colder months. Supply and Transportation In 2024, CenterPoint Energy’s Natural Gas purchased virtually all of its 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, 2024 were as follows: CenterPoint Energy CERC Tenaska Marketing Ventures, LLC 33 % 31 % BP Energy Company 11 % 12 % Macquarie Energy, LLC 11 % 11 % Total of major suppliers 55 % 54 % 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 transports 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 anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration. 7 CenterPoint Energy’s and CERC’s Natural Gas actively engage in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with CenterPoint Energy’s and CERC’s Natural Gas’ physical gas suppliers. Their gas supply plans generally call for 50–75% 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 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 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 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 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 businesses continue to utilize AMAs associated with their utility distribution service in Indiana, Louisiana, Minnesota, Mississippi and Texas. Generally, AMAs are contracts between CenterPoint Energy’s and CERC’s Natural Gas 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 agrees 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 and to use the released capacity for other purposes when it is not needed for CenterPoint Energy’s and CERC’s Natural Gas. CenterPoint Energy’s and CERC’s Natural Gas may receive compensation from the asset manager through payments made over the life of the AMAs. CenterPoint Energy’s and CERC’s Natural Gas has 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 either sells natural gas to the asset manager and agrees 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. For amounts outstanding under these AMAs, see Note 12 to the consolidated financial statements. Competition CenterPoint Energy’s and CERC’s Natural Gas 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’ facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Corporate and Other (CenterPoint Energy) CenterPoint Energy’s Corporate and Other 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 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. 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, 2024. 8 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. 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. 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 9 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 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. Costs of 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. Proceeds from the sales of energy from Indiana Electric’s generation facilities that exceed the requirements of retail customers are shared by Indiana Electric and 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 the discharge of constituents 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 provides 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 20 to 30 years. CenterPoint Energy’s and CERC’s Natural Gas expects 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 is 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 have annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized. 10 For a discussion of certain of CenterPoint Energy’s and CERC’s Natural Gas’ 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 Congress and with that reauthorization comes changes to the legislative requirements that 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 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 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, 2024. 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: 11 • 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. Increasingly, environmental regulation has resulted in more restrictions and limitations on activities that may impact the environment. 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 and safety 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. Greenhouse Gas and Climate Change-Related Regulation and Compliance (CenterPoint Energy) There is increasing attention being paid in the United States and worldwide to the issue of climate change. 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 on the state, federal, or international level. The EPA released its initial GHG regulation for fossil fuel-fired electric generating units in 2015. Since then, various iterations of GHG regulations have been promulgated, withdrawn and litigated, and the current rule applicable to fossil fuel-fired electric generating units was finalized in April 2024. 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. On February 19, 2021, the United States formally rejoined the Paris Agreement, which drove a renewed regulatory push to require further GHG emission reductions from the energy sector, and led negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, the United States announced goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035 from a 2021 baseline, which formed the basis of the U.S. commitments announced in Glasgow. Nevertheless, on January 20, 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement, marking a significant shift in U.S. climate policy. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. Additionally, in January 2025, President Trump signed a series of executive orders that, among other things, (i) call upon the EPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act and issue guidance on the “social cost of carbon” to consider whether such metric should be eliminated, (ii) direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, (iii) temporarily halt certain federal government agencies from issuing approvals, permits and loans for onshore wind projects pending the completion of certain assessments and reviews and (iv) pause the disbursement of funds appropriated through the IRA and the Infrastructure Investments and Jobs Act. In September 2021, CenterPoint Energy announced its net zero emissions goals for both Scope 1 emissions and certain Scope 2 emissions by 2035 as well as a goal to reduce certain Scope 3 emissions by 20% to 30% by 2035 from a 2021 baseline. 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 12 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 emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from any future administrations to further reduce GHG emissions. For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction 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 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. 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, and the EPA published final, new regulations targeting reductions in methane emissions on March 8, 2024, which may increase costs related to production, transmission and storage of natural gas. CenterPoint Energy’s net zero emissions goals are aligned with Indiana Electric’s generation transition plan and are expected to position Indiana Electric to comply with anticipated 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. For example, Minnesota has enacted the Natural Gas Innovation Act that seeks to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions. Further, certain local government bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by certain specified dates. For example, Minneapolis has adopted carbon emission reduction goals in an effort to decrease reliance on natural gas. Additionally, cities in Minnesota within CenterPoint Energy’s Natural Gas operational footprint are considering initiatives to eliminate natural gas use in buildings and focus on electrification. Also, Minnesota cities may consider seeking legislative authority for the ability to enact voluntary enhanced energy standards for all development projects. These initiatives could have a significant impact on CenterPoint Energy and its operations, and this impact could increase if other cities and jurisdictions in its service area enact similar initiatives. 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. On March 6, 2024, the SEC adopted final rules that require the Registrants to disclose certain climate-related information in registration statements and annual reports. Litigation challenging the new 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 April 4, 2024, the SEC announced that it is voluntarily delaying the implementation of the climate disclosure regulations while the U.S. Court of Appeals considers the litigation. While a majority of the reporting requirements would have been applicable to the Registrants in the fiscal year beginning in 2025, with the addition of assurance reporting for GHG inventories starting in 2029 for large accelerated filers, as of April 12, 2024, the effective date of the final rules has been delayed indefinitely and the SEC has indicated that it will publish a document in the Federal Register at the conclusion of the stay addressing a new effective date for the final rules. On February 11, 2025, the SEC notified the U.S. Court of Appeals of a statement issued by the SEC’s Acting Chairman regarding, among other things, the fact that the majority of current SEC Commissioners had previously voted against adopting the rules, and requested that the U.S. Court of Appeals not schedule the case for argument to provide time for the SEC to deliberate and determine the appropriate next steps in the cases. The Registrants continue to evaluate the impact of the final rules on their respective consolidated financial statements and related disclosures. Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain. 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. 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 net zero and GHG emissions 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. 13 For further information on climate change trends and uncertainties, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters — Climate Change Trends and Uncertainties” in Item 7 of Part II of this report. 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 In April 2020 the EPA proposed a new set of rules that sought to clarify the Clean Water Act’s jurisdiction over “waters of the United States,” but that set of rules was later vacated by decisions in the U.S. federal district courts in New Mexico and Arizona. On December 30, 2022, the EPA and the U.S. Army Corps of Engineers announced the final “Revised Definition of ‘waters of the United States”’ rule, which was published on January 18, 2023 and became effective on March 20, 2023. However, 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 seeks 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. 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. The Registrants currently anticipate that they will be in compliance with the Supplemental ELG Guidelines at the Culley facility due to previous wastewater treatment upgrades. 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 is currently completing the required ecological studies and anticipates timely compliance at its F.B. Culley facility in 2025. 14 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 Indiana Electric has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. In 2015, the EPA finalized its CCR Rule, which regulates coal ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and the majority of the ash generated by Indiana Electric’s remaining generating units will continue to be beneficially reused. Indiana Electric is required to perform integrity assessments, including ground water monitoring, at its F.B. Culley and A.B. Brown generating stations. The ground water studies were necessary to determine the remaining service life of the ponds and whether a pond must be retrofitted with liners or closed in place. Groundwater monitoring indicates potential groundwater impacts adjacent to Indiana Electric’s ash impoundments, and further analysis is ongoing. The CCR Rule required companies to complete location restriction determinations by October 18, 2018. Indiana Electric completed its evaluation and determined that one F.B. Culley pond (Culley East) and the A.B. Brown pond failed the aquifer placement location restriction. As a result of this failure, Indiana Electric was required to cease disposal of new ash in the ponds and commence closure of the ponds by April 11, 2021. Indiana Electric filed timely requests for extensions available under the CCR Rule that would allow Indiana Electric to continue to use the ponds through October 15, 2023. On January 22, 2021, Indiana Electric received letters from the EPA for both the F.B. Culley and A.B. Brown facilities that determined Indiana Electric’s extension submittals complete and extended the compliance deadline of April 11, 2021 until the EPA issues a final decision on the extension requests. On October 5, 2022, SIGECO received a proposed conditional approval of its extension request for the A.B. Brown facility. Both the Culley East and A.B. Brown facility have been taken out of service in a timely manner per the commitments made to the EPA in the extension requests filed for both ponds. The Culley West pond was closed under CCR provisions applicable to inactive ponds, and closure activities were completed in December 2020. For further discussion about Indiana Electric’s ash ponds, see Note 14(d) 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(d) 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. 15 Liability for Preexisting Conditions For information about preexisting environmental matters, see Note 14(d) to the consolidated financial statements. HUMAN CAPITAL CenterPoint Energy believes its employees are critical to safely delivering electricity and natural gas across its service territories and seeks to create an open and safe work environment. 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, 2024: Number of Employees Number of Employees Represented by Collective Bargaining Groups Reportable Segment CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC Electric 3,184 2,839 — 1,699 1,511 — Natural Gas 3,656 — 3,390 1,651 — 1,587 Corporate and Other (1) 2,032 — — 135 — — Total 8,872 2,839 3,390 3,485 1,511 1,587 (1) Employees in the Corporate and Other segment provide services to the Electric and Natural Gas segments and the costs of these services have been charged directly to the Electric and Natural Gas 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 3,485 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 recruits qualified employees regardless of race, gender, color, sexual orientation, age, religion, national origin, or physical or mental disability. The talent acquisition team actively promotes CenterPoint Energy on college campuses to create awareness of our offerings to engineering, finance and technical occupations, and maintains relationships with student organizations at many institutions throughout our footprint. CenterPoint Energy takes a strategic approach to attracting, retaining, and developing its workforce. CenterPoint Energy’s strategy combines succession planning along with internal talent development as essential elements of overall workforce development. To support its commitment to delivering electricity and natural gas safely and reliably, CenterPoint Energy focuses on the continuous development of its greatest assets, its employees, to build a sustainable leadership pipeline. To meet the business's 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. CenterPoint Energy has a number of tools for leadership and employee development that expand opportunities available to employees. CenterPoint Energy conducts regular talent discussions, including succession planning with all 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 performance to business needs, drive development planning and contribute to career progression. CenterPoint Energy’s processes and progress are reviewed regularly for continuous improvement. Engagement. CenterPoint Energy is dedicated to advancing an ethical and high performance 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 the Company’s long-term performance. In 2024, CenterPoint Energy’s senior leadership team held quarterly town hall meetings with employees to share key Company updates, with employees across the Company participating in person or via video conference. 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 16 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 10, 2025) Name Age Title Jason P. Wells 47 President and Chief Executive Officer Christopher A. Foster 46 Executive Vice President and Chief Financial Officer Monica Karuturi 46 Executive Vice President and General Counsel Jason M. Ryan 49 Executive Vice President, Regulatory Services and Government Affairs Darin M. Carroll 48 Senior Vice President, Electric Business Richard C. Leger 47 Senior Vice President, Natural Gas Business Jason P. Wells has served as President and Chief Executive Officer of CenterPoint Energy and a member of the Board of Directors of CenterPoint Energy 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. 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. and M.D. Anderson Cancer Center. 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 the Houston Zoo. 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 17 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; he was reappointed by Texas Governor Abbott in 2019 for a term ending in 2025. 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 and on the advisory board of the Strategic AI Program at Houston Christian University. He also serves on the executive committee of the legal committee of the American Gas Association. Darin M. Carroll has served as Senior Vice President, Electric Business of CenterPoint Energy since July 2024. He previously served as Senior Vice President, Natural Gas Business from January 2023 to July 2024; as Senior Vice President, Operations Support from January 2022 to January 2023; and as Vice President, Operations Support from February 2019 to January 2022. Prior to Vectren’s acquisition by CenterPoint Energy, Mr. Carroll served as Director, Operations from February 2014 to February 2019 of Vectren. He earned his bachelor’s degree from the University of Southern Indiana. Mr. Carroll currently serves on the Executive Committee and Board of Directors of the Junior Achievement of Southeast Texas and as a member of the Research Advisory Committee of the Electric Power Research Institute. He has also previously been on the Board of Directors of the American Gas Association, the Southern Gas Association, and the Guardianship Services of Southwestern Indiana, as well as a trustee of the American Gas Foundation. Mr. Carroll has also served as a member of the Indiana Energy Association Gas Operations Committee, Midwest Energy Association Electric Operations Steering Committee, and American Gas Association Field Operations Committee. He earned a bachelor’s degree from the University of Southern Indiana in Evansville, Indiana. Richard C. Leger has served as Senior Vice President, Natural Gas Business of CenterPoint Energy since January 2025. Mr. Leger previously served in various positions of increasing responsibilities at CenterPoint Energy since 2001, including as Interim Senior Vice President, Natural Gas Business from July 2024 to December 2024; as Senior Vice President, Indiana Electric from January 2022 to July 2024; as Vice President of Gas Operations, Indiana and Ohio from February 2019 to January 2022; as Director, District Operations for Little Rock, Arkansas from November 2015 to February 2019; as Director, Regulatory Affairs from August 2011 to November 2015; and as Manager, Sales and Conservation Improvement Program from August 2010 to August 2011. Mr. Leger currently serves as a board member for the American Gas Association, Southern Gas Association, United Way of Southwestern Indiana and Golf Gives Back. He is also a trustee of the American Gas Foundation and a former chair of the Southeast Energy Efficiency Alliance. In addition, Mr. Leger served six years in the Louisiana Army National Guard. He earned two bachelor’s degrees in accounting and marketing from McNeese State University. 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. 18 Risk Factors Affecting Operations Electric Generation, Transmission and Distribution (CenterPoint Energy and Houston Electric) Disruptions at power generation facilities, generation inadequacy or directives issued by regulatory authorities could cause interruptions in Houston Electric’s and Indiana Electric’s ability to provide transmission and distribution services and adversely affect their reputation, 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 power generation facilities, except for its operation of TEEEF. 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 respective independent system operator, ERCOT and MISO, respectively. ERCOT and MISO have and may in the future issue directives requiring members to implement controlled outages as a result of an emergency or reliability issues, and 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 shed load and which customers experienced outages and the duration of those outages. As a result, claims and lawsuits could be filed against Houston Electric and Indiana Electric for personal injury, property damage or other damage or loss as a result of their respective Load Shed planning, preparation, implementation, and decisions in order to meet the directives of ERCOT and MISO, respectively. For example, in February 2021, the ERCOT regulated Texas electric system experienced extreme winter weather conditions and an unprecedented power generation shortage. 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. 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, Houston Electric’s or Indiana Electric’s transmission and distribution services may be diminished or interrupted. 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, and our reputation, financial condition, results of operations and cash flows could be adversely affected. Additionally, Indiana Electric’s generating facilities and the generating facilities that supply the power transmitted by Houston Electric and Indiana Electric are subject to operational risks that have and may in the future result in unscheduled plant outages, unanticipated operation and maintenance expenses and increased purchase power costs. For example, in June 2022, Culley 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 operations, financial condition, results of operations and cash flows. Further, Indiana Electric is party to a number of PPAs with third parties. Indiana Electric’s power generation may be disrupted or otherwise insufficient if third parties do not deliver required power under our PPAs. These operational risks can arise from circumstances such as facility shutdowns or malfunctions due to equipment failure or operator 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 delivery of electricity; inability to comply with regulatory or permit requirements; labor disputes; or natural disasters, all of which could adversely affect Indiana Electric’s and Houston Electric’s businesses. Further, Indiana Electric currently relies on coal for a portion of its generation capacity. Indiana Electric purchases the majority 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 financial condition, results of operations and cash flows. In 2021 and part of 2022, Indiana Electric experienced coal supply shortages due to labor shortages that the coal industry experienced. While the coal supply shortage that Indiana Electric experienced did not impact its ability to deliver electricity to its customers, labor shortages as well as supply shortages in the future, whether caused by insufficient supply or supplier bankruptcy or other regulatory and supply issues in the mining industry, may lead to increased cost and have an adverse impact on our operations, financial condition, results of operations and cash flows. See “— Disruptions to the global supply...” As Indiana Electric continues its generation transition and more renewable energy sources come online, Indiana Electric’s generating facilities may experience unanticipated disruptions as a result of renewable supply shortages, including, but not limited to, adverse weather such as cloudy or windless days. Additionally, such disruptions could adversely affect its ability to deliver electricity to its customers and adversely impact Indiana Electric’s financial condition, results of operations and cash flows. The operations of Houston Electric and Indiana Electric are subject to the usual hazards associated with high-voltage 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 19 interruptions, 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 damage to solar panels, and environmental damage, and may result in suspension of operations, disruption of service to customers, and the imposition of civil or criminal penalties. For example, Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system, resulting in a substantial number of its customers (peaking at more than 2.1 million customers out of 2.8 million customers) being without power, many for extended periods of time. Houston Electric and Indiana Electric maintain property and casualty insurance but are not fully insured against all potential hazards incident to their businesses. Indiana Electric’s execution of its generation transition plan, including its IRP, 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 perform 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 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 have demonstrated Indiana Electric can most cost effectively serve its customers by transitioning its generation fleet to a wider mix of resources, including renewables. For example, Indiana Electric’s 2019/2020 IRP identified a preferred portfolio that retires 730 MW of coal-fired generation facilities and replaces these resources with a mix of generating resources composed primarily of renewables, including solar, wind, and solar with storage, supported by dispatchable natural gas combustion turbines including a pipeline to serve such natural gas generation. Indiana Electric is continuing its plan to transition generation resources away from coal-fired generation to a more sustainable portfolio of resources, including renewables. 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 DSM plans to help ensure 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, Indiana Electric may not be able to implement its generation transition plan in a timely manner or at all. Additionally, projected changes in how renewable and battery storage resources are accredited to meet MISO’s planning reserve margin requirement make it less economic to pursue these resources in the future. 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. 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 net zero and GHG emissions reduction goals, its goal to exit the coal plants that Indiana Electric operates, its growth strategy, achieve its financial goals, and otherwise impact 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, the ability to procure resources needed to build at a reasonable cost, scarcity of resources and labor, ability to appropriately estimate costs of new generation, the effects of potential construction delays, project scope changes, and cost overruns and the ability to meet capacity requirements. For example, in January 2025, President Trump signed executive orders that, among other things, temporarily halted certain federal government agencies from issuing approvals, permits and loans for onshore wind projects pending the completion of certain assessments and reviews, and pause the disbursement of funds appropriated through the IRA and the Infrastructure Investments and Jobs Act. As an additional example, the developers of a 130 MW Pike County Solar project informed Indiana Electric that, due to delays in the MISO interconnection queue and inflationary pressures, costs exceeded the agreed upon levels in the BTA. After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing. As a result, on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate the BTA. Further, tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could adversely affect our ability to develop and construct new generation, including our ability to procure the resources needed for such development and construction. For example, on February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. For additional information, see “— Disruptions to the global supply...” Furthermore, we have begun to acquire and/or develop additional solar and wind facilities as part of our capital plan. 20 However, we have not yet entered into definitive agreements with developers for the acquisition and/or development of all of the additional projects, and we face significant competition with other bidders for a limited number of such generation facilities that developers plan to construct and for solar panels. For additional information, see “— Increases in the cost or reduction in supply ...” The number of available projects is further limited by the MISO interconnection queue due to potential interconnection costs that may render projects infeasible. As a result, suitable generation facility project candidates or resources necessary to construct such projects may not be available on terms and conditions we find acceptable, or the expected benefits of a completed facility may not be realized fully or at all, or may not be realized in the anticipated timeframe. If Indiana Electric was unable to meet its generation needs as a result of project delays or cancellations, 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 operations, 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 future growth, 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 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, 2024, 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 pandemic 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, 2024 was $263 million. Approximately 37% and 21% 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 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. We are currently recording the amounts owed by these REPs as a regulatory asset for bad debt expenses, which is subject to a reasonableness review by the PUCT in our current base rate case. As of December 31, 2024 and 2023, as authorized by the PUCT, CenterPoint Energy and Houston Electric recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ defaults on their obligations to pay delivery charges to Houston Electric, net of collateral. There is no guarantee that we will be able to recover any or all of the regulatory asset in our next base rate case. See “— Rate regulation of 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. Houston Electric’s use of TEEEF is subject to various risks, including failure to obtain and deploy sufficient TEEEF resources, 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, effective September 1, 2021, that allows TDUs, such as Houston Electric, to lease and temporarily operate back-up generation resources 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 entered into two leases for large 27 MW to 32 MW TEEEF (temporary generation) and medium five MW TEEEF. In 2023, the Texas legislature amended the law to allow wider use of TEEEF, including in response to a significant power outage affecting a significant number of distribution customers that has lasted or is expected to last for at least six hours, affecting distribution customers in an area for 21 which the governor has issued a disaster or emergency declaration, affecting distribution customers served by a radial transmission or distribution facility that creates a risk to public health or safety and that has lasted or is expected to last for at least 12 hours, or creating a risk to public health or safety because it affects a critical infrastructure facility that serves the public. Pursuant to the amendment, the Texas Division of Emergency Management, ERCOT, or the executive director of the PUCT may also determine that a power outage other than one described above is a significant power outage for purposes of use of TEEEF. In response to this amendment, Houston Electric entered into additional leases for small 200-kilowatt to one MW TEEEF. If Houston Electric is unable to deploy a sufficient number of TEEEF resources in time to respond to a particular event (including as a result of re-leasing TEEEF to third parties or similar transactions, as described further below, or if leasing certain TEEEF becomes prohibited by law, 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 as intended; 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. For example, various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl and the efforts made by Houston Electric to prepare for, and respond to, this event, including, among other things, Houston Electric’s procurement of TEEEF. Texas Lieutenant Governor Patrick has publicly urged the PUCT to hold Houston Electric, rather than ratepayers, responsible for paying approximately $800 million, which, as detailed below, was the amount the PUCT had previously approved Houston Electric to recover from ratepayers relating to Houston Electric’s leasing of TEEEF. Additionally, legislation has been proposed in Texas to, among other things, require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl, including with respect to its TEEEF resources. There are significant uncertainties around these inquiries, investigations and proposed legislation and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed; whether changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom; or whether it will be viable for Houston Electric to continue leasing TEEEF. If it is no longer viable for Houston Electric to lease TEEEF at the same or similar scale at which it currently leases such resources and ERCOT issues a directive requiring TDUs to Load Shed or other 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. 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. For further information, see “— Hurricane Beryl caused severe disruptions...,” “— We are involved in numerous legal proceedings...” and “— Our insurance coverage may not...” As noted above, the legislation allowing TDUs to lease and operate TEEEF 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. 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. In April 2023, the PUCT approved revenue recovery of $39 million of TEEEF costs incurred in 2021, and in October 2023, an agreement with intervenors was reached with respect to Houston Electric’s second TEEEF filing for revenue recovery of $153 million ($114 million incremental to the prior filing) of TEEEF costs incurred through December 31, 2022, and the agreement was approved by PUCT in February 2024. On September 11, 2024, the TCA filed a complaint with the PUCT requesting that the PUCT modify its rulings with respect to its prior decisions related to the TEEEF filings made in 2022 and 2023. Specifically, TCA requested that the PUCT end cost recovery and return on investment on all the large 32 MW and 5 MW TEEEF units approved in docket 53442. On October 2, 2024, Houston Electric filed a response to the TCA complaint and requested that the complaint be dismissed due to the principles of res judicata and collateral estoppel. On October 8, 2024, TCA supplemented its complaint, and on October 9, 2024, PUCT staff filed a statement of position stating that Houston Electric’s response provided a strong argument for dismissal of the complaint, but also stating that it would be prudent to have a thorough legal argument from TCA. On October 10, 2024, PUCT issued Order No. 2 finding the TCA complaint insufficient and 22 requiring supplemental information or amendment from TCA by October 24, 2024; TCA filed supplemental information on October 24, 2024 and indicated it was prepared to submit supplemental evidence, but only in camera. On October 25, 2024, PUCT issued Order No. 3 in which TCA’s request for confidentiality with regard to its membership information was appropriate; Order No. 3 entered a protective order to govern the use of confidential materials in this docket. On November 13, 2024 TCA responded to Order No. 3 and repeated its offer to submit membership information in camera which the ALJ considered to be a motion for rehearing. On November 14, 2024, PUCT issued Order No. 4 which denied the motion to reconsider and extended the prior deadline to file supplemental information to December 13, 2024. On December 16, 2024, PUCT issued Order No. 5 granting waiver of the requirement for informal disposition and soliciting PUCT staff recommendation by January 16, 2025. On January 16, 2025, PUCT staff filed a supplemental recommendation recommending that TCA had not met the requirement to first present its complaint to the City of Houston prior to presenting it to the PUCT. On January 17, 2025 the case was abated until February 28, 2025 to enable TCA to present its complaint to the City of Houston. 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, on August 28, 2024, Houston Electric announced its proposal to forego approximately $110 million of profit related to its storm hardening and TEEEF efforts, which would be represented in part by Houston Electric not filing, beginning in 2028, for approximately $40 million in anticipated equity profit associated with Load Shed orientated TEEEF leased by Houston Electric through the remaining regulatory life of the leases in 2032 as new dispatchable generation is likely to come online in the state of Texas as a result of the Texas Energy Fund. Additionally, as noted above, legislation has been proposed in Texas to disallow recovery of costs associated with such disallowed leases and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. If Houston Electric is unable to recover or must return any or certain of its TEEEF costs our financial condition, results of operations and cash flows may be adversely affected. For further information, see “— Rate regulation of Registrants’ Electric...”, “— Our insurance coverage may not...” and “— We are subject to operational...” On December 19, 2024, Houston Electric announced a proposal to release Houston Electric’s 15 large 27 MW to 32 MW TEEEF units to the San Antonio area prior to the summer of 2025. The proposal is intended to help ERCOT address a potential energy shortfall and Load Shed risk and to provide additional electric generation capacity to support growing energy demand in the greater San Antonio region. Under the proposal, Houston Electric would not receive revenue or profit from ERCOT and would also not charge Houston-area customers for these TEEEF units for the period they are in San Antonio serving ERCOT, which is currently expected to be for a period of up to two years. Houston Electric anticipates receiving revenues from one or more future transactions after the period the units are released to temporarily serve the energy need in the San Antonio area, and would therefore plan to continue to not charge customers for these units for future periods. As of the date of the filing of this Form 10-K, Houston Electric estimates that the value of the TEEEF units to be removed from the rate base as a result of the aforementioned proposal will be approximately $375 million. The proposal has not been finalized and is subject to the negotiation of definitive documentation among the relevant parties, as well as being subject to the approval of ERCOT and other stakeholders. It is not certain that mutually agreeable definitive documentation will be entered into at all or that all approvals will be obtained. Assuming that a definitive agreement is executed and that all necessary transaction approvals are received, this proposal is expected to result in a reduction to Houston Electric’s customers’ bills that Houston Electric would propose to the PUCT in the spring of 2025. Nevertheless, there can be no assurance that Houston Electric will be able to finalize the proposal. If the proposal is not finalized, it may have an adverse effect on our reputation and customer satisfaction, as well as potentially lead to negative consequences from regulatory authorities or other public authorities. Additionally, suitable future transactions may not be available on terms and conditions we find acceptable, or the expected benefits of Houston Electric’s proposal to release its 15 large 27 MW to 32 MW TEEEF units to San Antonio 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, reputation, 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 own service territory, and if ERCOT issues a directive requiring TDUs to Load Shed or other 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. Hurricane Beryl caused severe disruptions to our operations, customers and markets in certain of our service territories and could have a material adverse impact on our financial condition, results of operations, cash flows and liquidity. In July 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain, which impacted our operations, customers and personnel in our Texas Gulf Coast markets. Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system, resulting in a substantial number of its customers (peaking at more than 2.1 million customers out of 2.8 million customers) being without power, many for extended periods of time. 23 The total cost for the restoration of Houston Electric’s electric delivery facilities as a result of Hurricane Beryl is currently estimated to be $1.1 billion, excluding carrying costs, but such estimate is preliminary and restoration costs could vary from that estimate. Houston Electric believes it is entitled to recover prudently incurred storm restoration costs in accordance with applicable regulatory and legal principles. However, neither the amount nor timing of the recovery is certain. Houston Electric’s failure to recover costs incurred as a result of Hurricane Beryl could adversely affect our liquidity, cash flows and financial condition. Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl and the efforts made by Houston Electric to prepare for, and respond to, this event, including, among other things, the electric service outage issues. Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl. Certain government officials have also made public statements calling for, and proposed legislation seeking to require, Houston Electric to pay certain costs related to TEEEF. For more information regarding TEEEF-related risks, see “— Houston Electric’s use of TEEEF ...” There are significant uncertainties around these inquiries and investigations and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom. If these or other inquiries, investigations or reviews ultimately result in changes to Houston Electric’s system, service territories, operations and/or regulatory treatment, such changes could have an adverse impact on our business, results of operations, cash flows and financial condition. Further, on January 22, 2025, a putative shareholder of CenterPoint Energy, Donel Davidson, filed a derivative petition in Harris County District Court, Texas, alleging breach of fiduciary duty and unjust enrichment on behalf of CenterPoint Energy against certain of its current and former directors and officers citing, in part, the topics of these inquiries and investigations. The action seeks to recover damages and other relief from the defendants on behalf of CenterPoint Energy. Additionally, on February 12, 2025, a second putative shareholder of CenterPoint Energy made a demand on the Board to investigate the same basic allegations raised in the derivative petition filed by Donel Davidson. CenterPoint Energy and Houston Electric are subject to current and potential future litigation and claims arising out of Hurricane Beryl, which litigation and claims could include allegations of, among other things, personal injury, property damage, various economic losses in connection with loss of power, unlawful business practices, and others. As of December 31, 2024, five lawsuits had been filed against CenterPoint Energy and/or Houston Electric in the District Courts of Harris County, including three putative class actions claiming losses due to power outages following Hurricane Beryl. Each class action seeks damages in excess of $100 million for, among other things, business interruption, property damage and loss, cost of repair, loss of use and market value, lost income, nuisance, extreme mental anguish and/or punitive damages. CenterPoint Energy and its subsidiaries have general and excess liability insurance policies that provide coverage for third party bodily injury and property damage claims. Given the nature of some allegations, it is possible that the insurers could dispute coverage for some types of claims or damages that may be alleged by plaintiffs, and CenterPoint Energy has received from two insurers denial of indemnity coverage in the putative class actions based on the failure to supply exclusion. Those insurers have also reserved their rights with respect to coverage in those actions. CenterPoint Energy and Houston Electric intend to continue to pursue all available insurance coverage for all of these matters. While CenterPoint Energy and Houston Electric intend to vigorously defend themselves against the lawsuits, final resolution of these matters, or any potential future claims or liabilities, may require expenditures that may be in excess of established insurance or reserves and may have a material adverse effect on the Registrants’ financial condition, results of operation, cash flows and liquidity. Increases in the cost or reduction in supply of solar energy system components due to tariffs or trade restrictions imposed by the U.S. government may have an adverse effect on our business, financial condition and results of operations. China is a major producer of solar panels and other solar products. Certain solar cells, modules, laminates and panels from China are subject to various antidumping and countervailing duty rates, depending on the exporter supplying the product, imposed by the U.S. government as a result of determinations the United States was materially injured as a result of such imports being sold at less than fair value and subsidized by the Chinese government. Additionally, in March 2022, the DOC announced it would initiate an investigation into whether imports of solar cells and panels produced in Cambodia, Malaysia, Thailand and Vietnam are circumventing U.S. rules and laws, such as antidumping and countervailing duty rates, which impose a tariff on imports of solar cells and panels manufactured in China. On August 18, 2023, the DOC announced its final determination that five of the eight companies investigated were attempting to bypass U.S. duties by doing minor processing in Southeast Asian countries before shipment to the United States. On May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam. On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates. A final 24 determination is expected in the first quarter of 2025. On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. A final determination is expected in the second quarter of 2025. In addition, in December 2021, the United States enacted the Uyghur Forced Labor Prevention Act, which bans goods from China’s Xinjiang region due to the use of forced labor. Continuing tensions between the United States and China may lead to restrictions in trade between the two countries or new legislation, tariffs or bans. Furthermore, President Trump has expressed a desire to impose substantial new or increased tariffs on foreign imports into the United States, and in February 2025, President Trump imposed tariffs on several countries (the effectiveness of tariffs imposed on certain countries was subsequently delayed until March 2025) and certain imports into the United States. These tariffs, as well as new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could further negatively impact the supply of solar panels. In addition to supply reductions, these or similar duties, legislation and other measures have and may in the future also put upward pressure on prices of these solar energy products, which may reduce our ability to acquire these items in a timely and cost-efficient manner. If we or the developers we are working with are unable to secure such solar energy products in a timely and cost-efficient manner, we may be required to seek additional regulatory review and approvals and/or be forced to delay, downsize and/or cancel solar projects, in which case we may not be able to fully execute on our ten-year capital plan or achieve our net zero and GHG emissions reduction goals. We have experienced project delays due to developers of our projects being unable to acquire solar panels due to supply chain constraints. Additionally, delays or cancellations by developers of third-party solar power facilities expected to interconnect with CenterPoint Energy’s and Houston Electric’s system may have adverse impacts, such as delayed or reduced potential future revenues. We cannot predict what additional actions the U.S. government may adopt with respect to tariffs, trade agreements or other trade regulations in the future or what actions may be taken by other countries in retaliation for such measures. If the DOC imposes tariffs on solar panels as a result of its findings or other additional measures are imposed, our business, financial condition and results of operations may be adversely affected. The occurrence of extreme weather events, including winter storms and record hot temperatures, or other causes could lead to additional reforms to the Texas electric market, some measure of which, if implemented, could have an adverse impact on Houston Electric. 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 power generation facilities and TDUs (like Houston Electric), have adopted sufficient winterization standards and protection. Houston Electric believes it is in compliance with the requirements applicable to it. 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 results of operations. Any potential decreases in customer usage due to higher electricity prices charged by REPs may not result in increased base rates charged by Houston Electric for its services until its next general base rate proceeding. For further information on Houston Electric’s regulatory proceedings, see “— Rate regulation of Registrants’ Electric...” In addition, the PUCT and ERCOT continue to review, among other things, the appropriate reliability standard and market design for the Texas electric market. There are uncertainties whether any further changes will result from these discussions or other efforts. If there are changes to how the Texas electric market is structured or regulated, including as a result of Hurricane Beryl and related investigations, such changes could have an adverse impact on Houston Electric’s business, financial condition and results of operations. See Note 7 to the consolidated financial statements for further information. Natural Gas (CenterPoint Energy and CERC) Access to natural gas supplies and pipeline transmission and storage capacity are essential components of reliable service for Natural Gas’ customers. Natural Gas depends 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 its customers’ needs, all of which are critical to system reliability. Substantially all of Natural Gas’ natural gas supply is purchased on intrastate and interstate pipelines. If Natural Gas is unable to secure an independent natural gas supply of its own or if third-party service providers fail to timely deliver natural gas to meet Natural Gas’ requirements, the resulting decrease in natural gas supply in Natural Gas’ service territories could have an adverse effect on its financial condition, results of operations, cash flows and reputation. 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 adversely affect Natural Gas’ businesses. Further, to the extent that Natural Gas’ natural gas requirements cannot be met 25 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 Natural Gas’ operations could be negatively affected. Natural Gas is subject to fluctuations in natural gas prices, which could affect the ability of its suppliers and customers to meet their obligations or may impact its operations, which could adversely affect CERC’s financial condition, results of operations and cash flows. Natural Gas is subject to risk associated with changes in the price of natural gas. Significant increases in natural gas prices, such as those experienced during the February 2021 Winter Storm Event, might affect Natural Gas’ 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 Natural Gas operates, thereby resulting in decreased sales and revenues and (ii) increase the risk that Natural Gas’ 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. Natural Gas must compete with alternate energy sources, which could result in less natural gas delivered and have an adverse impact on CenterPoint Energy’s and CERC’s financial condition, results of operations and cash flows. Natural Gas competes 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 Natural Gas 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 Natural Gas’ 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 Natural Gas as a result of competition with alternate energy sources may have an adverse impact on CenterPoint Energy and CERC’s financial condition, results of operations and cash flows. Risk Factors Affecting Regulatory, Environmental and Legal Risks Rate regulation of 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. Houston Electric and CERC, with respect to its Ohio gas territory, each filed rate cases during 2024. 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 2019 Houston Electric general rate case, Houston Electric filed a base rate case seeking approval for revenue increases of approximately $194 million and a 10.4% ROE, but after entering into a Stipulation and Settlement Agreement filed with the PUCT, Houston Electric received an overall revenue requirement increase of approximately $13 million and a 9.4% ROE. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their 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 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, like those experienced in 2022, 2023 and early 2024. 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, 26 RCRA, RRA, RSP, 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 its 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 securitization bonds in order to recover certain costs, including costs incurred as a result of severe weather or to recover stranded asset costs. The issuance of these securitization bonds may be delayed. If the issuance of 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 financial condition, results of operations and cash flows. Inherent in the regulatory process is some level of risk 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. From time to time, these reviews and investigations 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 or rulemakings, 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. For example, legislation has been proposed in Texas to require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. There can be no assurances 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 more information regarding TEEEF-related risks, see “— Houston Electric’s use of TEEEF ...” Additionally, changes to the rate case or interim adjustment mechanisms could result in an increase in regulatory lag or otherwise impact the Registrants’ ability to recover their costs in a timely manner. Additionally, 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 in the states in which we operate. To the extent the regulatory process does not allow the Registrants to make a full and timely recovery of appropriate costs, their 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, which 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 face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation, tariffs, 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 position, results of operation or cash flows. 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 generation, transmission and distribution 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. 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 financial condition could be impacted. Any failure to negotiate successful project development agreements for new facilities with third parties could also have adverse effects. Additionally, our projects 27 have faced and may in the future face opposition from individuals, community organizations, environmental and other activist groups, and other public-interest entities. 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’ financial results. For further information, see “— Our insurance coverage may not...” Customers’, investors’, legislators’, regulators’ and creditors’ opinions of us are affected by many factors, including actual or perceived system reliability, the speed of our response to service interruptions, rates, 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, results of operations, cash flows and financial condition. Our results are influenced by the expectations of our customers, investors, legislators, regulators and creditors. Those expectations are based, in part, on the actual or perceived reliability and affordability of our utility services. The speed with which we are able to respond effectively 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. For example, various federal, state and local governmental and regulatory agencies and other entities have called for or are conducting 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. CenterPoint Energy and Houston Electric are also subject to current and potential future litigation and claims arising out of Hurricane Beryl. For more information regarding Hurricane Beryl-related risks, see “— Hurricane Beryl caused severe disruptions...” The level of rates, the timing and magnitude of rate increases, and the volatility of rates can also affect customer satisfaction. Our ability to successfully execute our capital plan may also affect customers’, investors’, legislators’, regulators’ and creditors’ opinions and actions. Opinions of us can also be affected by media coverage, including social media, which may include information, whether factual or not, that damages our brand and reputation. If customers, investors, legislators, regulators or creditors 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 or increased regulatory oversight, negative effects on our access to, and the cost of, capital, increased litigation and negative public perception. The foregoing may have adverse effects on our business, results of operations, cash flow and financial condition. 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 28 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. The trend in environmental regulation in previous years has been to place more restrictions and limitations on activities that may impact the environment. On April 22, 2021, the United States announced new goals of 50% reduction of economy-wide GHG emissions and 100% carbon-free electricity by 2035, which formed the basis of the United States’ commitments announced in Glasgow, Scotland. These renewed climate commitments coming out of the 2021 United Nations Climate Change Conference held in Glasgow and certain executive orders resulted in the development of additional regulations and changes to existing regulations. For example, in May 2023, the EPA proposed regulations setting new GHG emission reduction targets for coal and gas-fired electric generating units that could potentially require additional operating costs or operating restrictions related to operation of Indiana Electric’s natural-gas fired units. On April 25, 2024, the EPA released its New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, Reconstructed Fossil Fuel-Fired Units; Emission Guidelines for Greenhouse Gas Emissions From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule. CenterPoint Energy is currently reviewing this rule. 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 its operations or that would have the effect of reducing the consumption of natural gas or electricity or prevent the use of certain fuel types. Nevertheless, on January 20, 2025, President Trump signed an executive order to withdraw the United States from the Paris Agreement, marking a significant shift in U.S. climate policy. Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. Additionally, in January 2025, President Trump signed executive orders that, among other things, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, and call upon the EPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act and issue guidance on the “social cost of carbon” to consider whether such metric should be eliminated. 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 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 decrease in demand for our services. For further discussion, see “Business—Environmental Matters” in Item 1 and “ —Natural Gas 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 CenterPoint Energy’s and CERC’s 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 Natural Gas 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 Natural Gas’ 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 results of operations. Further, 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 January 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. 29 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 GHG emissions reduction goals. In September 2021, CenterPoint Energy announced its net zero emission goals for Scope 1 and certain Scope 2 emissions by 2035 and a 20-30% reduction in certain Scope 3 emissions by 2035 as compared to 2021 levels. CenterPoint Energy’s analysis and plan for execution requires it to make a number of assumptions. These goals and underlying assumptions involve risks and uncertainties and are not guarantees. Should one or more of CenterPoint Energy’s underlying assumptions require updating, its actual results and ability to achieve its net zero and GHG emissions reduction goals by 2035 could differ materially from its expectations. Certain of the assumptions that could impact CenterPoint Energy’s ability to meet its net zero and GHG emissions reduction goals and the timing thereof include, but are not limited to: GHG emission levels, service territory size and capacity needs remaining in line with Company expectations, including with respect to demand for our services and in relation to the announced sale of CenterPoint Energy’s Louisiana and Mississippi natural gas LDC businesses; the ability to appropriately estimate and effectively manage business opportunities from new customers and load growth resulting from, among other things, expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics in our service territories; regulatory approvals related to Indiana Electric’s generation transition plan and our ability to obtain such approvals; interconnection delays in the footprints of regional transmission organizations and/or interconnection costs; impacts on affordability of customer rates; customer demand for GHG emission free or lower GHG emissions energy; impacts of future regulations or legislation, including those related to the environment and tax (including changes to the renewable energy tax credits enacted in the IRA); 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 of energy generation technologies, such as wind and solar, natural gas and storage solutions; adoption of alternative energy by the public, including adoption of electric vehicles; rate of technology innovation with regards to alternative energy resources; CenterPoint Energy’s ability to implement its modernization plans for its pipelines and facilities; the ability to complete and timely implement generation alternatives, such as solar and wind generation, to Indiana Electric’s coal generation and retirement or fuel conversion dates of Indiana Electric’s coal facilities by 2035; 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 tariffs, legislation, bans, retaliatory trade measures taken against the United States or related governmental action) 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 may face increased scrutiny from investors, governmental authorities and other stakeholders related to our sustainability and human capital management activities, including 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. If our sustainability practices do not align with investor or other stakeholder expectations and standards, which continue to evolve, vary, and sometimes conflict, our reputation, our ability to attract or retain employees, and our attractiveness as an investment or business partner could be negatively affected. 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 private 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 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 financial condition and results of operations. We are subject to regulatory compliance and proceedings, which could result in higher costs for system improvements, as well as fines or other sanctions. 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 30 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 ReliabilityFirst 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. While Houston Electric and Indiana Electric have received minor 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 sanctions, including potential 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. The 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. The 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, and we systematically monitor and renew infrastructure over time; however, CERC has received minor fines in the past for noncompliance, and a significant incident or material finding of non-compliance in the future could result in penalties and higher costs of operations. Our businesses may be adversely affected by the intentional misconduct of our employees. 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 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 Code and other policies. If such intentional misconduct by employees 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 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 employee misconduct, 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 may lead to higher prices for goods and services and impact our operations, which could have an adverse impact on our ability to execute our capital plan and on our financial condition, results of operations and cash flows. The global supply chain has experienced disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and policy instability, import tariffs and trade agreements, the COVID-19 pandemic, labor shortages, resource availability, long lead time, 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, as well as increased prices, and we may continue to experience this in the future. For example, President Trump has expressed a desire to impose substantial new or increased tariffs and, in February 2025, imposed tariffs on several countries (the effectiveness of tariffs imposed on certain countries was subsequently delayed until March 2025) and certain imports into the United States. On February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. These tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could increase or cause volatility in the cost of and negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and capital plan, lead to a scarcity of resources and labor necessary for our business and capital plan, further extend lead time or otherwise negatively impact the supply chain. Examples of materials necessary for the transmission and distribution of power we and our industry have experienced difficulties in procuring include transformers, wires, cables, meters, poles and solar panels. If the supply chain disruption persists or worsens, we may experience difficulties in procuring these resources and others necessary to operate our businesses in the future. As a result, we may not be able to procure the resources, including labor, needed to timely perform storm restoration activities, fully execute on our ten-year capital plan and/ 31 or achieve our net zero emission and GHG emissions reduction goals. Moreover, inflation and high interest rates have contributed to increased prices for materials and services experienced by us and other companies in our industry and, if such conditions continue, they may have adverse effects on our business, results of operations, cash flow and financial condition. Even if we are able to procure the necessary resources, we might not be able to do so at a reasonable cost or in a timely manner which could result in project cancellations or scope changes, delays, cost overruns and under-recovery of costs. If we are unable to fully execute on capital plans, our 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 or refinance outstanding indebtedness could be limited. Our businesses are capital intensive, and we rely on various sources to finance our capital expenditures. 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. 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. As of December 31, 2024, CenterPoint Energy had $21 billion of outstanding indebtedness on a consolidated basis, which included $324 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. If we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures, including our ten-year capital plan (which has increased to nearly $47.5 billion through 2030), or refinance our outstanding indebtedness could be limited. Our future financing activities may be significantly affected by, among other things: • general economic and capital market conditions, including inflation; • credit availability from financial institutions and other lenders; • investor confidence in us 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; • timing of future securitizations by jurisdictions in which we operate; and • provisions of relevant securities laws. The Registrants’ current credit ratings and any changes in credit ratings in 2024 and to date in 2025 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 financial condition, results of operations and cash flows could be adversely affected. 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, as a result of the Restructuring, 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 32 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, as part of the agreement resulting from Houston Electric’s 2019 base rate case, Houston Electric filed a base rate proceeding in 2024. Further ring-fencing measures could be imposed on Houston Electric in the future through legislation or PUCT rules or orders. While current ring-fencing measures have not impacted Houston Electric’s ability to pay dividends to CenterPoint Energy, the imposition of any additional measures impacting CenterPoint Energy’s ability to receive dividends from Houston Electric could adversely affect CenterPoint Energy’s cash flows, credit quality, financial condition and results of operations. Any such adverse effect on CenterPoint Energy could also adversely affect Houston Electric’s and/or CERC’s cash flows, credit quality, financial condition and results of operations 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 obligations pursuant to these parental guarantees to date but may be required to do so in the future. For further information, see Note 14(c) 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, 2024, 2023, and 2022. 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 financial condition and results of operations. If CenterPoint Energy redeems the ZENS prior to their maturity in 2029, its ultimate tax liability and redemption payments would 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, 2024. 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 per ZENS $9 million in the aggregate, or $0.62 per ZENS, as of December 31, 2024, 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. 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, 2024, deferred taxes of approximately $802 million would have been payable in 2024, based on 2024 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2024 to fund the aggregate 33 redemption amount, capital gains taxes of approximately $84 million would have been payable in 2024. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows and liquidity. 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 disposed when ZENS are exchanged and ZENS-Related Securities shares are sold. 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 financial condition, results of operations and cash flows. Our 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 2021, we announced our strategic goals for CenterPoint Energy, including our ten-year capital plan, and net zero and GHG emissions reduction goals. 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 ten-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 Louisiana and Mississippi natural gas LDC businesses, Houston Electric’s proposed release of its 15 large 27 MW to 32 MW TEEEF units to the San Antonio area and other potential future subleasing of TEEEF and our completed sale of our Energy Systems Group business, 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 similar 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 similar 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; and • we may not receive regulatory approvals necessary to complete an acquisition, disposition or similar transaction in a timely manner or at all. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. 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 otherwise not consummated. Changing demographics, poor investment performance of pension plan assets and other factors adversely affecting the calculation of pension liabilities could unfavorably impact our financial condition, results of operations and liquidity. 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 34 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. In 2023 and 2022, CenterPoint Energy had a settlement expense for its pension plans as a result of an increase in eligible employee retirements and pension plan distributions. 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 financial condition, results of operations and liquidity. 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, and the IRA 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, limiting interest deductions, altering the expensing of capital expenditures, enacting a new CAMT, and expanding federal tax credits for cleaner energy production. Based on guidance available as of December 31, 2024, the Registrants will be subject to the CAMT included in the IRA. The interpretive guidance issued by the IRS and state tax authorities 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 retail regulatory treatment of the expanded tax credits and CAMT could impact the Registrants’ future 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 federal tax reform legislation, including legislation proposed by the new presidential administration, could be enacted that may 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. While the details of the Trump Administration’s potential tax reform have not been announced as of the date of the filing of this Form 10-K, during his 2024 presidential campaign, President Trump outlined several intended reforms, including reducing the corporate tax rate for domestic oil and gas production, repealing or revising the IRA, extending certain provisions of the TCJA and imposing new tariffs. In January 2025, President Trump signed an executive order that, among other things, pauses the disbursement of funds appropriated through the IRA. In February 2025, President Trump imposed tariffs on various countries (the effectiveness of tariffs imposed on certain countries was subsequently delayed until March 2025) and certain imports into the United States. 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. Additionally, the change in administration and the expiring tax cuts in the TCJA could result in the repeal of or changes to the IRA, including renewable energy tax credits enacted in the IRA, and these changes could impact CenterPoint Energy’s net zero and GHG emissions reduction goals. 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 financial condition, results of operations or 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 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 could 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 being unable or unwilling to complete critical functions, which could adversely affect our businesses, financial condition and results of operations, and could make it harder to, among other things, recruit and retain certain employees. 35 Cyberattacks, physical security breaches, acts of terrorism or other disruptions could adversely impact our reputation, 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 generation, transmission and distribution systems is dependent on the physical interconnection of our facilities, as well as communications among the various components of our systems and third-party systems. 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 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 our use of AI, may further expose our computer systems to the risk of cybersecurity incidents. Cyberattacks, including phishing 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 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 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. 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 vendors, suppliers, contractors and quasi 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, results of operations, or financial condition. 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. Our insurance coverage may not be sufficient to cover all costs associated with cybersecurity threats or incidents. 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. A failure to maintain and enhance existing information technology systems 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. 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, or acts of terrorism, including by foreign or domestic actors, 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, regulatory enforcement actions, litigation and a potential adverse effect on our operations, 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. 36 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 reputation, financial condition, results of operations and cash flows. Cyberattacks are becoming more sophisticated, and U.S. government warnings have indicated infrastructure assets, including pipelines and electric generation and infrastructure, may be specifically targeted by certain groups. 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 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 reputation, 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 our third parties (vendors, suppliers, and contractors) collect and retain personal information (for example, information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties 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 of our third parties 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. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection privacy, we may incur significant liabilities and penalties as a result. 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 our third-parties (vendors, suppliers, and contractors) could result in unintended consequences. We contract with third-parties 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, our AI-related efforts may give rise to risks related to harmful content, accuracy, bias, discrimination, intellectual property infringement or misappropriation, defamation, data privacy, and cybersecurity, among others. In addition, the adoption of AI may subject us to new or enhanced governmental or regulatory scrutiny, new or amended laws, rules, directives, and regulations governing the use of AI, litigation, ethical concerns, negative consumer perceptions as to automation and AI, or other complications that could adversely affect our business, reputation, or financial results. We may not be able to recover our investments in AI technology through our regulatory proceedings, and our use of, or our third parties’ 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. 37 General and Other Risks Our revenues and results of operations are seasonal. Houston Electric’s, Indiana Electric’s and Natural Gas’ 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 financial condition. 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 Electric’s results of operations in a manner that would not likely be annually recurring. Natural Gas’ revenues are customarily higher during the winter months. As in certain past years, unusually mild weather in the winter months could diminish Natural Gas’ results of operations and harm its financial condition. Conversely, as occurred in certain past years, extreme cold weather conditions could increase its results of operations in a manner that would not likely be annually recurring. For additional risks related to the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements for further information. Climate change and other weather and natural disaster impacts could adversely impact financial results from our businesses and our results of operations. A changing climate creates uncertainty and could result in broad changes, both physical and financial in nature, to our service territories and our business. If climate changes occur that result in warmer temperatures than normal in our service territories, 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. Another possible result of climate change is more frequent and more severe weather events. Weather-related incidents have become more prevalent, unpredictable and severe as a result of climate change or other factors. Severe weather events impact our service territories, primarily when hurricanes, tornadoes, floods, severe winter weather conditions, including ice storms, wildfires, thunderstorms, high winds, hail, derecho events, microbursts, or extreme temperatures (high heating/cooling days) occur, which can impact our operations and our ability to serve our customers, including resulting in large-scale and/or prolonged outages. To the extent the frequency and severity of extreme weather events increases, 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. Further, events of extreme weather 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 financial condition, results of operations and cash flows. Wildfires also have the potential to negatively affect communities our service territories and the surrounding areas, as well as 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. The possibility of wildfires and the risk of damage to our network, facilities and systems resulting therefrom may be exacerbated by severe weather events and the effects of climate change. The continued expansion of the wildland-urban interface has also increased wildfire risk to communities in our service territories. 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. 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 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 financial condition, results of operations and cash flows. Furthermore, any 38 damage caused to our assets, loss of service to our customers or liability imposed as a result of wildfires could negatively impact our financial condition, results of operations and cash flows. In the long term, climate change could also cause shifts in population, including customers moving away from our service territories. When we cannot deliver electricity or natural gas to 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. For further information on these initiatives, see “— We are subject to operational…” Finally, we 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. For more information, see “— CenterPoint Energy is subject to operational and financial risks...” We are exposed to risks related to changes in demand and energy consumption that could adversely impact financial results from our businesses and our results of operations. Our businesses are affected by reduction in energy consumption due to factors including economic, climate and market conditions in our service territories, energy efficiency initiatives, 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 mandated energy efficiency measures, bans on or further regulation of natural gas-fired appliances, demand-side management goals, distributed generation resources and economic and demographic conditions, including population changes, job and income growth, housing starts, new business formation and the overall level of economic activity. 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. 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 financial condition, results of operations and cash flows. Additionally, our operations are affected by new customers and load growth. For example, the expansion of data centers (associated with, among other things, increasing demand for artificial intelligence), energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, among others, could lead to an unprecedented increase in demand for electric power in our service territories. As we evaluate business opportunities presented by such development in our service territories, we are subject to potential challenges including accurately predicting future power needs due to rapidly changing technology and market dynamics, 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, managing the possible environmental impact of the potential increased power demand, achieving our net zero and GHG emissions reduction goals and evaluating and complying with evolving regulations related to such development. Our efforts to predict and address these challenges could have a material impact on us, including if we fail to fully realize anticipated benefits from significant capital investments and expenditures made to address such development, which could have an adverse effect on our financial condition, results of operations and cash flows. 39 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. The age of certain of our assets may result in a need for replacement or higher level of maintenance costs because of our risk based federal and state compliant integrity management programs. As part of our long-term capital plan, GHRI and the SRP, 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 may make inspections, maintenance, upgrading and replacement of the assets particularly challenging. Also, our ability to successfully maintain or replace our aging infrastructure may be delayed or be at a greater cost than anticipated due to supply chain disruptions. Further, with respect to 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 financial condition, results of operations and cash flows. Finally, aging infrastructure may complicate our utility operations ability to address climate change concerns and efforts to enhance resiliency and reliability. See “— Disruptions to the global supply...” Our 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 generation, transmission and distribution 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 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 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; • 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 of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations; • compliance mandates that result in 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; • information technology failure, including failure of AI technology, that affects our ability to access customer information or causes us to lose confidential or proprietary data that adversely affects our reputation or exposes us to legal claims; and • catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornados, derecho events, ice storms, terrorism, wildfires, pandemic health events, 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. Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities, delays in cash collections, harm to our reputation, less favorable legislative and regulatory outcomes or increased regulatory oversight, any of which could have an adverse effect on our business, financial condition, results of operations and 40 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 technological change and may not be successful or may have to incur significant expenditures to adapt to 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 grow that may be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant investments and expenditures so that we can continue to provide cost-effective and reliable methods for energy production and delivery. Among such technological advances are distributed generation resources (e.g., private solar, microturbines, fuel cells), energy storage devices and more energy-efficient buildings and products designed to reduce energy consumption, emissions attributable to our operations and waste. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, such as under the IRA, certain customers may choose to meet their own energy needs and subsequently decrease usage of our systems and services, including Indiana Electric’s generating facilities becoming less competitive and economical. Further, certain regulatory and legislative bodies have introduced or are considering requirements and incentives to reduce energy consumption by certain dates. Just as high inflation and rising interest rates incentivize our customers to consume less energy, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric and natural gas devices or other improvements in or applications of technology could lead to declines in per capita energy consumption. Our future success will depend, in part, on our ability to anticipate and adapt to these technological changes in a 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 in obsolete assets. For example, an expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, among others, could generate a significant increase in demand for electric power in CenterPoint Energy’s service territories, which may require us to rapidly adopt new technologies and make significant transmission and distribution investments, including advanced grid infrastructure, which increases exposure to overall grid instability and technology obsolescence. If we fail to adapt successfully to any technological change or obsolescence, fail to obtain access to important technologies or incur significant expenditures in adapting to technological change, or if implemented technology does not operate as anticipated, 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 financial condition, results of operations and cash flows. We currently have insurance in place, such as general liability and property insurance, to cover certain of our facilities 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 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. 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 financial condition, results of operations and cash flows. Global or regional health pandemics, epidemics or similar public health threats could negatively impact our business, outlook, financial condition, results of operations and liquidity. 41 Current and future health pandemics, epidemics and similar public health threats and the measures implemented to contain their spread, such as travel bans and restrictions, quarantines and vaccination mandates, have had and may in the future have widespread impacts on the global economy, our employees, customers, and third-party business partners. The severity, magnitude and duration of future health threats is uncertain and hard to predict. Any future health threat could impact our business in numerous ways, including, but not limited to, those outlined below: • reduced demand from our commercial and industrial customers and shifts in demand for our services; • delayed service to customers because of shutdowns or illness and travel restrictions among our employees; • negative impacts to the financial condition of our customers and REPs and their ability to pay for our services, and our ability to disconnect service for non-payment may be limited, and state regulators may impose bill deferral programs; • potential limits or significant or entire curtailments of the ability of public utility commissions to approve or authorize applications and other requests we may make with respect to our businesses, including delaying rate making proceedings; • increased risk to our cybersecurity program as a result of an increase in cyberattacks during the pandemic and increased remote working arrangements (for further information, see “— Risk Factors Affecting Safety and Security Risks”); • increased rates of inflation and delays in our supply chain and our ability to complete maintenance, repairs, and capital programs, which could result in disruption, increased costs and our inability to execute on or require us to make modifications to our capital plan; and • accelerated employee turnover as a result of concerns regarding restrictions and guidelines, including mask mandates and quarantine mandates, and increased acceptability of alternative work arrangements. Like many companies, we experienced the above and other impacts during the COVID-19 pandemic. These and other impacts of global or regional health pandemics, epidemics or similar public health threats could also have the effect of heightening many of the other risks described in this section and the other reports we file from time to time with the SEC. 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 operations, financial condition and liquidity. The ultimate impact of public health threats on our business depends on factors beyond our knowledge or control, including the duration and severity of the outbreak as well as third-party actions taken to contain the spread and mitigate the public health effects. Any of these factors could have a negative impact on our business, outlook, financial condition and results of operations, which impact could be material. Our success depends upon our ability to attract, effectively transition, motivate and retain key employees and identify and develop talent to succeed senior management. We depend on senior executive officers and other key personnel. Our success depends on our ability to attract, effectively transition and retain key personnel. Further tightening of the labor market and increasing wages to attract and retain key personnel may adversely affect our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify, motivate and develop talent to succeed senior management. The retention of key personnel and appropriate senior management succession planning will continue to be critically important to the successful implementation of our strategies. Failure to attract and retain an appropriately qualified workforce and maintain good labor relations could adversely impact the operations of our facilities and our results of operations. Our businesses are dependent on recruiting, retaining and motivating employees. 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, increasing 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, 18.2%, 18.7%, and 19.3% were retirement eligible as of December 31, 2024, 2023, and 2022, 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 and safety costs, may rise. 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 contract labor may adversely affect the ability to manage and operate our 42 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. If we are unable to successfully attract and retain an appropriately qualified workforce, our ability to execute on our 10-year capital plan and our results of operations 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 different labor unions, comprising approximately 39% 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 Gas Workers Union Local 340, IBEW Local 949 and OPEIU Local 12 related to CERC employees in Minnesota, as well as with IBEW Local 702 related to SIGECO employees, are scheduled to expire in April 2025, December 2025, December 2025 and June 2025, respectively, and negotiations of these agreements are expected to be completed before the respective expirations. 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, results of operations and/or 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, results of operations and cash flows. 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 of Directors. 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 annually 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 43 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. 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, the Company 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 and data privacy programs, including cybersecurity 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, Senior Vice President and Chief Information Security Officer (CISO) 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 significant 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 CISO 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 CISO 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 CISO 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. 44 CenterPoint Energy’s CISO joined the Company in September 2024 and has over two decades of experience serving in multiple global leadership roles in cybersecurity, as well as technology and industrial systems at a Fortune 500 global industrial company, for which he was responsible for, among other things, building and maintaining enterprise programs relating to cybersecurity and managing cybersecurity risk. 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, 2024. 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. 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 project 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. Electric Lines - Transmission and Distribution. As of December 31, 2024, 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 109 2 568 — 138 kV 2,347 24 422 9 345 kV 1,445 — 49 15 Total 3,901 26 1,039 24 Distribution lines 29,327 27,000 7,318 — 45 (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. Generating Capacity. As of December 31, 2024, Indiana Electric had 577 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 2 Warrick County, Indiana 1966 90 F.B. Culley 3 Warrick County, Indiana 1973 270 Total Coal Capacity 360 Gas Brown (1) 3 Posey County, Indiana 1991 80 Brown 4 Posey County, Indiana 2002 80 Renewable Landfill Gas Pike County, Indiana 2009 3 Total Gas Capacity 163 Solar Oak Hill Evansville, Indiana 2018 2 Volkman Evansville, Indiana 2018 2 Troy Spencer County, Indiana 2021 50 Total Solar Capacity 54 Total Generating Capacity (2) 577 (1) Brown Unit 3 is also equipped to burn oil. (2) 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. The turbines are targeted to be operational by mid-year 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. Indiana Electric entered into an amended and restated BTA to build a 191 MW solar array in Posey County, Indiana, , and a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price; however on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate this BTA. For further information about Indiana Electric’s BTA’s, 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. Temporary Generation. As allowed by a law enacted by the Texas legislature after the February 2021 Winter Storm Event and amended in 2023, Houston Electric is leasing TEEEF that can aid in restoring power to customers during certain significant power outages that are impacting its distribution system. On December 19, 2024, Houston Electric announced a proposal to release certain of Houston Electric’s TEEEF to the San Antonio area prior to the summer of 2025 for a period of up to two years, during which Houston Electric would not receive revenue or profit from ERCOT and would not charge Houston-area customers for these TEEEF units. As of December 31, 2024, Houston Electric leased 505 MW of TEEEF. For more information, see Note 7 and Note 19 to the consolidated financial statements. 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, 2024: Number of Substations Transformer Capacity (in Mva) Houston Electric 243 73,667 Indiana Electric 109 6,992 Total CenterPoint Energy 352 80,659 46 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, 2024: Number of Service Centers Acres of Land Houston Electric 13 362 Indiana Electric 6 70 Total CenterPoint Energy 19 432 Natural Gas (CenterPoint Energy and CERC) CenterPoint Energy’s and CERC’s Natural Gas 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 may also supplement contracted supplies and storage from time to time with stored LNG and propane-air plant production. As of December 31, 2024, CenterPoint Energy’s and CERC’s Natural Gas 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 contracted upstream storage services as of December 31, 2024: Storage Capacity (Bcf) Maximum Peak Daily Delivery (MMcf) Upstream Storage Service 89 2,311 The table below reflects the approximate total linear miles of CenterPoint Energy’s and CERC’s Natural Gas distribution and transmission mains owned as of December 31, 2024: CenterPoint Energy CERC All Locations 85,000 82,000 Indiana and Ohio 22,000 19,000 CenterPoint Energy’s and CERC’s Natural Gas owned mains varying in size from one-half inch to 24 inches in diameter. CenterPoint Energy’s and CERC’s Natural Gas Indiana and Ohio mains 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, they own the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure 47 maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s Natural Gas 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, 2024, CenterPoint Energy and CERC, through CEIP, owned and operated over 219 miles of intrastate pipeline in Louisiana and Texas. On February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses, which include the intrastate pipelines owned by CEIP in Louisiana. The transaction is expected to close in the first quarter of 2025. 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(d) to the consolidated financial statements, which information is incorporated herein by reference. Item 4. Mine Safety Disclosures Not applicable. 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 10, 2025, CenterPoint Energy’s common stock was held by approximately 21,495 shareholders of record. CenterPoint Energy’s common stock is listed on the NYSE and NYSE Chicago 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 CenterPoint Energy’s Board of Directors considers relevant and will be declared at the discretion of CenterPoint Energy’s Board of Directors. 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, 2024, 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 10, 2025, 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 10, 2025, 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. 48 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 stated otherwise. No registrant makes any representations as to the information related solely to CenterPoint Energy, Inc. or the subsidiaries of CenterPoint Energy, Inc. other than itself. 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. CERC Corp. is an indirect, wholly-owned subsidiary of CenterPoint Energy, which (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi 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 February 19, 2024, CenterPoint Energy, through its subsidiary CERC Corp., entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The transaction is expected to close in the first quarter of 2025. 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, 2024. For a detailed description of the assets included in each reporting segment, see Part I, Item 1. Business. • The Electric reportable segment includes electric transmission and distribution services that are subject to rate regulation in Houston Electric’s and Indiana Electric’s service territories, as well as the impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility and energy delivery services to electric customers and electric generation assets to serve electric customers and optimize those assets in the wholesale power market in Indiana Electric’s service territory. • The Natural Gas reportable segment includes (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial and industrial customers in Indiana, Louisiana, Minnesota, Mississippi, Ohio and Texas; (ii) permanent pipeline connections through interconnects with various interstate and intrastate pipeline companies through CEIP; and (iii) home appliance maintenance and repair services to customers in Minnesota and home repair protection plans to natural gas customers in Indiana, Mississippi, Ohio and Texas through a third party. 49 • The Corporate and Other reportable segment includes (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 operations that support the business operations of CenterPoint Energy; 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 and distribution, power generation, and natural gas distribution operations that serve more than seven million metered customers across six jurisdictions. 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 which were set in 2021. These include our ten-year capital plan from 2021 through 2030, a focus on targeting controllable operations and maintenance savings for the benefit of our customers, prudent capital funding including divestitures of non-core assets, and net zero and GHG emissions reduction goals. Our focus continues to be on the growth of our regulated utility businesses including our electric and gas utility operations, which comprise over 95% of our earnings for the year ended December 31, 2024. See Note 16 to the consolidated financial statements for further details. Pursuant to this business strategy and in light of the nature of our businesses, significant amounts of capital investment are reflected in our current 10-year capital plan, which has increased to nearly $47.5 billion through 2030. These investments include a focus on additional system resiliency, reliability, and grid modernization. These investments are not only intended to meet our customers’ current needs, but are also in anticipation for further organic growth and load growth from increased electrification in our service territories. 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 the divestitures of our Arkansas and Oklahoma LDC businesses in 2022, our Energy Systems Group divestiture in 2023 and the proposed sale of our Louisiana and Mississippi natural gas LDC businesses, which is expected to close in the first quarter of 2025), and issuances of equity and debt in the capital markets, including the issuance of non-recourse securitization bonds at Houston Electric related to costs incurred during the year ended December 31, 2024 due to the May 2024 Storm Events and Hurricane Beryl. We strive to maintain investment grade ratings for our securities to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would increase 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 new capital 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. The regulation of electric transmission, distribution and generation facilities as well as natural gas pipelines and related facilities by federal and state regulatory agencies affects our businesses. In accordance with applicable regulations, we are making, and will continue to make, significant capital investments in our service territories under our capital plan to help operate and maintain safer, more reliable and growing electric and natural gas systems. The current economic environment (e.g., sustained higher interest rates and higher relative levels of inflation in the United States) discussed further below could result in heightened regulatory scrutiny as these regulatory agencies seek to reduce the financial impact of utility bills on customers. While greater than 80% 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, the balance is expected to be recovered through base rate cases. Indiana Electric filed a rate case during 2023, and Houston Electric and CERC’s Ohio jurisdiction filed rate cases in 2024. The outcome of these base rate proceedings will determine, among other things, the ability to recover certain capital 50 investments within those jurisdictions. The outcome of these base rate proceedings is uncertain and may be impacted by the current economic environment. CERC’s Texas and Minnesota gas jurisdictions filed rate cases in 2023, which were settled in 2024. 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 the evaluation of net income and capital expenditures, among other things, 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. 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, environmental impacts, 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 Natural Gas in Indiana, Louisiana, Mississippi, Minnesota and Ohio, as applicable. CenterPoint Energy’s and CERC’s Natural Gas in Texas and CenterPoint Energy’s electric operations in Texas and Indiana do not have such mechanisms, although fixed customer charges are historically higher in Texas for Natural Gas compared to its other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on CenterPoint Energy’s and CERC’s Natural Gas’ results in Texas and on CenterPoint Energy’s electric operations’ results in its Texas and Indiana service territories. Each state has a unique economy and is driven by different industrial sectors. Our largest customers reflect the diversity in industries in the states across our footprint. For example, Houston Electric is largely concentrated in Houston, a diverse economy where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although the Houston area represents a large part of our customer base, we have a diverse customer base throughout the various states our utility businesses serve. In Minnesota, for instance, education and health services are the state’s largest sectors. Indiana and Ohio are impacted by changes in the Midwest economy in general and changes in particular industries concentrated in the Midwest such as automotive, feed and grain processing. Some industries are driven by population growth like education and health care, while others may be influenced by strength in the national or international economy. Adverse economic conditions, coupled with concerns for protecting the environment and increased availability of alternate energy sources, may cause consumers to use less energy or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for our services. Long-term national trends indicate residential customers have reduced their energy consumption, which could adversely affect 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. Management expects residential meter growth for Houston Electric to remain in line with long term trends at approximately 2%. Management additionally anticipates significant increased electric load growth demand in our Houston Electric service territory, including in relation to the expected expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics. Typical customer growth in the jurisdictions served by the Natural Gas reportable segment is approximately 1%. Management expects residential meter growth for CERC to remain in line with long term trends at approximately 1%. Inflation and high interest rates and a recessionary environment could potentially adversely impact CenterPoint Energy’s ability to execute on its 10-year capital plan. The inability to execute on our capital plan may result in lost future revenues for CenterPoint Energy. Additionally, these economic conditions may affect customers’ ability to pay their utility bills which may preclude our ability to collect balances due from such customers. Further, the global supply chain has experienced significant disruptions due to a multitude of factors, such as geopolitical and economic uncertainty, regulatory and political instability, import tariffs and trade agreements, labor shortages, resource availability, long lead times, manufacturer production limitations, delivery delays, inflation and severe weather events. These disruptions have adversely impacted the utility industry. Like many of our peers, we have experienced disruptions to our supply chain, as well as increased prices, and may continue to experience such disruptions in the future. For example, President Trump has expressed a desire to impose substantial new or increased tariffs, and in February 2025, imposed tariffs on several countries and certain imports into the United States. These tariffs, as well as any new legislation, tariffs, bans, potential retaliatory trade measures taken against the United States or related governmental action, could increase or cause volatility in the cost of and negatively impact our ability to procure materials, supplies (such as natural gas) or services necessary for our business and capital plan, lead to scarcity of resources and labor necessary for our business and capital plan, further extend lead time or otherwise negatively impact the supply chain and our ability to timely execute our capital plan. To the extent adverse economic conditions, including supply chain disruptions, affect our suppliers and customers as well as our ability to meet our capital plan and generation transition plan, including with respect to developing and constructing new generation facilities at the cost and scale and on the timelines that we anticipate, results from our energy delivery businesses may suffer. For more information, see Note 14 to the consolidated financial statements. 51 Further, in response to concerns for protecting the environment, we have strived to take a leading stance in the transition to safer and cleaner energy by being the first combined electric and natural gas utility with regulated generation assets to adopt net zero for its Scope 1 and certain Scope 2 emissions by 2035 goals. In addition, we set a Scope 3 emission reduction goal across our multi-state footprint by committing to help our residential and commercial customers reduce GHG emissions attributable to their end use of natural gas by 20% to 30% by 2035 from a 2021 baseline. Our capital plan supports these goals. For more information regarding CenterPoint Energy’s net zero and GHG emissions reduction goals and the risks associated with them, see Part I, Item 1A. “Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks...” Significant Events May 2024 Storm Events and Hurricane Beryl. Houston Electric’s service territory experienced sudden and destructive severe weather events in May 2024 that included hurricane-like winds and tornadoes. Subsequently, on July 8, 2024, Hurricane Beryl made landfall in Texas, bringing sustained winds, storm surges and torrential rain into Houston Electric’s service territory. The May 2024 Storm Events and Hurricane Beryl caused significant damage to Houston Electric’s electric delivery system and resulted in electric service interruptions peaking at an estimated 922,000 customers and more than 2.1 million customers, respectively. Various federal, state and local governmental and regulatory agencies and other entities, such as the Texas Governor’s office, the Texas legislature and the PUCT, have called for or are conducting inquiries and investigations into Hurricane Beryl, the efforts made by Houston Electric to prepare for, and respond to, this event, including the electric service outage issues, and the procurement of TEEEF. Moreover, additional governmental and regulatory agencies and other entities may conduct such inquiries and investigations, as well. On August 12, 2024, Texas Attorney General Ken Paxton opened an investigation to evaluate CenterPoint Energy’s conduct during Hurricane Beryl. Texas Lieutenant Governor Patrick has publicly urged the PUCT to hold Houston Electric, rather than ratepayers, responsible for paying $800 million, which was the amount the PUCT had previously approved Houston Electric to recover from ratepayers pursuant to Texas legislation passed after the 2021 Winter Storm Event relating to emergency responsiveness and the leasing of temporary generation units. Additionally, legislation has been proposed in Texas to, among other things, require the PUCT to review TEEEF leased by TDUs, disallow any leases that do not conform to the terms of the proposed legislation (which include, among other things, requirements relating to the speed with which TEEEF may be deployed), disallow recovery of costs associated with such disallowed leases, and implement a process to refund ratepayers the charges paid for the leasing of certain TEEEF. There are significant uncertainties around these inquiries and investigations and potential results and consequences, including with respect to our recovery of costs incurred as a result of Hurricane Beryl and whether any financial penalties will be assessed or changes to Houston Electric’s system, service territories, operations and/or regulatory treatment will result therefrom. Further, on January 22, 2025, a putative shareholder of CenterPoint Energy, Donel Davidson, filed a derivative petition in Harris County District Court, Texas, alleging breach of fiduciary duty and unjust enrichment on behalf of CenterPoint Energy against certain of its current and former directors and officers citing, in part, the topics of these inquiries and investigations. The action seeks to recover damages and other relief from the defendants on behalf of CenterPoint Energy. Additionally, on February 12, 2025, a second putative shareholder of CenterPoint Energy made a demand on the Board to investigate the same basic allegations raised in the derivative petition filed by Donel Davidson. Houston Electric announced an initial hurricane preparedness and response action plan to the PUCT on July 25, 2024 to enhance the resiliency of the electric system through various investments. Following a meeting with Texas Governor Abbott on August 1, 2024, Houston Electric publicly committed to accelerating its previously announced initial hurricane preparedness and response action plan. Accordingly, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan with the PUCT in order to focus on addressing the impacts of Hurricane Beryl in its service territory and accelerating preparedness and resiliency efforts for the remaining storm season, and the withdrawal granted by the PUCT. On August 5, 2024, Houston Electric announced the launch of its GHRI. Subsequently, Houston Electric announced the completion of core resiliency actions as part of the first phase of its GHRI, which included certain vegetation management and pole installation goals. In September 2024, Houston Electric announced the launch of the second phase of its GHRI, which included a series of resiliency plans to install new poles, manage higher-risk vegetation and install certain automated devices prior to the start of the 2025 hurricane season as part of its efforts to strengthen grid resiliency, improve public and customer communications and strengthen local, community and emergency partnerships. Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed the SRP 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. 52 Houston Electric announced on August 28, 2024 its proposal to forego approximately $110 million of profit related to its storm hardening and TEEEF efforts, which would be represented by (1) Houston Electric not seeking to recover approximately $70 million in incremental storm hardening costs incurred in connection with accelerated operational activities after Hurricane Beryl; and (2) Houston Electric not filing, beginning in 2028, for approximately $40 million in anticipated equity profit associated with load-shed orientated TEEEF leased by Houston Electric through the remaining regulatory life of the leases in 2032 as new dispatchable generation is likely to come online in the state of Texas as a result of the Texas Energy Fund. Additionally, on December 19, 2024, Houston Electric announced a proposal to release Houston Electric’s 15 large 27 MW to 32 MW TEEEF units to the San Antonio area prior to the summer of 2025 in an effort to help ERCOT address a potential energy shortfall and Load Shed risk and to provide additional electric generation capacity to support growing energy demand in the greater San Antonio region. Under the proposal, Houston Electric would not receive revenue or profit from ERCOT and would also not charge Houston-area customers for these TEEEF units for the period when they are in San Antonio serving ERCOT, which is currently expected to be for a period of up to two years. Houston Electric would anticipate receiving revenues from one or more future transactions after the period the units are utilized to temporarily serve an energy need in the San Antonio area, and would therefore plan to continue to not charge customers for these units for any future periods. As of the date of the filing of this Form 10-K, Houston Electric estimates that the value of the TEEEF units to be removed from the rate base as a result of the aforementioned proposal will be approximately $375 million. The proposal has not been finalized and is subject to the negotiation of definitive documentation among the relevant parties, as well as being subject to the approval of ERCOT and other stakeholders. It is not certain that mutually agreeable definitive documentation will be entered into at all or that all approvals will be obtained. For more information, see Note 7, 12 and 14 to the consolidated financial statements and “Liquidity and Capital Resources” below. Equity Transactions. On August 9, 2024, CenterPoint Energy issued 9,754,194 shares of Common Stock in an underwritten public offering at a price of $25.36 per share, for net proceeds of $247 million after deducting issuance costs. For further information, see Note 11 to the consolidated financial statements. On January 10, 2024, CenterPoint Energy entered into an Equity Distribution Agreement with certain financial institutions with respect to the offering and sale from time to time of shares of Common Stock, having an aggregate gross sales price of up to $500 million. Sales of Common Stock may be made by any method permitted by applicable law and deemed to be an “at the market offering” as defined in Rule 415 of the Securities Act of 1933, as amended. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. During the year ended December 31, 2024, CenterPoint Energy issued 8,790,848 shares of Common Stock through the ATM Managers under the Equity Distribution Agreement, representing aggregate cash proceeds of $247 million, which was net of compensation paid by CenterPoint Energy to the ATM Managers of $2 million. As of December 31, 2024, CenterPoint Energy had not entered into any forward sale agreements under the at-the-market program. Additionally, as of December 31, 2024, CenterPoint Energy had $250 million of remaining capacity available under the program. For further information, see Note 11 to the consolidated financial statements. Assets Held for Sale. On February 19, 2024, CERC Corp. entered into the LAMS Asset Purchase Agreement to sell its Louisiana and Mississippi natural gas LDC businesses. The purchase price for the Louisiana and Mississippi natural gas LDC businesses is $1.2 billion and subject to adjustment as set forth in the LAMS Asset Purchase Agreement, including adjustments based on net working capital, regulatory assets and liabilities and capital expenditures at closing. The transaction is not subject to a financing condition and is expected to close by the end of the first quarter of 2025, subject to satisfaction of customary closing conditions. The businesses include approximately 12,000 miles of main pipeline in Louisiana and Mississippi serving more than 300,000 customers. The Louisiana and Mississippi natural gas LDC businesses are 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. Regulatory Proceedings. For further information, see Note 7 to the consolidated financial statements. For information related to our pending and completed regulatory proceedings to date in 2024 and to date in 2025, see “—Liquidity and Capital Resources —Regulatory Matters” below. Debt Transactions. In 2024, CenterPoint Energy issued or borrowed a combined $4.0 billion in new debt, including Houston Electric’s issuance of $900 million aggregate principal amount of general mortgage bonds and a $500 million term loan, CERC’s issuance of $400 million principal amount of senior notes, SIGECO’s issuance of $160 million aggregate principal amount of first mortgage bonds, and CenterPoint Energy’s issuance of $700 million aggregate principal amount of senior notes and $1.3 billion aggregate principal amount of junior subordinated notes. During 2024, CenterPoint Energy repaid or redeemed a combined $0.9 billion of debt, including $500 million of its senior notes, $350 million of its floating rate senior notes and $22 million of SIGECO’s first mortgage bonds. For further information about debt transactions in 2024, see Note 12 53 to the consolidated financial statements. Subsequent Events . On January 29, 2025, CenterPoint Energy, Houston Electric, CERC and SIGECO each entered into Extension Agreements to, among other things, extend the maturity date of the lenders’ commitments under each of their respective Credit Agreements by one year, from December 6, 2027 to December 6, 2028. Additionally, on January 31, 2025, SIGECO issued $165 million aggregate principal amount of 5.69% First Mortgage Bonds, Series 2025A, Tranche A due 2055. Total net proceeds from SIGECO’s January 2025 issuance of first mortgage bonds, net of transaction expenses and fees, were approximately $164 million, which will be used for the acquisition of Posey Solar. 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 Louisiana and Mississippi natural gas LDC businesses, 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, including in relation to the expansion of data centers, energy export facilities, including hydrogen facilities, electrification of industrial processes and transport and logistics, as well as the effects of energy efficiency measures and demographic patterns; • 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 Indiana Electric’s generation transition plan as part of its IRPs and Houston Electric’s GHRI and SRP; • our ability to successfully construct, operate, repair and maintain electric generating facilities, natural gas facilities, TEEEF and electric transmission facilities, including complying with applicable environmental standards and the implementation of a well-balanced energy and resource mix, as appropriate; • 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 TEEEF leases and restoration costs relating to the May 2024 Storm Events and Hurricane Beryl, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings; • our ability to finalize Houston Electric’s proposal to release its 15 large 27 MW to 32 MW TEEEF units to the San Antonio area and complete one or more other future transactions involving the units on acceptable terms and conditions within the anticipated timeframe; • economic conditions in regional and national markets, including changes to inflation and interest rates, and their effect on sales, prices and costs; • weather variations and other natural phenomena, including the impact of severe weather events on operations, capital, legislation and/or regulations, such as 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, tariffs, legislation, bans, potential retaliatory trade measures taken against the United States or related governmental action, as well as armed conflicts, including the conflict in the Middle East and any broader related conflict, and the conflict in Ukraine, and the related sanctions on certain Russian entities; • disruptions to the global supply chain, including as a result of volatility in commodity prices, trade agreements, geopolitical and economic uncertainty, regulatory and policy instability, severe weather events, tariffs, bans, retaliatory trade measures, legislation and governmental action impacting the supply chain, that could prevent CenterPoint Energy from securing the resources needed to, among other things, fully execute on its 10-year capital plan or achieve its net zero and GHG emissions reduction goals; • 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; • state and federal legislative and regulatory actions or developments affecting various aspects of our businesses, including, among others, any actions resulting from the May 2024 Storm Events and/or Hurricane Beryl, energy 54 deregulation or re-regulation, pipeline integrity and safety and changes in regulation and legislation pertaining to trade, health care, finance and actions regarding the rates charged by our regulated businesses; • our ability to execute Houston Electric’s GHRI and SRP; • direct or indirect effects on our facilities, resources, operations, reputation and financial condition resulting from terrorism, cyberattacks or intrusions, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes, derecho events, ice storms and other severe weather events, terrorism, wildfires, pandemic health events, geopolitical conflict or other occurrences; • risks relating to potential wildfires, including damages to our network and losses in excess of insurance liability coverage; • tax legislation, including the effects of or changes to or the repeal of the IRA (which includes but is not limited to any potential changes to tax rates, CAMT imposed, tax credits and/or interest deductibility), as well as any changes in tax laws under the current or future administrations, and 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; • matters affecting regulatory approval, legislative actions, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or cancellation or in costs that cannot be recouped in rates; • local, state and federal legislative and regulatory actions or developments relating to the environment, including, among others, those related to global climate change, 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 net zero and GHG emissions reduction 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; • the availability and prices of raw materials and services and changes in labor for current and future construction projects and operations and maintenance costs, including our ability to control such costs; • 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; • 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 debt 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 the May 2024 Storm Events and 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 management and key employees and maintain good labor relations; • changes in technology, particularly 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 and adapt to technological changes; • our success in adopting, developing and deploying AI; • the impact of climate change and alternate energy sources on the demand for natural gas and electricity generated or transmitted by us; • 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 new presidential administration; • CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including its net zero and GHG emissions reduction goals and its 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. 55 56 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, read “Risk Factors” in Part I, Item 1A of this report. Income available to common shareholders for the years ended December 31, 2024, 2023 and 2022 was as follows: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions) Electric $ 671 $ 654 $ 603 $ 17 $ 51 Natural Gas 564 533 492 31 41 Total Utility Operations 1,235 1,187 1,095 48 92 Corporate & Other (1) (216) (320) (87) 104 (233) Total CenterPoint Energy $ 1,019 $ 867 $ 1,008 $ 152 $ (141) (1) 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. 2024 Compared to 2023 CenterPoint Energy reported income available to common shareholders of $1,019 million for 2024 compared to income available to common shareholders of $867 million for 2023. 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 $31 million for the Natural Gas reportable segment, as further discussed below; and • an increase in income available to common shareholders of $104 million for Corporate and Other, 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. 2023 Compared to 2022 CenterPoint Energy reported income available to common shareholders of $867 million for 2023 compared to income available to common shareholders of $1,008 million for 2022. Income available to common shareholders decreased $141 million primarily due to the following items: • an increase in income available to common shareholders of $51 million for the Electric reportable segment, as further discussed below; • an increase in income available to common shareholders of $41 million for the Natural Gas reportable segment, as further discussed below; and • a decrease in income available to common shareholders of $233 million for Corporate and Other, primarily due to a pre-tax net gain of $86 million on the sale of Energy Transfer equity securities in 2022 further discussed in Note 10 to the consolidated financial statements, partially offset by $45 million of costs associated with early redemption of long-term debt in first quarter 2022. The decrease is also due to a loss on sale of $13 million and current tax expense of 57 $32 million related to the divestiture of Energy Systems Group further discussed in Note 4 to the consolidated financial statements, as well as $19 million due to remeasurement of deferred income tax balances. 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: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues $ 4,590 $ 4,290 $ 4,108 $ 300 $ 182 Expenses: Utility natural gas, fuel and purchased power 198 176 222 (22) 46 Operation and maintenance 2,072 1,880 1,864 (192) (16) Depreciation and amortization 877 872 793 (5) (79) Taxes other than income taxes 304 272 275 (32) 3 Total expenses 3,451 3,200 3,154 (251) (46) Operating Income 1,139 1,090 954 49 136 Other Income (Expense): Interest expense and other finance charges (372) (303) (235) (69) (68) Other income, net 61 56 31 5 25 Income Before Income Taxes 828 843 750 (15) 93 Income tax expense 157 189 147 32 (42) Net Income $ 671 $ 654 $ 603 $ 17 $ 51 Throughput (in GWh): Residential 34,190 35,166 35,074 (3) % — % Total 110,831 108,766 105,541 2 % 3 % Weather (percentage of normal weather for service area): Cooling degree days 115 % 114 % 110 % 1 % 4 % Heating degree days 76 % 90 % 121 % (14) % (31) % Number of metered customers at end of period: Residential 2,640,150 2,588,510 2,534,730 2 % 2 % Total 2,971,730 2,916,028 2,858,203 2 % 2 % 59 The following table provides variance explanations by major income statement caption for the Electric reportable segment: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Customer rates and impact of the change in rate design $ 143 $ 167 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 217 122 Customer growth 26 26 Energy efficiency, offset in operation and maintenance below 5 — Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (20) (5) Pass-through revenues, offset in operation and maintenance below (5) (13) Miscellaneous revenues, including service connections and off-system sales 1 (14) Lost revenues as a result of outages associated with Hurricane Beryl (10) — Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (70) (27) Weather, efficiency improvements and other usage impacts (9) (28) Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below 22 (46) Total $ 300 $ 182 Utility natural gas, fuel and purchased power Cost of purchased power, offset in revenues above $ (87) $ 30 Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above 65 16 Total $ (22) $ 46 Operation and maintenance Transmission costs billed by transmission providers, offset in revenues above $ (124) $ (26) Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl (112) — Contract services 16 (21) Energy efficiency, and other pass-through, offset in revenues above (1) 3 Corporate support services — (8) Labor and benefits 4 7 All other operation and maintenance expense, including materials and supplies and insurance 25 29 Total $ (192) $ (16) Depreciation and amortization Ongoing additions to plant-in-service $ (79) $ (106) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 74 27 Total $ (5) $ (79) Taxes other than income taxes Incremental capital projects placed in service, and the impact of updated property tax rates $ (26) $ 2 Franchise fees and other taxes (6) 1 Total $ (32) $ 3 Interest expense and other finance charges Changes in outstanding debt $ (63) $ (76) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (4) (4) Other, primarily AFUDC and impacts of regulatory deferrals (2) 12 Total $ (69) $ (68) Other income (expense), net Other income, including AFUDC - equity $ 5 $ 21 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above — 4 Total $ 5 $ 25 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: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues $ 4,048 $ 4,279 $ 4,946 $ (231) $ (667) Expenses: Utility natural gas and fuel 1,520 1,888 2,665 368 777 Non-utility cost of revenues, including natural gas 3 3 4 — 1 Operation and maintenance 881 949 919 68 (30) Depreciation and amortization 542 513 466 (29) (47) Taxes other than income taxes 237 245 261 8 16 Total expenses 3,183 3,598 4,315 415 717 Operating Income 865 681 631 184 50 Other Income (Expense): Gain on sale — — 303 — (303) Interest expense and other finance charges (207) (188) (137) (19) (51) Other income (expense), net 14 15 (62) (1) 77 Income Before Income Taxes 672 508 735 164 (227) Income tax expense (benefit) 108 (25) 243 (133) 268 Net Income $ 564 $ 533 $ 492 $ 31 $ 41 Throughput (in Bcf): Residential 189 199 240 (5) % (17) % Commercial and industrial 426 418 424 2 % (1) % Total Throughput 615 617 664 — % (7) % Weather (percentage of 10-year average for service area): Heating degree days 78 % 86 % 106 % (8) % (20) % Number of metered customers at end of period: Residential 4,063,928 4,010,113 3,964,221 1 % 1 % Commercial and industrial 304,606 303,841 301,834 — % 1 % Total 4,368,534 4,313,954 4,266,055 1 % 1 % 61 The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Cost of natural gas, offset in utility natural gas and fuel below $ (368) $ (754) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — (38) Gross receipts tax, offset in taxes other than income taxes below 1 (17) Weather and usage (11) (7) Non-volumetric and miscellaneous revenue (7) 14 Energy efficiency and other pass-through, offset in operation and maintenance below (20) 17 Non-utility revenues 15 18 Customer growth 14 20 Customer rates 145 80 Total $ (231) $ (667) Utility natural gas and fuel Cost of natural gas, offset in revenues above $ 368 $ 754 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 23 Total $ 368 $ 777 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 $ 23 $ (36) Energy efficiency and other pass-through, offset in revenues above 20 (17) Contract services (6) (3) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3 Labor and benefits 8 11 Corporate support services 23 12 Total $ 68 $ (30) Depreciation and amortization Ongoing additions to plant-in-service $ (29) $ (49) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 2 Total $ (29) $ (47) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (1) $ 17 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 1 Incremental capital projects placed in service, and the impact of updated property tax rates 9 (2) Total $ 8 $ 16 Gain on Sale Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022 $ — $ (303) Total $ — $ (303) Interest expense and other finance charges Changes in outstanding debt $ (12) $ (59) Other, primarily AFUDC and impacts of regulatory deferrals (7) 8 Total $ (19) $ (51) Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60 Other income, including AFUDC - Equity 3 10 Other (7) 7 Total $ (1) $ 77 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, read “Risk Factors” in Item 1A of Part I of this report. The following table provides summary data of Houston Electric’s single reportable segment: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues: TDU $ 3,862 $ 3,514 $ 3,205 $ 348 $ 309 Bond Companies 77 163 207 (86) (44) Total revenues 3,939 3,677 3,412 262 265 Expenses: Operation and maintenance, excluding Bond Companies 1,923 1,669 1,647 (254) (22) Depreciation and amortization, excluding Bond Companies 688 593 479 (95) (114) Taxes other than income taxes 295 262 261 (33) (1) Bond Companies 78 159 194 81 35 Total 2,984 2,683 2,581 (301) (102) Operating Income 955 994 831 (39) 163 Other Income (Expense): Interest expense and other finance charges (311) (259) (202) (52) (57) Interest expense on Securitization Bonds (3) (8) (13) 5 5 Other income, net 43 34 19 9 15 Income Before Income Taxes 684 761 635 (77) 126 Income tax expense 138 168 125 30 (43) Net Income $ 546 $ 593 $ 510 $ (47) $ 83 Throughput (in GWh): Residential 32,769 33,830 33,676 (3) % — % Total 106,014 103,862 100,062 2 % 4 % Weather (percentage of 10-year average for service area): Cooling degree days 115 % 114 % 110 % 1 % 4 % Heating degree days 92 % 92 % 120 % — % (28) % Number of metered customers at end of period: Residential 2,506,284 2,455,309 2,402,329 2 % 2 % Total 2,818,343 2,763,535 2,706,598 2 % 2 % 63 The following table provides variance explanations by major income statement caption for Houston Electric: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Customer rates and impact of the change in rate design $ 153 $ 187 Transmission Revenues, including TCOS and TCRF, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 217 120 Customer growth 25 25 Energy efficiency, partially offset in operation and maintenance below 5 1 Miscellaneous revenues 1 (4) Lost revenues as a result of outages associated with Hurricane Beryl (10) — Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (19) (5) Weather, efficiency improvements and other usage impacts (24) (15) Bond Companies, offset in other line items below (86) (44) Total $ 262 $ 265 Operation and maintenance, excluding Bond Companies Transmission costs billed by transmission providers, offset in revenues above $ (124) $ (26) Incremental storm expenses, including storm hardening expenses incurred in connection with accelerated operational activities after Hurricane Beryl (112) — Contract services 7 (23) Energy efficiency, offset in revenues above (6) (8) Corporate support services (2) (6) Labor and benefits 1 3 All other operation and maintenance expense, including materials and supplies and insurance (18) 38 Total $ (254) $ (22) Depreciation and amortization, excluding Bond Companies Ongoing additions to plant-in-service $ (95) $ (114) Total $ (95) $ (114) Taxes other than income taxes Franchise fees and other taxes $ (7) $ (2) Incremental capital projects placed in service, and the impact of changes to tax rates (26) 1 Total $ (33) $ (1) Bond Companies expense Operations and maintenance and depreciation expense, offset in revenues above $ 81 $ 35 Total $ 81 $ 35 Interest expense and other finance charges Changes in outstanding debt $ (55) $ (64) Other, primarily AFUDC and impacts of regulatory deferrals 3 7 Total $ (52) $ (57) Interest expense on Securitization Bonds Lower outstanding principal balance, offset in revenues above $ 5 $ 5 Total $ 5 $ 5 Other income, net Other income, including AFUDC - equity $ 9 $ 11 Bond Companies — 4 Total $ 9 $ 15 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, read “Risk Factors” in Item 1A of Part I of this report. The following table provides summary data of CERC’s single reportable segment: Year Ended December 31, Favorable (Unfavorable) 2024 2023 2022 2024 to 2023 2023 to 2022 (in millions, except throughput, weather and customer data) Revenues $ 3,925 $ 4,149 $ 4,800 $ (224) $ (651) Expenses: Utility natural gas 1,489 1,856 2,607 367 751 Non-utility cost of revenues, including natural gas 3 3 4 — 1 Operation and maintenance 848 904 886 56 (18) Depreciation and amortization 522 493 448 (29) (45) Taxes other than income taxes 234 243 257 9 14 Total expenses 3,096 3,499 4,202 403 703 Operating Income 829 650 598 179 52 Other Income (Expense): Gain on sale — — 557 — (557) Interest expense and other finance charges (197) (178) (130) (19) (48) Other income (expense), net 12 14 (64) (2) 78 Income Before Income Taxes 644 486 961 158 (475) Income tax expense (benefit) 104 (26) 236 (130) 262 Net Income $ 540 $ 512 $ 725 $ 28 $ (213) Throughput (in BCF): Residential 184 194 233 (5) % (17) % Commercial and Industrial 390 386 389 1 % (1) % Total Throughput 574 580 622 (1) % (7) % Weather (percentage of 10-year average for service area): Heating degree days 78 % 86 % 106 % (8) % (20) % Number of metered customers at end of period: Residential 3,958,584 3,905,388 3,859,726 1 % 1 % Commercial and Industrial 293,959 293,235 291,184 — % 1 % Total 4,252,543 4,198,623 4,150,910 1 % 1 % 65 The following table provides variance explanations by major income statement caption for CERC: Favorable (Unfavorable) 2024 to 2023 2023 to 2022 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (367) $ (728) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — (38) Gross receipts tax, offset in taxes other than income taxes below 1 (15) Weather and usage (9) (7) Energy efficiency and other pass-through, offset in operation and maintenance below (10) 8 Non-volumetric and miscellaneous revenue (6) 13 Non-utility revenues 15 18 Customer growth 13 20 Customer rates 139 78 Total $ (224) $ (651) Utility natural gas Cost of natural gas, offset in revenues above $ 367 $ 728 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 23 Total $ 367 $ 751 Non-utility costs of revenues, including natural gas Other, primarily non-utility cost of revenues $ — $ 1 Total $ — $ 1 Operation and maintenance All other operations and maintenance expenses, including bad debt expense $ 21 $ (36) Energy efficiency and other pass-through, offset in revenues above 10 (8) Contract services (6) — Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3 Labor and benefits 8 11 Corporate support services 23 12 Total $ 56 $ (18) Depreciation and amortization Ongoing additions to plant-in-service $ (29) $ (47) Indiana lower depreciation rates from recent rate order — — Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 2 Total $ (29) $ (45) Taxes other than income taxes Gross receipts tax, offset in revenues above $ (1) $ 15 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 1 Incremental capital projects placed in service, and the impact of updated property tax rates 10 (2) Total $ 9 $ 14 Gain on sale Net gain on sale of Arkansas and Oklahoma Natural Gas businesses $ — $ (557) Total $ — $ (557) Interest expense and other finance charges Changes in outstanding debt $ (11) $ (56) Other, primarily AFUDC and impacts of regulatory deferrals (8) 8 Total $ (19) $ (48) Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 3 $ 60 Other income, including AFUDC - Equity 3 9 Other (8) 9 Total $ (2) $ 78 66 Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 13 to the consolidated financial statements. LIQUIDITY AND CAPITAL RESOURCES Cash Flows The following table summarizes the Registrants’ cash flows by category for the periods presented: Year Ended December 31, 2024 2023 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Cash provided by (used in): Operating activities $ 2,139 $ 960 $ 1,068 $ 3,877 $ 1,401 $ 2,312 $ 1,810 $ 966 $ 856 Investing activities (4,489) (2,767) (1,419) (4,233) (2,503) (1,643) (1,628) (2,435) 406 Financing activities 2,271 1,732 352 374 1,103 (668) (345) 1,324 (1,277) Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities: 2024 compared to 2023 2023 compared to 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Changes in net income after adjusting for non-cash items $ 315 $ (132) $ 153 $ 394 $ 235 $ 170 Changes in working capital (134) 195 (83) 917 229 358 Changes in current regulatory assets and liabilities (1) (1,238) (4) (1,183) 1,085 26 986 Changes in non-current regulatory assets and liabilities (535) (472) (85) (276) (115) (78) Lower pension contribution 2 — — 3 — — Other (148) (28) (46) (56) 60 20 $ (1,738) $ (441) $ (1,244) $ 2,067 $ 435 $ 1,456 (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: 2024 compared to 2023 2023 compared to 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Proceeds from the sale of equity securities $ — $ — $ — $ (702) $ — $ — Net change in capital expenditures (112) (363) 180 18 157 42 Net change in notes receivable from affiliated companies — 108 2 — (238) (1) Proceeds from divestitures (144) — — (1,931) — (2,075) Other — (9) 42 10 13 (15) $ (256) $ (264) $ 224 $ (2,605) $ (68) $ (2,049) 67 Financing Activities. The following items contributed to (increased) decreased net cash provided by (used in) financing activities: 2024 compared to 2023 2023 compared to 2022 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Net changes in commercial paper outstanding $ 516 $ — $ 436 $ (981) $ — $ (227) Net changes in proceeds from issuance of Common Stock 494 — — — — — Net changes in long-term debt and term loans outstanding, excluding commercial paper 51 (6) 725 2,560 373 (778) Net changes in debt and equity issuance costs 20 5 11 (19) 4 — Net changes in short-term borrowings 6 — 6 (462) — (462) Redemption of Series A Preferred Stock 800 — — (800) — — Increased payment of Common Stock dividends (37) — — (45) — — Decreased (increased) payment of preferred stock dividends 50 — — (1) — — Payment of obligation for finance lease — — — 485 485 — Net change in notes payable from affiliated companies — 642 — — (772) 1,517 Change in contribution from parent — (41) (210) — (258) 211 Change in dividend to parent — 28 54 — (51) 348 Other (3) 1 (2) (18) (2) — $ 1,897 $ 629 $ 1,020 $ 719 $ (221) $ 609 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. Capital expenditures (other than expenditures associated with the May 2024 Storm Events and Hurricane Beryl) are expected to be used for investment in infrastructure. These capital expenditures are anticipated to enhance reliability and safety, increase resiliency and expand our systems through value-added projects. Substantial capital expenditures are also expected for restoration costs associated with Hurricane Beryl, as further described below. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2025 include the following: CenterPoint Energy Houston Electric CERC (in millions) Estimated capital expenditures (1) $ 4,802 $ 2,560 $ 1,391 Estimated restoration costs associated with May 2024 Storm Events (2) 34 34 — Estimated restoration costs associated with Hurricane Beryl (2) 102 102 — Scheduled principal payments on Securitization Bonds 13 — — Expected contributions to pension plans and other postretirement plans 120 1 5 (1) Excludes expenditures for the restoration costs associated with the May 2024 Storm Events and Hurricane Beryl. (2) Represents cash requirements associated with estimated storm restoration costs for 2025. The Registrants expect that anticipated cash needs for 2025 will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, including the issuance of non-recourse securitization bonds at Houston Electric related to costs incurred during the year ended December 31, 2024 due to the May 2024 Storm Events and Hurricane Beryl, anticipated cash flows from operations, and, with respect to CenterPoint Energy and CERC, proceeds from commercial paper and the sale of the Louisiana and Mississippi natural gas LDC businesses, if and when completed (the transaction is expected to close in the first quarter of 2025). Issuances of debt securities in the capital markets, funds raised in the commercial paper markets, term loans and additional credit facilities 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. For more information regarding the May 2024 Storm Events and Hurricane Beryl, see Notes 7, 12 and 14 to the consolidated financial statements as well as “Risk Factors” in Part I, Item 1A of this report. 68 The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for 2025 through 2029. See Note 16 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2024. 2025 2026 2027 2028 2029 CenterPoint Energy (in millions) Electric $ 3,306 $ 4,358 $ 4,266 $ 4,106 $ 2,728 Natural Gas 1,465 1,604 1,469 1,344 1,327 Corporate and Other 31 20 20 20 20 Total $ 4,802 $ 5,982 $ 5,755 $ 5,470 $ 4,075 Houston Electric (1) $ 2,560 $ 3,432 $ 4,008 $ 3,904 $ 2,546 CERC (1) $ 1,391 $ 1,486 $ 1,391 $ 1,271 $ 1,254 (1) Houston Electric and CERC each consist of a single reportable segment. Capital Expenditures for Climate-Related Projects . As part of its approximately $47.5 billion 10-year capital expenditure plan, which concludes in 2030, CenterPoint Energy anticipates spending over $3 billion in lower-emissions energy investments and enablement, which may be used to support, among other things, renewable energy generation. The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2024: 2025 2026 2027 2028 2029 Thereafter Total (in millions) CenterPoint Energy Securitization Bonds (1) $ 13 $ 14 $ 14 $ 15 $ 16 $ 252 $ 324 Other long-term debt (1) (2) 51 2,260 1,306 2,048 919 13,738 20,322 Interest payments — Securitization Bonds (3) 16 16 15 14 13 85 159 Interest payments — other long-term debt (3) 967 937 852 771 671 7,596 11,794 Short-term borrowings 500 — — — — — 500 Commodity and other commitments (4) 805 822 664 578 555 3,059 6,483 Total cash requirements $ 2,352 $ 4,049 $ 2,851 $ 3,426 $ 2,174 $ 24,730 $ 39,582 Houston Electric Other long-term debt (1) $ — 300 $ 300 $ 500 $ — $ 7,313 $ 8,413 Interest payments — other long-term debt (3) 378 351 339 335 309 3,809 5,521 Short-term borrowings 500 — — — — — 500 Total cash requirements $ 878 $ 651 $ 639 $ 835 $ 309 $ 11,122 $ 14,434 CERC Long-term debt (1) $ 10 $ 60 $ 625 $ 1,230 $ 30 $ 3,260 $ 5,215 Interest payments — long-term debt (3) 251 250 246 188 156 1,071 2,162 Commodity and other commitments (4) 631 597 513 470 456 1,544 4,211 Total cash requirements $ 892 $ 907 $ 1,384 $ 1,888 $ 642 $ 5,875 $ 11,588 (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 $9 million as of December 31, 2024. 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 ($558 million as of December 31, 2024), 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, 2024. 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: 69 • estimated future payments for expected future AROs primarily estimated to be incurred after 2029. See Note 3(c) to the consolidated financial statements for further information. • expected contributions to pension plans and other postretirement plans in 2025. 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(c) to the consolidated financial statements) and short-term leases, the Registrants have no off-balance sheet arrangements. Regulatory Matters Houston Electric TEEEF For information about Houston Electric’s TEEEF, see Note 7 to the consolidated financial statements. Hurricane Beryl For information about Hurricane Beryl, see Note 7 to the consolidated financial statements. May 2024 Storm Events For information about May 2024 Storm Events, see Note 7 to the consolidated financial statements. February 2021 Winter Storm Event 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 On February 23, 2021, Indiana Electric filed a CPCN with the IURC seeking approval to purchase the Posey Solar project. On October 27, 2021, the IURC issued an order approving the CPCN, authorizing Indiana Electric to purchase the Posey Solar project through a BTA to acquire its solar array assets for a fixed purchase price and approved recovery of costs via a levelized rate over the anticipated 35-year life. Due to community feedback and rising project costs caused by inflation and supply chain issues affecting the energy industry, Indiana Electric, along with Arevon, the developer, announced plans in January 2022 to downsize the Posey Solar project to 191 MW. Indiana Electric collaboratively agreed to the scope change, and on February 1, 2023, Indiana Electric entered into an amended and restated BTA that was contingent on further IURC review and approval. On February 7, 2023, Indiana Electric filed a CPCN with the IURC to approve the amended BTA. With the passage of the IRA, Indiana Electric can now pursue PTCs for solar projects. 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. The Posey Solar project is expected to be placed in service in the second quarter of 2025 and recovered through base rates. On July 5, 2022, Indiana Electric entered into a BTA to acquire a 130 MW solar array in Pike County, Indiana through a special purpose entity for a capped purchase price. A CPCN for the project was filed with the IURC on July 29, 2022. On September 21, 2022, an agreement in principle was reached resolving all the issues between Indiana Electric and OUCC. The Stipulation and Settlement agreement was filed on October 6, 2022 and a settlement hearing was held on November 1, 2022. On January 11, 2023, the IURC issued an order approving the settlement agreement authorizing Indiana Electric to purchase and acquire the Pike County Solar project through a BTA and approved the estimated cost. The IURC also designated the 70 project as a clean energy project under applicable Indiana regulations, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs exceeded the agreed upon levels in the BTA. After negotiations, Indiana Electric and the developer were not able to agree upon updated pricing. As a result, on March 15, 2024, Indiana Electric provided notice to the IURC that it was exercising its right to terminate the BTA, which terminated all further obligations of Indiana Electric with respect to the project. On January 10, 2023, Indiana Electric filed a CPCN with the IURC to acquire a wind energy generating facility with installed capacity of 200 MWs through a BTA, consistent with its 2019/2020 IRP that calls for up to 300 MWs of wind generation. The wind project is located in MISO’s Central Region. Indiana Electric received approval from the IURC to recover the costs of the wind facility via the CECA mechanism, which the developer believes can be placed in service by the end of 2026. On June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing Indiana Electric to purchase the wind generating facility. However, as of the date of the filing of this Form 10-K, Indiana Electric has not entered into any definitive agreement relating to this wind energy generating facility, and it is not certain that a definitive agreement will be entered into at all. PPAs Indiana Electric also 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 provides 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 were compelled to renegotiate terms of the agreement to increase the PPA price. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved PPA with certain modifications. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026. 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 interconnection study were completed, Origis advised Indiana Electric that the costs to construct the solar project in Knox County, Indiana had increased. The increase was largely driven by 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 previously approved Knox County solar 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 will be delayed to 2026. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved Vermillion County solar PPA with Oriden with certain modifications. Revised purchase power costs were approved to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. 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 2026. 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 early 2026. Natural Gas Combustion Turbines 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 estimated $334 million turbine facility is being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and is expected to provide a combined output of 460 MW. 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 will be constructed and 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 the 71 FERC’s order granting the certificate. Indiana Electric granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. The facility is targeted to be operational by mid-year 2025. On February 6, 2025, the EPC contractor for Indiana Electric’s proposed natural gas combustion turbines provided a notice to Indiana Electric that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. Recovery of the proposed natural gas combustion turbines and regulatory asset was included in the forecasted test year in the Indiana Electric rate case, which was filed with the IURC on December 5, 2023. For more information on the Indiana Electric rate case, see “— Rate Change Applications” below. For more information regarding uncertainties related to our solar projects, see Part I, Item 1A of this combined Form 10-K and “ —Solar Panel Issues” below. Culley Unit 3 Operations In June 2022, F.B. Culley Unit 3, an Indiana Electric coal-fired electric generation unit with an installed generating capacity of 270 MW, experienced an operating issue relating to its boiler feed pump turbine. The unit returned to service in March 2023. In testimony filed September 13, 2023, the OUCC and an intervenor that represents industrial customers filed testimony with the IURC alleging that Indiana Electric did not act prudently which led to the unplanned outage and recommended disallowances between $21 million to $27 million. On July 3, 2024, the IURC issued an order finding Indiana Electric acted reasonably and prudently with respect to the events that gave rise to the Culley Unit 3 outage and, in addition, did not approve the intervenors proposed disallowance. The order is now final and non-appealable. 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 half of 2026. 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, 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 second 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 first half of 2027. Texas Legislation (CenterPoint Energy, Houston Electric and CERC) Houston Electric and CERC were affected by legislation passed in 2023 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 88th Texas Legislature, including: • House Bill 1500 became effective on September 1, 2023 and continues the functions of the PUCT, the Office of Public Utility Counsel, and ERCOT through 2029. This bill also includes an amendment that clarifies the use cases under which TDUs may lease and operate temporary generation during “significant” power outages; 72 • House Bill 2263 became effective on June 12, 2023 and authorizes LDCs to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority; • House Bill 2555 became effective on June 13, 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity, physical security, vegetation management and wildfire mitigation. On January 18, 2024, the PUCT issued an Order adopting its Resiliency Plan Rule (16 Tex. Admin. Code § 25.62); • Senate Bill 947 became effective on September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages; • Senate Bill 1015 became effective on June 18, 2023 and allows utilities to file the DCRF twice a year, on any day the PUCT is open (at least 185 days after filing a full base rate proceeding) and setting an administrative approval timeline of 60 days; • Senate Bill 1016 became effective on May 5, 2023 and requires the PUCT to presume that all employee compensation and benefits are reasonable and necessary when establishing a utility’s rates if based upon market compensation studies issued within the last three years; it includes exceptions for utility officer incentives that are based on financial metrics. Certain incentive compensation that is in-line with market studies will be presumed reasonable and recoverable; and • Senate Bill 1076 became effective on June 2, 2023 and moves the timeline for the PUCT to approve CCN for transmission projects to 180 days after the date of filing, rather than the first anniversary of the day it was filed. The Registrants will monitor the 89th Texas Legislature for legislation that may impact their businesses. Minnesota Legislation (CenterPoint Energy and CERC) The Natural Gas Innovation Act was passed by the Minnesota legislature in June 2021 with bipartisan support. This law establishes a regulatory framework to enable the state’s investor-owned natural gas utilities to provide customers with access to renewable energy resources and innovative technologies, with the goal of reducing GHG emissions and advancing the state’s clean energy future. The maximum allowable cost for an innovation plan will start at 1.75% of the utility's revenue in the state and could increase to 4% by 2033, subject to review and approval by the MPUC. Specifically, the Natural Gas Innovation Act allows a natural gas utility to submit an innovation plan for approval by the MPUC that can propose the use of renewable energy resources and innovative technologies such as: • renewable natural gas (produces energy from organic materials such as wastewater, agricultural manure, food waste, agricultural or forest waste); • renewable hydrogen gas (produces energy from water through electrolysis with renewable electricity such as solar); • energy efficiency measures (avoids energy consumption in excess of the utility’s existing conservation programs); and • innovative technologies (reduces or avoids GHG emissions using technologies such as carbon capture). On June 28, 2023, CERC submitted its first innovation plan to the MPUC; the five-year plan includes 18 pilot projects and seven smaller research-and-development projects. These projects will deploy and evaluate a broad array of innovative resources including made-in-Minnesota alternative gases such as renewable natural gas and green hydrogen, as well as pioneering technologies such as a networked geothermal district energy system and end-use carbon capture. The proposed plan requires approval from the MPUC through a review process that is expected to take about one year. The MPUC requested comments by September 15, 2023 if parties believe that the filing is incomplete based on the reporting requirements or if parties do not believe that that the MPUC’s standard informal proceeding process is appropriate. No parties filed comments regarding completeness or raising concerns that the MPUC’s standard informal procedural process is inappropriate. The initial comment period closed on January 15, 2024, the reply comment period closed on March 15, 2024 and the supplemental comment period closed on May 15, 2024. On July 25, 2024, the MPUC voted to approve the plan with some minor modifications during its agenda meeting and a formal order was issued on October 9, 2024. Solar Panel Issues (CenterPoint Energy) CenterPoint Energy’s current and future solar projects have been impacted by delays and/or increased costs. The potential delays and inflationary cost pressures communicated from the developers of our solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to DOC antidumping and countervailing duties investigation(s), (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the 73 initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam. On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates. A final determination is expected in the first quarter of 2025. On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. A final determination is expected in the second quarter of 2025. These impacts could result in cost increases for certain projects, and such impacts may require that we seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects. For more information regarding potential delays, cancellations and supply chain disruptions, see “Part I, Item 1A. Risk Factors— Risk Factors Affecting Operations — Electric Generation, Transmission and Distribution — Increases in the cost or...” in this report. TDSIC 2.0 (CenterPoint Energy) On May 24, 2023, Indiana Electric filed its petition and case-in-chief with the IURC requesting, among other things, approval of its five-year plan for transmission, distribution, and storage improvements (TDSIC Plan) and an order approving the TDSIC Plan was issued on December 27, 2023. The approved five-year TDSIC Plan, covering the period January 1, 2024 through December 31, 2028, consists of approximately $454 million in proposed investments across seven different programs: (1) Distribution 12kV Circuit Rebuild, (2) Distribution Underground Rebuild, (3) Distribution Automation, (4) Wood Pole Replacement, (5) Transmission Line Rebuild, (6) Substation Rebuild, and (7) Substation Physical Security. Transmission and Distribution System Resiliency Plans (CenterPoint Energy and Houston Electric) House Bill 2555, codified as Tex. Util. Code § 38.078, was passed by the 88th Texas Legislature in 2023 and allows an electric utility to file a transmission and distribution system resiliency plan with the PUCT to enhance the resiliency of the utility’s transmission system through at least one or more of the following measures: hardening, modernization, undergrounding certain lines, lightning mitigation measures, flood mitigation measures, information technology, cybersecurity measures, physical security measures, vegetation management, and wildfire mitigation and response. House Bill 2555 also allows an electric utility to establish a regulatory asset for distribution-related costs, including depreciation expense and carrying costs at the electric utility’s weighted average cost of capital, relating to the implementation of a transmission and distribution system resiliency plan. On April 29, 2024, Houston Electric filed its first transmission and distribution system resiliency plan with the PUCT, which proposed to implement 25 resiliency measures over a three-year period. On August 1, 2024, Houston Electric announced that it was withdrawing its application for approval of its transmission and distribution system resiliency plan in order to focus on addressing the impacts of Hurricane Beryl and accelerating preparedness and resiliency efforts for the remaining storm season. The ALJ granted Houston Electric’s request for withdrawal of the transmission and distribution system resiliency plan on August 16, 2024. Following feedback from customers, external experts and other stakeholders, including elected officials and local agencies, Houston Electric filed the SRP with the PUCT on January 31, 2025 for review and approval. Anticipated to benefit Houston Electric customers by saving approximately 1.3 billion customer minutes of interruption, the SRP proposes 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 proposes 39 resiliency-enhancing measures and a microgrid pilot program to be implemented over the three-year period. The SRP has 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 is for transmission-related investments, and approximately $3.58 billion is for distribution-related investments. 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 cost of service adjustments (e.g., RSP and RRA), their decoupling mechanism (e.g., decoupling and SRC), and their energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR). 74 Texas Gas Rate Case. On October 30, 2023, CERC filed an application with the Railroad Commission and municipal regulatory authorities to set new natural gas base rates that would be applied consistently across the approximately 1.9 million customers. The need for a rate change was primarily driven by the 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. A settlement agreement was filed on April 23, 2024. The settlement agreement was approved by the Railroad Commission on June 25, 2024 and provides for a $5 million annual increase in current revenues and establishes a 9.80% ROE and a 60.61% equity ratio for future GRIP filings. New rates became effective in December 2024. 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 is approximately 6.5% or $85 million for 2024 and an additional approximately 3.7% or $52 million for 2025. The need for a rate change is primarily driven by the 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 reflects 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. The settlement 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 Administrative Law Judge filed a report on February 13, 2025 recommending the Commission approve the settlement agreement. The anticipated decision date of the rate case is July 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 is approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase is 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 reflects 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 approves 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 is 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 is primarily driven by the 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 ref