CENTERPOINT ENERGY INC 10-K

cnp-20231231 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 , 2023 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, 2023 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) $ 18,251,183,835 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 12, 2024: CenterPoint Energy, Inc. 631,594,706 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 2024 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2023, 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 38 Item 1C. Cybersecurity 38 Item 2. Properties 40 Item 3. Legal Proceedings 43 Item 4. Mine Safety Disclosures 43 PART II Item 5. Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 43 Item 6. [Reserved] 44 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 44 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 82 Item 8. Financial Statements and Supplementary Data 84 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 172 Item 9A. Controls and Procedures 172 Item 9B. Other Information 175 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 175 PART III Item 10. Directors, Executive Officers and Corporate Governance 176 Item 11. Executive Compensation 176 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 177 Item 13. Certain Relationships and Related Transactions, and Director Independence 177 Item 14. Principal Accounting Fees and Services 177 PART IV Item 15. Exhibits and Financial Statement Schedules 178 Item 16. Form 10-K Summary 178 i GLOSSARY ACE Affordable Clean Energy AFUDC Allowance for funds used during construction AGC Alcoa Generating Corporation, a subsidiary of Alcoa, Inc. AI Artificial intelligence 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 AT&T Inc. AT&T Common AT&T common stock ATM Forward Purchasers Bank of America, N.A., Barclays Bank PLC, Citibank, N.A., Goldman Sachs & Co. LLC, JPMorgan Chase Bank, National Association, Mizuho Markets Americas LLC, MUFG Securities EMEA plc and Royal Bank of Canada ATM Forward Sellers BofA Securities, Inc. Barclays Capital Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc. and RBC Capital Markets, LLC ATM Managers BofA Securities, Inc., Barclays Capital Inc., Citigroup Global Markets Inc., Goldman Sachs & Co. LLC, J.P. Morgan Securities LLC, Mizuho Securities USA LLC, MUFG Securities Americas Inc. and RBC Capital Markets, LLC Bcf Billion cubic feet Board CenterPoint Energy’s Board of Directors Bond Companies 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 CERC Corp. CenterPoint Energy Resources Corp. CERC CERC Corp., together with its subsidiaries CERCLA Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended CES CenterPoint Energy Services, Inc. (now known as Symmetry Energy Solutions, LLC), previously a wholly-owned subsidiary of CERC Corp. until its divestiture on June 1, 2020 Charter Common Charter Communications, Inc. common stock CIP Conservation Improvement Program CNG Compressed natural gas 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 Compensation Committee Compensation Committee of the Board ii GLOSSARY Convertible Notes CenterPoint Energy’s 4.25% Convertible Senior Notes due 2026 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 CPP Clean Power Plan CSIA Compliance and System Improvement Adjustment DCRF Distribution Cost Recovery Factor DE&I Council Diversity, Equity and Inclusion Council 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 Elk GP Merger Sub Elk GP Merger Sub LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Energy Transfer Elk Merger Sub Elk Merger Sub LLC, a Delaware limited liability company and a direct wholly-owned subsidiary of Energy Transfer Enable Enable Midstream Partners, LP Enable Common Units Enable common units, representing limited partnership interests in Enable Enable GP Enable GP, LLC, a Delaware limited liability company and the general partner of Enable Enable Merger The merger of Elk Merger Sub with and into Enable and the merger of Elk GP Merger Sub with and into Enable GP, in each case on the terms and subject to the conditions set forth in the Enable Merger Agreement, with Enable and Enable GP surviving as wholly-owned subsidiaries of Energy Transfer, which closed on December 2, 2021 Enable Merger Agreement Agreement and Plan of Merger by and among Energy Transfer, Elk Merger Sub, Elk GP Merger Sub, Enable, Enable GP and, solely for the purposes of Section 2.1(a)(i) therein, Energy Transfer GP, and solely for the purposes of Section 1.1(b)(i) therein, CenterPoint Energy Enable Series A Preferred Units Enable’s 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units, representing limited partner interests in Enable Energy Services Offered competitive variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and natural gas utilities through CES and CEIP Energy Services Disposal Group Substantially all of the businesses within CenterPoint Energy’s and CERC’s Energy Services reporting unit that were sold under the Equity Purchase Agreement Energy Systems Group Energy Systems Group, LLC, 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 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 ERG Employee Resource Group ERO Electric Reliability Organization ESG Holdings Group ESG Holdings Group, LLC a Delaware limited liability company, and an affiliate of Oaktree Capital Management 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 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 GHG Greenhouse gases GRIP Gas Reliability Infrastructure Program GWh Gigawatt-hours HLPSA Hazardous Liquid Pipeline Safety Act of 1979 Houston Electric CenterPoint Energy Houston Electric, LLC and its subsidiaries HVAC Heating, ventilation and air conditioning IBEW International Brotherhood of Electrical Workers ICPA Inter-Company Power Agreement IDEM Indiana Department of Environmental Management Indiana Electric Operations of SIGECO’s electric transmission and distribution services, and includes its power generating and wholesale power operations Indiana Gas Indiana Gas Company, Inc., a wholly-owned subsidiary of CERC Corp. Indiana North Gas operations of Indiana Gas Indiana South Gas operations of SIGECO Indiana Utilities Indiana Electric, Indiana North and Indiana South, collectively IRA Inflation Reduction Act of 2022 IRP Integrated Resource Plan IRS Internal Revenue Service IURC Indiana Utility Regulatory Commission 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 Utilities No. LA, LLC, a Delaware limited liability company, Delta Utilities S. LA, LLC, a Delaware limited liability company, Delta Utilities MS, LLC, a Delaware limited liability company, and Delta Shared Services Co., 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 MCRA MISO Cost and Revenue Adjustment iv GLOSSARY 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 Merger The merger of Merger Sub with and into Vectren on the terms and subject to the conditions set forth in the Merger Agreement, with Vectren continuing as the surviving corporation and as a wholly-owned subsidiary of CenterPoint Energy, Inc., which closed on the Merger Date Merger Agreement Agreement and Plan of Merger, dated as of April 21, 2018, among CenterPoint Energy, Vectren and Merger Sub Merger Date February 1, 2019 Merger Sub Pacer Merger Sub, Inc., an Indiana corporation and wholly-owned subsidiary of CenterPoint Energy MES CenterPoint Energy Mobile Energy Solutions, Inc. (now known as Mobile Energy Solutions, Inc.), previously a wholly-owned subsidiary of CERC Corp. MGP Manufactured gas plant MISO Midcontinent Independent System Operator MMBtu One million British thermal units MMcf Million cubic feet Moody’s Moody’s Investors Service, Inc. MPUC Minnesota Public Utilities Commission MPSC Mississippi Public Service Corporation Mva Megavolt amperes MW Megawatts 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 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 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, Houston Electric and CERC, collectively REP Retail electric provider Restoration Bond Company CenterPoint Energy Restoration Bond Company, LLC, a wholly-owned subsidiary of Houston Electric v GLOSSARY 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 Scope 1 emissions Direct source of emissions from a company’s operations Scope 2 emissions Indirect source of emissions from a company’s energy usage Scope 3 emissions Indirect source of 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 Series B Preferred Stock CenterPoint Energy’s previously outstanding 7.00% Series B Mandatory Convertible Preferred Stock, par value $0.01 per share, with a liquidation preference of $1,000 per share Series C Preferred Stock CenterPoint Energy’s previously outstanding Series C Mandatory Convertible 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 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 S&P S&P Global Ratings, a division of S&P Global Inc. SRC Sales Reconciliation Component TBD To be determined 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 mobile generation Texas RE Texas Reliability Entity Topic 326 Accounting Standards Update 2016-13 - Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments 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 the Merger Date, 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 Vistra Energy Corp. Texas-based energy company focused on the competitive energy and power generation markets. VRP Voluntary Remediation Program vi GLOSSARY 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 2022 Form 10-K Annual Report on Form 10-K for the fiscal year ended December 31, 2022 2022 Annuity Lift-Out 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. • 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. • 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. • 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. • 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 deployment of the resources (including the planning, execution and effectiveness of the same), regulatory and environmental requirements, and timely recovery of capital. 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 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 the implementation of and efforts to achieve its carbon emissions reduction goals. • We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolution adverse to us could negatively affect our financial results. 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. • 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 we are unable to arrange future financings on acceptable terms, our ability to finance our capital expenditures or refinance outstanding indebtedness could be limited. • 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. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. 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. General and Other Risks • Our revenues and results of operations are seasonal. • Climate change could adversely impact financial results from our businesses and result in more frequent and more severe weather events that could adversely affect 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. ix 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 other than itself or its subsidiaries. Except as discussed in Note 13 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, which, along with CenterPoint Energy, 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 Form 10-K, the terms “our,” “we” and “us” are used as abbreviated references to CenterPoint Energy, Inc. together with its consolidated subsidiaries. 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 facilities. As of December 31, 2023, CenterPoint Energy’s indirect, wholly-owned subsidiaries include: • 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 Companies are wholly-owned, bankruptcy remote entities formed solely for the purpose of purchasing and owning transition or system restoration 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 VEDO, 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. • 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, 2023, 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 17. 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. Discontinued Operations. From time to time, we consider the acquisition or the disposition of assets or businesses. For a discussion of discontinued operations and divestitures, see Note 4 to the consolidated financial statements. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 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 our Internet website 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 1 Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC. The SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, we make available free of charge on our 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, compensation, and governance, environmental and sustainability 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. Our website address is www.centerpointenergy.co m . 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 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 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, please read “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 generation generating facilities other than TEEEF. Electric Transmission On behalf of REPs, Houston Electric delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kV in locations throughout Houston Electric’s certificated service territory. Houston Electric constructs and maintains transmission facilities and provides transmission services under tariffs approved by the PUCT. Electric Distribution Houston Electric’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer through distribution feeders. Houston Electric’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. Houston Electric provides distribution services under tariffs approved by the PUCT. PUCT rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the PUCT. 2 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 are repaid through charges imposed on customers in Houston Electric’s service territory. On August 15, 2022, Restoration Bond Company repaid in full its last outstanding system restoration bonds at maturity. For further discussion of the Securitization Bonds issued by Bond Company IV and the outstanding balances as of December 31, 2023 and 2022, see Note 13 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. It 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 17 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, 2023: REPs Residential Commercial/ Industrial Total Customers Texas gulf coast 65 2,455,309 308,226 2,763,535 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 certificate of convenience and necessity 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 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. 3 Indiana Electric (CenterPoint Energy) Indiana Electric consists of SIGECO’s electric transmission and distribution services, including its power generating and wholesale power operations. As of December 31, 2023, Indiana Electric supplied electric service to the following: Residential Commercial/Industrial Total Customers Southwestern Indiana 133,201 19,292 152,493 System Load Total load and the related reserve margin at the time of the system summer peak on August 25, 2023, is presented below in MW, except for reserve margin at peak. 2023 Total load at peak 1,020 Generating capability 1,205 Purchase supply (effective capacity) (1) 659 Interruptible contracts & direct load control 4 Total power supply capacity 1,868 Reserve margin at peak 83 % (1) Indiana Electric procured bi-lateral capacity contracts starting in the 2023-2024 MISO planning year to support the generation transition. 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 2022-2023 season of approximately 785 MW occurred on December 23, 2022. Solar Indiana Electric has entered into various PPAs to purchase solar power to meet its future generation needs as reported in the table below. PPA with Location Expected Date in Service Capacity (MW) Term (in Years) Clenera Warrick County, Indiana 2025 100 25 Oriden Vermillion County, Indiana 2025 185 15 Origis Knox County, Indiana 2025 150 20 435 For further information about Indiana Electric’s solar power activities, see “Item 2. Properties” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters” in Item 7 of Part II of this report, which discussion is incorporated herein by reference. Coal Purchases Coal for coal-fired generating stations has been supplied from operators of nearby coal mines as there are substantial coal reserves in the southern Indiana area. Major suppliers are those that account for greater than 10% of Indiana Electric’s coal purchases. For the year ended December 31, 2023, Sunrise LLC accounted for 98% of Indiana Electric’s coal purchases, with the remaining 2% being purchased from other suppliers. 4 The table below presents information related to coal purchases during the year ended December 31, 2023 and coal inventory as of December 31, 2023. (In tons, except average cost per ton) Coal purchased for generating electricity 1,945,593 Coal inventory as of December 31, 2023 345,784 Average cost of coal per ton $55.26 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 2023 (in GWh) Coal OVEC (1) Indiana and Ohio n/a 32 186 Wind Benton County Wind Farm, LLC Benton County, Indiana 2028 30 76 Wind Fowler Ridge II Wind Farm, LLC Benton/Tippecanoe Counties, Indiana 2029 50 116 112 378 (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 as well as other utilities in the region. Indiana Electric is an active participant in the MISO energy markets, where it bids its generation into the Day Ahead and Real Time markets and procures power for its retail customers at Locational Marginal Price 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, 2023 was as follows: In GWh Net purchases (1) 397 Net sales (2) 510 (1) Represents volume intervals when purchases from the MISO were in excess of generation sold to the MISO. (2) Represents volume intervals when sales to the MISO were in excess of purchases from the MISO. Interconnections As of December 31, 2023, 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 and its own transmission assets to the MISO. Indiana Electric, in conjunction with the MISO, must operate the bulk electric transmission system in accordance with NERC Reliability Standards. As a result, interchange capability varies based on regional transmission system configuration, generation dispatch, seasonal facility ratings and other factors. Indiana Electric is in compliance with reliability standards promulgated by NERC. 5 SIGECO Securitization Subsidiary SIGECO has a 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 in the second quarter of 2023 associated with the completed retirement of SIGECO’s A.B. Brown coal generation facilities through the issuance of SIGECO Securitization Bonds. 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, 2023, see Note 13 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, 2023. For information regarding the properties of the Natural Gas reportable segment, please 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 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, 2023: Residential Commercial/ Industrial/Transportation Total Customers Indiana (Indiana Gas) 597,315 55,171 652,486 Louisiana 230,833 16,204 247,037 Minnesota 848,909 72,634 921,543 Mississippi 122,306 13,140 135,446 Ohio 308,622 24,543 333,165 Texas 1,797,403 111,543 1,908,946 Total CERC Natural Gas 3,905,388 293,235 4,198,623 Indiana (SIGECO) 104,725 10,606 115,331 Total CenterPoint Energy Natural Gas 4,010,113 303,841 4,313,954 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, 2023. CenterPoint Energy CERC Residential 32 % 33 % Commercial/Industrial and Transportation 68 % 67 % 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 2023, approximately 65% and 66%, respectively, of CenterPoint Energy’s and CERC’s Natural Gas total throughput occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during the colder months. Supply and Transportation In 2023, 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-year terms. 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, 2023 were as follows: CenterPoint Energy CERC Tenaska Marketing Ventures, LLC 39 % 44 % Macquarie Energy, LLC 15 % 19 % Koch Energy Services, LLC 8 % 10 % Total of major suppliers 62 % 73 % 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 ten 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 13 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. 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, 2023. 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 has 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. A proposed rule was published on May 18, 2023. Additional sections of the PIPES Act directed PHMSA to develop regulations requiring natural gas distribution operators to identify and address specific risks associated with piping materials with known issues. Over-pressurization, extreme weather and geohazards require certain actions associated with emergency response and require operators to identify and maintain certain records associated with system operating characteristics and controls. A proposed rule was published on September 7, 2023. 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. 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 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, 2023. 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. 11 To comply with these requirements, the Registrants may need to spend substantial amounts and devote other resources from time to time to, among other activities: • construct or acquire new facilities and equipment; • acquire permits for facility operations or purchase emissions allowances; • modify, upgrade or replace existing and proposed equipment; and • decommission or remediate waste management areas, fuel storage facilities and other locations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, revocation of permits, the imposition of remedial actions and monitoring and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to assess, clean up and restore sites where hazardous substances have been stored, disposed or released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and/or property damage allegedly caused by the release of hazardous substances or other waste products into the environment. 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. Global Climate Change 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. On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. On May 11, 2023, the EPA announced proposed emission limits and guidelines for carbon dioxide from fossil fuel-fired power plants under Section 111 of the Clean Air Act which, if finalized, apply new GHG performance standards for those existing coal-fired units expected to continue operation beyond December 31, 2029. We will continue to evaluate the applicability of the rule to the existing and new gas-fired generating units, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029. The Biden administration recommitted the United States to the Paris Agreement, which has driven a renewed regulatory push to require further GHG emission reductions from the energy sector. On April 22, 2021, President Biden 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, and most recently the international climate negotiations held in Dubai, and concluded in December 2023, included for the first time language in the agreement to “transition away from fossil fuels” so as to achieve net zero emissions by 2050. 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. Because Texas is an 12 unregulated market and customers choose their generation providers, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 emissions estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. These emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from the current and future administrations to further reduce GHG emissions. For more information regarding CenterPoint Energy’s net zero and carbon emission 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, and on December 2, 2023, the EPA finalized rules that target reductions in methane emissions, which are likely to increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than 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. 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. 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 fossil natural gas. Additionally, cities in Minnesota within CenterPoint Energy’s Natural Gas operational footprint are considering initiatives focused on electrification that could eliminate natural gas use in buildings. 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 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. 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 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. To the extent climate changes may occur and such climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding. Since many of the Registrants’ facilities are located along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes could increase costs to repair damaged facilities and restore service to customers. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted. 13 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 Under the Obama administration, the EPA promulgated a set of rules that included a comprehensive regulatory overhaul of defining “waters of the United States” for the purposes of determining federal jurisdiction. The Trump administration signaled its intent to repeal and replace the Obama-era rules. In accordance with this intent, the EPA promulgated a rule in early 2018 that postponed the effectiveness of the Obama-era rules until 2020. Thereafter, the EPA proposed a new set of rules that would narrow the Clean Water Act’s jurisdiction, which were finalized on April 21, 2020. That set of rules was vacated by decisions in the U.S. federal district courts in New Mexico and Arizona, and on November 18, 2021, the EPA released a proposal to reestablish the pre-2015 definition of “waters of the United States” which will become effective upon finalization and publication. 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, and on August 29, 2023, the EPA issued a final rule that seeks to conform with the U.S. Supreme Court decision. 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. These new standards are applied at the time of permit renewal and an affected facility must comply with the wastewater discharge limitations no later than December 31, 2023, and the prohibition of wet sluicing of bottom ash no later than December 31, 2025. In February 2019, the IURC approved Indiana Electric’s ELG compliance plan for its F.B. Culley Generating Station, which was completed in a timely manner and in compliance with the requirements of ELG . 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 in 2025. 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 14 as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters 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. The EPA continues to propose amendments to the CCR Rule; however, under the CCR Rule as it is currently in effect, 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 fail 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, please see Note 15(d) to the consolidated financial statements. On May 18, 2023, the EPA issued a proposed revision to the CCR rule that could potentially expand the scope of units regulated under the federal CCR rule (the CCR “Legacy” rule). The CCR Legacy rule seeks to include legacy CCR surface impoundments (inactive surface impoundments at inactive generating facilities) as well as new “CCR management units” at active or inactive facilities otherwise subject to federal CCR regulations. The potential impact of the CCR Legacy rule is uncertain at this time, and if finalized could require Registrant to conduct additional CCR investigations. Liability for Remediation CERCLA, also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of “hazardous substances” into the environment. Classes of PRPs include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is expressly excluded from CERCLA’s definition of a “hazardous substance,” in the course of the Registrants’ ordinary operations they do, from time to time, generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take action in response to threats to the public health or the environment and to recover the costs they incur from the responsible classes of persons. Under CERCLA, the Registrants could potentially be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for associated response and assessment costs, including for the costs of certain health studies. Liability for Preexisting Conditions For information about preexisting environmental matters, please see Note 15(d) to the consolidated financial statements. 15 HUMAN CAPITAL CenterPoint Energy believes its employees are critical to safely delivering electricity and natural gas across its service territories and seeks to create a diverse, equitable, inclusive 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, 2023: Number of Employees Number of Employees Represented by Collective Bargaining Groups Reportable Segment CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC Electric 3,132 2,781 — 1,659 1,472 — Natural Gas 3,705 — 3,393 1,695 — 1,639 Corporate and Other (1) 1,990 — — 147 — — Total 8,827 2,781 3,393 3,501 1,472 1,639 (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 19 to the consolidated financial statements. CenterPoint Energy’s workforce includes 3,501 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 maintain a workforce reflective of the available workforce within the communities we serve by attracting quality candidates through its recruitment and selection processes, with the goal of creating a work environment in which every employee is engaged; aligned with CenterPoint Energy’s strategy, goals and priorities; and understands how they contribute to its long-term performance. CenterPoint Energy recruits qualified employees regardless of race, gender, color, sexual orientation, age, religion, or physical or mental disability. The talent acquisition team has an increased focus with local partnerships to strategically impact all the local communities being served. This continues to include SERJobs, Houston Area Urban League, Work Texas, Wesley Community Center, Historically Black Colleges and Universities, Hispanic Serving Institutions, and a more robust college partnership in all six states in alignment with CenterPoint Energy Foundation initiatives. 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 strategy. To support its commitment to safely and reliably delivering electricity and natural gas, CenterPoint Energy focuses on the continuous development of its greatest assets, its employees, building 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. Diversity, Equity and Inclusion. CenterPoint Energy is dedicated to advancing an inclusive culture and work environment, free from discrimination of any kind, where business results are achieved through the skills, abilities and talents of a diverse workforce. In 2023, CenterPoint Energy’s DE&I Council continued to focus on the strategic pillars of employee engagement, community and giving, supplier diversity and sustainability, talent acquisition, and customer focus. The DE&I Council has approved eight ERGs with a 123% increase in events that garnered an 87% increase in employee engagement from 2022 to 2023. The ERG events range from professional development podcasts to wellness learnings which are all aligned with CenterPoint Energy’s objectives. These events are available to the employee population. In 2023, CenterPoint Energy and employees continued to be recognized locally, regionally and nationally for enterprise-wide inclusive initiatives. As of December 31, 2023, CenterPoint Energy’s workforce was 42% racially and/or ethnically diverse. Certain members of 16 CenterPoint Energy’s executive management team have a negative-only modifier related to diversity metrics that could reduce their short-term incentive compensation. Compensation and Benefits. CenterPoint Energy is committed to providing its employees with competitive pay and benefits. Its compensation philosophy is to maintain employee total compensation that is competitive with the relevant markets, internally equitable, and based on company and individual performance. CenterPoint Energy expects that this will enable it to attract, motivate and retain employees with the skills and competencies necessary to achieve its business strategy. In addition to competitive compensation, CenterPoint Energy provides its employees with a robust, 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, family leave, well-being and employee assistance programs. The employee wellness resources encompass support for mental, financial and physical health. INFORMATION ABOUT OUR EXECUTIVE OFFICERS (as of February 12, 2024) Name Age Title Jason P. Wells 46 President and Chief Executive Officer Christopher A. Foster 45 Executive Vice President and Chief Financial Officer Lynne Harkel-Rumford 67 Executive Vice President and Chief Human Resources Officer Monica Karuturi 45 Executive Vice President and General Counsel Jason M. Ryan 48 Executive Vice President, Regulatory Services and Government Affairs Darin Carroll 47 Senior Vice President, Natural Gas Business Lynnae Wilson 48 Senior Vice President, Electric 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, Bauer College Board of the C.T. Bauer College of Business at the University of Houston, 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, has 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, since March 2021. 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. Lynne Harkel-Rumford has served as Executive Vice President and Chief Human Resources Officer of CenterPoint Energy since January 2022. With over 30 years of experience in compensation and benefits matters, Ms. Harkel-Rumford previously served as Senior Vice President and Chief Human Resources Officer from July 2020 to January 2022; Vice President, Total Rewards and Technology from September 2014 to July 2020; and as Associate General Counsel from April 2007 to September 2014. Ms. Harkel-Rumford currently serves on the advisory board of directors of Target Hunger in Houston assisting with Board governance. 17 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; Senior 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 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 currently serves as Chair of the Houston Bar Foundation. 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; Senior Vice President and General Counsel from April 2019 to July 2020; as Senior Vice President, Regulatory and Government Affairs from February 2019 to April 2019; as Vice President of Regulatory and Government Affairs and Associate General Counsel from March 2017 to February 2019; and as Vice President and Associate General Counsel from September 2014 to March 2017. He was appointed to the Texas Diabetes Council by Texas Governor Perry in 2013 for a term ending in 2019; he was reappointed by Texas Governor Abbott in 2019 for a term ending in 2025. 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 Carroll has served as Senior Vice President, Natural Gas Business of CenterPoint Energy since January 2023. He previously served 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. Mr. Carroll currently serves on the Executive Committee and Board of Directors of the Junior Achievement of Southeast Texas, and the Boards of Directors of the American Gas Association and Southern Gas Association. He has also previously been on the Board of Directors of Guardianship Services of Southwestern Indiana and 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. Lynnae Wilson has served as Senior Vice President, Electric Business of CenterPoint Energy since January 2023. She previously served as Senior Vice President, Houston Electric from January 2022 to January 2023; as Senior Vice President, High Voltage Operations from August 2020 to January 2022; and as Chief Business Officer, Indiana Electric, from February 2019 to August 2020. Prior to Vectren’s acquisition by CenterPoint Energy, Ms. Wilson served as Vice President, Energy Delivery from June 2016 to February 2019 of Vectren. Ms. Wilson currently serves on the Board of the United Way of Greater Houston and previously served on the Board of ReliabilityFirst Corporation from January 2018 to December 2021. 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 and CERC, which, along with CenterPoint Energy, 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 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 their planning and preparation for such directives and their implementation of Load Shed, including, for example, allegations that they 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 and those purchases are currently being challenged at the IURC by multiple intervenors. 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 contracts expire and inflation rises; 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 the majority 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, due to 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, including inclement weather, natural disasters, mechanical failure, contact with electrified facilities by people, equipment, and debris, unscheduled downtime, equipment interruptions, contamination, remediation, explosions, fires, 19 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, and environmental damage, and may result in suspension of operations, disruption of service to customers, and the imposition of civil or criminal penalties. Houston Electric and Indiana Electric maintain property and casualty insurance but are not fully insured against all potential hazards incident to their businesses. 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, 2023, Houston Electric provided electric delivery service to approximately 65 REPs. Adverse economic conditions, including, but not limited to, the impact of COVID-19, 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, 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 from affiliates of NRG and Vistra Energy Corp. Houston Electric’s aggregate billed receivables balance from REPs as of December 31, 2023 was $253 million. Approximately 39% and 20% 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 capturing the amounts owed by these REPs as a permitted regulatory asset for bad debt expenses, which will be subject to a reasonableness review by the PUCT when we seek recovery in our next base rate case. As of both December 31, 2022 and 2021, as authorized by the PUCT, CenterPoint Energy and Houston Electric recorded a regulatory asset of $8 million for bad debt expenses resulting from REPs’ default on their obligation 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 ...” 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, and ultimately a goal to exit the coal plants that Indiana Electric operates by the end of 2027, as reflected in its most recent IRP submitted to the IURC in May 2023. 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 ensure cost recovery. Indiana Electric must manage several risks associated with its generation transition plan. The IURC may delay providing comments on Indiana Electric’s most recent IRP, requiring Indiana Electric to either wait for comments or proceed to 20 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. 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 carbon emission goals, its goal to exit the coal plants that Indiana Electric operates by the end of 2027, 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 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, the developers of a 130 MW Pike County Solar project have informed Indiana Electric that, due to delays in the MISO interconnection queue and inflationary pressures, costs have exceeded the agreed upon levels in the BTA. We and the developers are actively evaluating possible cost impacts to the project, which may lead to a refile for approval of the project with the IURC and further delay the completion of the project. If Indiana Electric is not able to reach a mutually acceptable solution with the developers of the Pike County Solar project, Indiana Electric may seek to terminate 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. 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. 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. 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. In addition, in December 2021, President Biden signed into law 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, any of which could further negatively impact the supply of solar panels. These or similar duties and legislation 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 forced to delay, downsize and/or cancel solar projects and we may not be able to procure the resources needed to fully execute on our ten-year capital plan or achieve our net zero emissions 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 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. 21 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 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, 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. 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 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 TEEEF (mobile generation). In 2023, the Texas legislature amended the law to allow wider use of TEEEF. If Houston Electric is unable to deploy a sufficient number of TEEEF resources in time to respond to a particular event; if TEEEF resources fail to perform as intended; if Houston Electric is otherwise 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. 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. As noted above, the legislation 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 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. Despite the recovery of these TEEEF costs in the past, there can be no assurances that Houston Electric will be able to recover future TEEEF costs. If Houston Electric is unable to recover any or all 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...” 22 The impact of wildfires could negatively affect Houston Electric’s and Indiana Electric’s financial condition, results of operations and cash flows. Wildfires have the potential to negatively affect communities within Houston Electric’s and Indiana Electric’s service territories and the surrounding areas, as well as Houston Electric’s and Indiana Electric’s vast network of electric transmission and distribution lines and facilities. The possibility of wildfires and the risk of damage to our network and facilities resulting therefrom may be exacerbated by severe weather events and the effects of climate change. For more information regarding climate related risks, see “ — Climate change could adversely impact ...” 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 assets, wildfire risk is always present. Houston Electric or Indiana Electric 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 Houston Electric or Indiana Electric. Wildfires could also lead to significant financial distress and further increased costs for wildfire insurance or lack of availability thereof. Furthermore, any damage caused to our assets, loss of service to our customers, or liability imposed as a result of wildfires could negatively impact Houston Electric’s or Indiana Electric’s financial condition, results of operations, and cash flows. 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 and cash flows. Additionally, a significant disruption, whether through reduced intrastate and interstate pipeline transmission or storage capacity 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 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. 23 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 and state commissions. 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. Indiana Electric and CERC each filed rate cases during 2023. Houston Electric and CERC, with respect to its Ohio gas territory, each plan to file a rate case 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 increasing inflation rates like those experienced in 2022 and continuing into 2023. For example, the MPUC ordered extraordinary gas costs incurred in the February 2021 Winter Storm Event be recovered over a 63-month period from 2022 — 2027 and CERC forego recovery of the associated carrying costs. Though several interim rate adjustment mechanisms have been approved by jurisdictional regulatory authorities and implemented by the Registrants and their subsidiaries to reduce the effects of regulatory lag (for example, CSIA, DCRF, DRR, DSMA, GRIP, RCRA, 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. 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. 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 24 “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. 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 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 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. 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 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, both nationally and internationally, regarding the possible means for their regulation. The trend in environmental regulation has been to place more restrictions and limitations on activities that may impact the environment. On April 22, 2021, President Biden 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 President Biden’s executive orders have 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. The administration is expected to finalize additional GHG regulations and mandated financial, emissions and other disclosures. 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. Also, 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 25 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’s current generating units substantially rely on coal for their operations, 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. This focus on environmental justice matters at the federal and state levels may also provide communities opposed to our operations with greater opportunities to challenge or delay our projects. Opposition to our projects or successful challenges or appeals to permits issued for our projects could result in cancellation of such projects and the loss of investments we have made with respect thereto. CenterPoint Energy is subject to operational and financial risks and liabilities associated with the implementation of and efforts to achieve its carbon 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 prove incorrect, its actual results and ability to achieve net zero emissions by 2035 could differ materially from its expectations. Certain of the assumptions that could impact CenterPoint Energy’s ability to meet its net zero emissions goals include, but are not limited to: emission levels, service territory size and capacity needs remaining in line with expectations; regulatory approvals related to Indiana Electric’s generation transition plan; customer demand for carbon free energy; impacts of future environmental regulations or legislation; 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 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 and the ability to appropriately estimate costs of new generation; impact of any supply chain disruptions; changes in applicable standards or methodologies; and enhancement of energy efficiencies. Our businesses may face increased scrutiny from investors and other stakeholders related to our sustainability activities, including the goals, targets, and objectives we announce, our methodologies and timelines for pursuing them, and related disclosures. If our sustainability practices do not align with investor or other stakeholder expectations and standards, which continue to evolve, 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 or fulfill our sustainability-focused goals, targets, and objectives, to comply with ethical, environmental, or other standards, regulations, or expectations, or to satisfy various reporting standards with respect to these matters, 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 26 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. Houston Electric and Indiana Electric, as a member of ERCOT and MISO, respectively, could be subject to higher costs for system improvements, as well as fines or other sanctions as a result of FERC mandatory reliability standards. 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 operational control over their transmission facilities and are subject to certain costs for improvements to these regional electric transmission systems. In addition, FERC has jurisdiction with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by Houston Electric and other utilities within ERCOT and Indiana Electric and other utilities within MISO, respectively. FERC has designated NERC as the ERO to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system. FERC has approved the delegation by NERC of authority for reliability in ERCOT to the Texas RE, a Texas non-profit corporation, and for reliability in the portion of MISO that includes Indiana Electric to 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. 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 15 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. 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 the COVID-19 pandemic, labor shortages, resource availability, long lead time, 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, 27 and we may continue to experience this in the future. 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/or achieve our net zero emission and carbon emissions reduction goals. Moreover, high inflation and persistent high interest rates continue to be an area of economic concern and has contributed to the increased prices for materials and services that have been experienced by us and other companies in our industry. 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 as a result of supply chain disruptions, our financial condition, results of operations and cash flows may 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 VEDO. As a result, CenterPoint Energy and to a lesser extent, CERC, depend on the performance of and distributions from their respective subsidiaries to meet their respective payment obligations and to pay dividends on their respective common stock. In general, CenterPoint Energy’s and CERC’s subsidiaries are separate and distinct legal entities and have no obligation to provide them with funds for their respective payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit CenterPoint Energy’s and CERC’s respective subsidiaries’ ability to make payments or other distributions to CenterPoint Energy or CERC, and their respective subsidiaries could agree to contractual restrictions on their ability to make payments or other distributions. Further, as part of Houston Electric’s 2019 base rate case, Houston Electric agreed to certain “ring-fencing” measures to increase its financial separateness from CenterPoint Energy. Houston Electric is expected to file a base rate proceeding in 2024. In this proceeding, Houston Electric may be requested to institute further ring-fencing measures or 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. 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, 2023, CenterPoint Energy had $19 billion of outstanding indebtedness on a consolidated basis, which includes $502 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 13 to the consolidated financial statements. 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; 28 • 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 2023 and to date in 2024 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’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 15(c) to the consolidated financial statements. An impairment of goodwill, long-lived assets, including intangible assets, equity method investments and an impairment or fair value adjustment could reduce our earnings. Long-lived assets, including intangible assets with finite useful lives, 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, 2023, 2022 and 2021. 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. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. CenterPoint Energy has approximately $828 million principal amount of ZENS outstanding as of December 31, 2023. 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 ($18 million in the aggregate, or $1.24 per ZENS, as of December 31, 2023), 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- 29 Related Securities continues to increase by the amount of the tax benefit realized each year. If the ZENS had been redeemed on December 31, 2023, deferred taxes of approximately $728 million would have been payable in 2023, based on 2023 tax rates in effect. In addition, if all the shares of ZENS-Related Securities had been sold on December 31, 2023 to fund the aggregate redemption amount, capital gains taxes of approximately $81 million would have been payable in 2023. Similarly, a significant amount of exchanges of ZENS by ZENS holders could adversely impact CenterPoint Energy’s cash flows. 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 carbon emission reductions goals. Our strategic goals are subject to the risks described in this section and various assumptions. These assumptions may be proven incorrect 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 businesses and assets, such as our proposed sale of our Louisiana and Mississippi natural gas local distribution companies, 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 or dispositions 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 or dispositions involve substantial risks, including the following: • acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels; • acquired businesses or assets 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 or dispositions, 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 or disposition 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 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 30 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, 2022 and 2021, 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 information and forecasts as of December 31, 2023, 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, 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 could be enacted that may significantly change the federal income tax laws applicable to domestic businesses, including changes that may increase the federal income tax rate and impact investment incentives and deductions for depreciation and interest, among other deductions. While CenterPoint Energy and its subsidiaries cannot assess the overall impact of any such potential legislation 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, 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 field employees 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 recruit and retain certain employees. 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. For example, the operation of our electric generation, transmission and distribution systems are dependent on not only physical interconnection of our facilities but also on communications among the various components of our systems and third-party systems. This reliance on information and communication between and among those components has increased since deployment of the intelligent grid, smart devices and operational technologies across our businesses. 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 are interconnected with external networks and facilities. For example, the operation of an efficient deregulated wholesale and retail electric market in Texas mandates communication with ERCOT, and competitive retailers; and our Indiana Electric organization has a similar relationship with MISO. Also, the distribution of natural gas to our customers requires communications with third-party 31 systems. Disruption of those communications, 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. 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. 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. We are not fully insured against all cybersecurity risks, any of which could adversely affect our reputation and could have an adverse effect on our financial condition, results of operations and cash flows. 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. 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. The TSA announced two new security directives in the second and third quarters of 2021. These directives required critical pipeline owners to comply with mandatory reporting measures, designate a cybersecurity coordinator, provide vulnerability assessments, and ensure compliance with certain cybersecurity requirements. In the third quarter of 2022, the TSA made significant updates to one of the security directives to require critical pipeline owners to establish and implement a TSA-approved Cybersecurity Implementation Plan, develop and maintain a Cybersecurity Incident Response Plan, and establish a Cybersecurity Assessment Plan. The TSA approved CenterPoint Energy’s Cybersecurity Implementation Plan in December 2022. The TSA further updated and renewed the pipeline security directive in July 2023 with updated requirements for Pipeline Cybersecurity Mitigation Actions, Contingency Planning, and Testing. CenterPoint Energy continues to take measures to comply with the TSA pipeline security directive requirements. 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. 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. 32 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. While we have implemented and maintain a cybersecurity program designed to protect our information technology, operational technology, and data systems from attacks, and while we have implemented and maintain a data privacy program designed to manage and protect personal information, neither program can prevent all security or 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 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 there can be no assurance that the use of AI will 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, toxicity, 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 AI may subject us to legal liability. Similarly, as AI continues to evolve we may not be able to adopt and implement AI as quickly as our customers or communities desire or regulators may require, which could also adversely affect us. AI is a relatively new and rapidly evolving technology, and we are unable to predict all of the risks that may result from the adoption of our AI initiatives. General and Other Risks Our revenues and results of operations are seasonal. 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 information related to weather normalization regulatory mechanisms and weather hedges, see Note 9(a) to the consolidated financial statements. For additional risks related to the February 2021 Winter Storm Event, see Note 7 to the consolidated financial statements for further information. 33 Climate change could adversely impact financial results from our businesses and result in more frequent and more severe weather events that could adversely affect 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, such as hurricanes, tornadoes, and severe winter weather conditions, including ice storms, all of which may impact our operations and ability to serve our customers. 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 or tornadoes could increase our costs to repair damaged facilities and restore service to our customers. Our Electric and Natural Gas operations in our service territories were both also impacted by the February 2021 Winter Storm Event and could experience a similar event in the future, which could have an adverse impact on 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, please 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 oil and gas 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, and other industries, including ours, could face such litigation in the future. For more information, see Note 7 to the consolidated financial statements, and “— CenterPoint Energy is subject to operational and financial risks...” We are exposed to risks related to reduction in energy consumption due to factors such as changes in customers’ perceptions from incidents of other utilities. 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. 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. 34 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, 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 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, propane-air 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 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, ice storms, flooding, terrorism, wildfires, pandemic health events 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. Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have an adverse effect on our financial condition, results of operations and cash flows. Such events have and may in the future result in the imposition of regulatory or environmental fines and increased litigation. 35 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 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/or 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. 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. Current and future health pandemics, epidemics and similar public health threats, such as COVID-19 and its variants, and the measures implemented to contain their spread, such as travel bans and restrictions, quarantines and vaccination mandates, continue to 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 a current or future health threat is uncertain, rapidly changing and hard to predict. Any future health threat, including the emergence of a new variant of COVID-19, could, in the future, impact our business in numerous ways, including, but not limited to, those outlined below: 36 • reduced demand from our commercial and industrial customers and shifts in demand for our services; • delayed service to customers because of shutdowns and/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, see above “Risks Affecting our 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 pursuant to 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 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 the COVID-19 pandemic, 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 the divestiture on June 30, 2023 or temporary employees, 18.7%, 19.3% and 23.6% were retirement eligible as of December 31, 2023, 2022 and 2021, respectively. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skillsets to future needs, 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 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 40% of our workforce. We have several separate bargaining units, each with a unique collective bargaining agreement described further in 37 Note 8(j) to the consolidated financial statements, which information is incorporated herein by reference. The collective bargaining agreements with Teamsters Local 135 related to SIGECO employees and Utility Workers Union of America, Local 175 related to VEDO employees are scheduled to expire in September 2024 and October 2024, 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. Managing Material Risks & Integrated Overall Risk Management As a foundation of this approach, we have implemented a layered governance structure to help assess, identify, and manage cybersecurity risks. It starts with our internal Cybersecurity Operations Center (CSOC), which routinely analyzes threat information from external sources, monitors network activity, and responds to potential security incidents. In addition, our cybersecurity and privacy policies encompass incident response procedures and information security governance. As part of our ongoing assessment of our cybersecurity program, we monitor and make adjustments, as necessary, in support of compliance with current and emerging cybersecurity and privacy laws, regulations and guidance applicable to us in jurisdictions where we do business (including NERC CIP reliability standards and TSA security directives), as further described in Item 1A “Risk Factors.” Our internal audit team conducts regular internal security audits and vulnerability assessments of CenterPoint Energy’s systems and user data security practices. In addition, CenterPoint Energy’s cybersecurity program is increasingly leveraging intelligence-sharing capabilities about emerging threats within the energy industry, across other industries, with specialized vendors, and through public-private partnerships with U.S. government intelligence agencies. By engaging with utility-specific organizations, CenterPoint Energy benefits from quality analysis and rapid sharing of security information across the energy sector. Such intelligence helps allow for better detection and prevention of emerging cyber threats before they materialize. Just as it tests its policies and plans internally, CenterPoint Energy also engages in external exercises such as the bi-annual GridEx Security Exercise to evaluate and address the preparedness of the industry as a whole. Oversee Third-Party Risk We conduct security risk assessments on proposed software, hardware, and third-party technology solutions used by CenterPoint Energy, including a diligence review of enterprise and security architecture, vendor security, and a privacy impact assessment when deemed appropriate. These assessments evaluate these technologies prior to deployment in CenterPoint Energy’s network environment. Further, we maintain a vendor risk management program, a component of which assesses the maturity of certain third parties and their cybersecurity and data privacy programs to help protect information shared with approved third parties. We also leverage third-party cybersecurity ratings of companies to inform our risk rating when conducting these assessments. Additionally, CenterPoint Energy imposes contractual obligations on vendors and other third-party business partners related to privacy, confidentiality, and data security based on their access to our data and systems and the nature and sensitivity of the data and systems. Such contractual provisions may specify the measures and safeguards that the parties must implement to protect our data from unauthorized access use, disclosure, modification, or destruction. Engage Third Parties on Risk Management We also undergo periodic external security audits, vulnerability assessments, and penetration testing of CenterPoint Energy’s systems and user data security practice, conducted by third-party consultants. We also conduct tabletop exercises to 38 test our incident response processes. Further, as discussed below, we engage third parties to provide guidance and support to our cybersecurity management team. Risks from Cybersecurity Threats 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, hackers, employee or vendor incidents, and other external hazards could expose our information systems—and those of our 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, to date none have materially affected us, including our business strategy, results of operations or financial condition. Governance As part of our overall risk management approach, we prioritize the identification and management of cybersecurity risks at several levels, including Board oversight, executive commitment, management support, and employee training. Board of Directors Oversight As of December 2023, 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. Prior to December 2023, our Governance, Environmental and Sustainability Committee, comprised of independent directors from our Board, oversaw cybersecurity responsibilities. As part of their risk oversight responsibilities, the applicable committee received quarterly reports from our Executive Vice President and General Counsel, or representatives from our cybersecurity or data privacy groups, and periodic reports from our third party consultants. Based on these reports, the applicable committee reported to the Board regarding certain cybersecurity or data privacy related items, including, among other items, CenterPoint Energy’s progress in maturing its cybersecurity program, results of audits, penetration and vulnerability testing of CenterPoint Energy’s cybersecurity program, 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 Since January 2023, our cybersecurity program has been overseen by our Executive Vice President and General Counsel. Our Executive Vice President and General Counsel has significant risk management, governance and litigation experience. We believe these skills are needed in leadership of our cybersecurity program to help ensure that risk management, legal, disclosure and governance perspectives are considered in the design of our cybersecurity program and in evaluating and responding to potential cyber incidents. CenterPoint Energy currently engages a third-party consultant, who reports directly to the Executive Vice President and General Counsel, to provide Chief Information Security Officer (CISO) advisory services. This consultant has 15 years of experience serving in cybersecurity leadership positions, including as a CISO at a large U.S.-based power, utility, and gas company and also at a large multi-national energy products and services company. We also have management-level committees and an experienced CSOC team that support our processes to assess and manage cybersecurity risk as follows: • The Data Privacy Office, led by our Senior Vice President, Deputy General Counsel, Chief Ethics and Compliance Officer, and Data Privacy Officer, addresses the collection, storage, usage, disclosure and destruction of data for specific business purposes and addresses existing and emerging laws, regulations, trends, expectations and best practices with regards to maintaining a mature data privacy program. • The Risk Oversight Committee, which is supported by our Enterprise Risk Management function and chaired by our Executive Vice President and General Counsel, is comprised of senior executives from across CenterPoint Energy, monitors and oversees risks facing CenterPoint Energy, as well as provides risk assessments and control oversight for certain business activities, including overseeing CenterPoint Energy’s cybersecurity risks. • The crisis management team, which includes senior executives across CenterPoint Energy, is alerted as appropriate to cybersecurity incidents, natural disasters, and business outages. This team has established and continually assesses CenterPoint Energy’s communications plan in the event of a crisis. Additionally, as appropriate, the Audit Committee 39 or the Board are made aware of significant cybersecurity incidents in accordance with our cybersecurity incident response playbook. • The Cybersecurity Awareness Governance Committee, which includes leaders from across CenterPoint Energy’s corporate functions and business units, each with expertise in, or with specific responsibility for, managing or protecting CenterPoint Energy’s assets, information and personnel. This committee provides strategic direction and oversight for CenterPoint Energy’s cybersecurity awareness and training initiatives. • The Artificial Intelligence (AI) Steering Committee was established by CenterPoint Energy to provide strategic direction, oversight, and guidance in the planning, development, deployment, and management of AI initiatives within the organization. The committee's primary objective is to ensure that AI technologies are aligned with business goals, ethical considerations, appropriate security protections, and industry best practices while driving innovation and enhancing competitiveness. These committees provide periodic summary reports on their activities and initiatives to appropriate senior executives, and the Executive Vice President and General Counsel and/or various members of the cyber and data privacy teams communicates updates to the Audit Committee or the Board. At the employee level, we maintain an experienced information technology team that is tasked with implementing our privacy and cybersecurity programs and supporting the cybersecurity consultant in carrying out reporting, security and mitigation functions. We also hold employee trainings on privacy, cybersecurity, AI, records and information management, conduct phishing tests, and generally seek to promote awareness of cybersecurity risk through communication and education of our employee population. The Governance, Environmental and Sustainability Committee was, and now the Audit Committee will be, provided with periodic reports on our employee cybersecurity awareness efforts. Item 2. Properties The following discussion is based on the Registrants’ businesses as of December 31, 2023. 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 and 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 13 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. 40 Electric Lines - Transmission and Distribution. As of December 31, 2023, 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 132 2 567 — 138 kV 2,333 24 420 9 345 kV 1,445 — 49 15 Total 3,910 26 1,036 24 (in Circuit Miles) Distribution lines 29,270 27,267 7,266 — (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. In 2023, SIGECO completed the planned retirement of its A.B. Brown Units 1 & 2. As of December 31, 2023, Indiana Electric had 727 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 1966 90 F.B. Culley 3 Warrick County 1973 270 Warrick (1) 4 Warrick County 1970 150 Total Coal Capacity 510 Gas Brown (2) 3 Posey County 1991 80 Brown 4 Posey County 2002 80 Renewable Landfill Gas Pike County 2009 3 Total Gas Capacity 163 Solar Oak Hill Evansville, Indiana 2018 2 Volkman Evansville, Indiana 2018 2 Troy Spencer County 2021 50 Total Solar Capacity 54 Total Generating Capacity (3) 727 (1) SIGECO and AGC own a 300 MW unit at the Warrick Power Plant as tenants in common. SIGECO exited joint operations of Warrick 4 on January 1, 2024. (2) Brown Unit 3 is also equipped to burn oil. (3) Excludes 1.5% participation in OVEC. See Item 1. Business for more details. Natural Gas Combustion Turbines. In 2022, Indiana Electric received approval from the IURC for a CPCN seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. The turbines are targeted to be operational by year end 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. Additionally, 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. 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. 41 Mobile 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. As of December 31, 2023, Houston Electric leased 505 MW of TEEEF. For more information, see Note 20 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. As of December 31, 2023 Number of Substations Transformer Capacity (in Mva) Houston Electric 240 72,806 Indiana Electric 108 6,913 Total CenterPoint Energy 348 79,719 Service Centers. Service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity. As of December 31, 2023 Number of Service Centers Acres of Land Houston Electric 13 375 Indiana Electric 6 70 Total CenterPoint Energy 19 445 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, 2023, 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 16 247,000 14.1 1,228,000 LNG Plant Facility 1 72,000 12.0 1,010,000 42 The table below reflects CenterPoint Energy’s and CERC’s Natural Gas contracted upstream storage services as of December 31, 2023: Storage Capacity (Bcf) Maximum Peak Daily Delivery (MMcf) Upstream Storage Service 84 2,241 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, 2023: CenterPoint Energy CERC All Locations 84,000 81,000 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 maintenance. With a few exceptions, the measuring stations at which CenterPoint Energy’s and CERC’s Natural Gas receives 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, 2023, CenterPoint Energy and CERC, through CEIP, owned and operated over 217 miles of intrastate pipeline in Louisiana and Texas. 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, please 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 15(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, Houston Electric and CERC. Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities CenterPoint Energy As of February 12, 2024, CenterPoint Energy’s common stock was held by approximately 22,703 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 12 to the consolidated financial statements. 43 Repurchases of Equity Securities During the quarter ended December 31, 2023, 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 12, 2024, 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 12, 2024, all of CERC Corp.’s 1,000 outstanding shares of common stock were held by Utility Holding, LLC, a wholly-owned subsidiary of CenterPoint Energy. Item 6. [Reserved] Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations No Registrant makes any representations as to the information related solely to CenterPoint Energy or the subsidiaries of CenterPoint Energy other than itself. The following combined discussion and analysis should be read in combination with the consolidated financial statements included in Item 8 herein. When discussing CenterPoint Energy’s consolidated financial information, it includes the results of Houston Electric and CERC, which, along with CenterPoint Energy, 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. OVERVIEW Background CenterPoint Energy, Inc. is a public utility holding company. CenterPoint Energy’s operating subsidiaries own and operate electric transmission, distribution and generation and natural gas distribution facilities. For a detailed description of CenterPoint Energy’s operating subsidiaries, please read Note 1 to the consolidated financial statements. Houston Electric is an indirect, wholly-owned subsidiary of CenterPoint Energy that 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 that (i) directly owns and operates natural gas distribution systems in Louisiana, Minnesota, Mississippi and Texas, (ii) indirectly, through Indiana Gas and VEDO, 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. Reportable Segments In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our reportable segments, which are listed below. We also discuss our liquidity, capital resources and critical accounting policies. 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. 44 As of December 31, 2023, CenterPoint Energy’s reportable segments were Electric, Natural Gas, and Corporate and Other. • 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. For further information about the Electric reportable segment, see “Business — Our Business — Electric” in Item 1 of Part I of this report. • The Natural Gas reportable segment includes (i) intrastate natural gas sales to, and natural gas transportation and distribution for residential, commercial, industrial and institutional 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. For further information about the Natural Gas reportable segment, see “Business — Our Business — Natural Gas” in Item 1 of Part I of this report. • The Corporate and Other reportable segment includes energy performance contracting and sustainable infrastructure services by Energy Systems Group through June 30, 2023, the date of the sale of Energy Systems Group, and corporate support operations that support CenterPoint Energy’s business operations. CenterPoint Energy’s Corporate and Other also includes office buildings and other real estate used for business operations. Houston Electric and CERC each consist of a single reportable segment. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 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 carbon emission 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, 2023. See Note 11 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 capital plan, which has increased to nearly $44 billion through 2030, a nearly 10% increase from the original 10-year plan. 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 sale of our Arkansas and Oklahoma LDC businesses in 2022 and our Energy Systems Group divestiture in 2023), and issuances of equity and debt in the capital markets to satisfy these capital needs. 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 45 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 they would otherwise accept. 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 CenterPoint Energy’s, Houston Electric’s and CERC’s businesses. In accordance with applicable regulations, CenterPoint Energy, Houston Electric and CERC are making, and will continue to make, significant capital investments in their 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. CERC’s Texas and Minnesota gas jurisdictions along with Indiana Electric have filed rates cases during 2023, and Houston Electric intends to file a rate case in early 2024 and CERC’s Ohio jurisdiction intends to file a rate case in the second half of 2024. The outcome of these base rate proceedings will determine, among other things, the ability to recover certain capital investments within those jurisdictions. The outcome of these base rate proceedings is uncertain and may be impacted by the current economic environment. 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, use per customer, 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 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%. 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%. Rising inflation and sustained 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 46 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 labor shortages, resource availability, long lead times, inflation and weather. These disruptions have adversely impacted the utility industry. Like many of our peers, we have experienced disruptions to our supply chain and may continue to experience such disruptions in the future. 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, results from our energy delivery businesses may suffer. For more information, see Note 15 to the consolidated financial statements. 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 GHG emissions by 2035 goals. In addition, we set a Scope 3 GHG 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. Significant Events Series A Preferred Stock Redemption. On September 1, 2023, CenterPoint Energy redeemed all of the outstanding shares of Series A Preferred Stock for cash of $800 million at a redemption price of $1,000 per share, plus accumulated and unpaid dividends thereon to, but excluding, the redemption date. For further information, see Note 12 to the consolidated financial statements. Divestiture of Energy Systems Group. On May 21, 2023, Vectren Energy Services entered into an Equity Purchase Agreement to sell all of the outstanding limited liability company interests of Energy Systems Group to ESG Holdings Group, for a purchase price of $157 million, subject to customary adjustments set forth in the Equity Purchase Agreement, including adjustments based on Energy Systems Group’s net working capital at closing, indebtedness, cash and cash equivalents and transaction expenses. The transaction closed on June 30, 2023 for $154 million in cash, subject to finalization of the purchase price adjustment. For further information, see Note 4 to the consolidated financial statements. Regulatory Proceedings. On March 23, 2023, CenterPoint Energy and CERC, collectively, received approximately $1.1 billion in proceeds from the customer rate relief bonds issued by the Texas Public Financing Authority related to the February 2021 Winter Storm Event. On April 5, 2023, a final order was issued approving the $39 million revenue requirement from Houston Electric’s 2021 investment in TEEEF. On April 5, 2023, Houston Electric filed its second TEEEF filing requesting a TEEEF revenue requirement of $188 million or a net increase in TEEEF revenues of approximately $149 million . On August 28, 2023 the State Office of Administrative Hearings issued an Order setting interim rates to collect an annual revenue requirement at the filed amount. On September 26, 2023, intervenors filed testimony with various recommendations including extending the amortization period. A settlement was reached with parties that incorporated an 8 1/2 year amortization period and a TEEEF revenue requirement of $153 million based on the December 31, 2022 balance with interim rates effective December 15, 2023. The State Office of Administrative Hearings ALJ approved the revised interim rates and the settlement was approved by the PUCT in its order issued on February 1, 2024. On June 29, 2023, Indiana Electric received the net securitization proceeds of $337 million from the issuance and sale of the SIGECO Securitization Bonds to reimburse or pay for qualified costs approved by the IURC related to the completed retirement of its A.B. Brown coal-fired generation facilities. For further information, see Note 7 to the consolidated financial statements. For information related to our pending and completed regulatory proceedings to date in 2023 and to date in 2024, see “—Liquidity and Capital Resources —Regulatory Matters” below. Debt Transactions. In 2023, CenterPoint Energy issued or borrowed a combined $6.0 billion in new debt, including Houston Electric’s issuance of $1.4 billion aggregate principal amount of general mortgage bonds, CERC’s issuance of $1.5 billion aggregate principal amount of senior notes and a $500 million term loan, SIGECO Securitization Subsidiary’s issuance of $341 million aggregate principal amount of SIGECO Securitization Bonds, SIGECO’s issuance of $650 million aggregate principal amount of first mortgage bonds, and CenterPoint Energy’s issuance of $1.0 billion aggregate principal amount of convertible senior notes, $400 million aggregate principal amount of senior notes and a $250 million term loan. During 2023, CenterPoint Energy repaid or redeemed a combined $3.0 billion of debt, including CERC’s repayment of $1.0 billion of term loans and $1.332 billion of senior notes maturing in 2023, CenterPoint Energy’s repayment of its 47 $250 million term loan and $350 million of its floating rate senior notes and SIGECO’s early redemption of $91 million of first mortgage bonds, excluding scheduled principal payments on Securitization Bonds. For information about debt transactions in 2023, see Note 13 to the consolidated financial statements. CenterPoint Energy Leadership Transition. On March 15, 2023, CenterPoint Energy announced the appointment of Christopher A. Foster to the position of Executive Vice President and Chief Financial Officer, effective May 5, 2023. On September 27, 2023, CenterPoint Energy appointed Kristie L. Colvin to the position of Senior Vice President and Chief Accounting Officer of CenterPoint Energy and its affiliated subsidiaries, effective October 5, 2023. On October 26, 2023, CenterPoint Energy announced the retirement of Dave Lesar and appointment of Jason Wells to the position of President and Chief Executive Officer, effective January 5, 2024. Subsequent Events . 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. CenterPoint Energy may also enter into one or more forward sales agreements pursuant to master forward confirmations. The offer and sale of Common Stock under the Equity Distribution Agreement will terminate upon the earliest of (1) the sale of all Common Stock subject to the Equity Distribution Agreement, (2) termination of the Equity Distribution Agreement, or (3) May 17, 2026. As of February 20, 2024, CenterPoint Energy has not issued any shares of Common Stock under the Equity Distribution Agreement and has not entered into any forward sale agreements. Additionally, 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 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: • CenterPoint Energy’s business strategies and strategic initiatives, restructurings, including the completed Restructuring, joint ventures and acquisitions or dispositions of assets or businesses, including the proposed sale of our Louisiana and Mississippi natural gas local distribution company businesses, and the completed sale of Energy Systems Group, 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 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 those related to Indiana Electric’s generation transition plan as part of its IRPs; • 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 requested and timely recovery of costs and a reasonable return on investment, including the timing and amount of recovery of Houston Electric’s TEEEF leases, and requested or favorable adjustments to rates and approval of other requested items as part of base rate proceedings; • economic conditions in regional and national markets, including changes to inflation and interest rates, and instability of banking institutions, and their effect on sales, prices and costs; • weather variations and other natural phenomena, including the impact of severe weather events on operations, capital and legislation such as in connection with the February 2021 Winter Storm Event; • volatility in the markets for natural gas as a result of, among other factors, 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 volatility in commodity prices, and tariffs and other legislation 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 carbon 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; 48 • public health threats, such as COVID-19, 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, energy 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; • direct or indirect effects on our facilities, resources, operations 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, ice, earthquakes, explosions, leaks, floods, droughts, hurricanes, tornadoes and other severe weather events, pandemic health events or other occurrences; • tax legislation, including the effects 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, carbon, waste water 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 carbon 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, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; • 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 securitization for any hurricanes or other severe weather events, or natural disasters or other recovery of costs, including stranded coal-fired generation asset costs; • acquisition and merger or divestiture activities involving us or our industry, including the ability to successfully complete merger, acquisition and divestiture plans such as the proposed sale of our Louisiana and Mississippi natural gas local distribution company businesses; • 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; • 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, including energy and environmental policies under the current administration; • CenterPoint Energy’s ability to execute on its strategy, initiatives, targets and goals, including its net zero and carbon emissions reduction goals and its operations and maintenance expenditure goals; • the outcome of litigation, including litigation related to the February 2021 Winter Storm Event; • the effect of changes in and application of accounting standards and pronouncements; and 49 • other factors discussed in “Risk Factors” in Item 1A of Part I of this report and in other reports that the Registrants file from time to time with the SEC. 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, please read “Risk Factors” in Item 1A of Part I of this report. Income available to common shareholders for the years ended December 31, 2023, 2022 and 2021 was as follows: Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions) Electric $ 654 $ 603 $ 475 $ 51 $ 128 Natural Gas 533 492 403 41 89 Total Utility Operations 1,187 1,095 878 92 217 Corporate & Other (1) (320) (87) (305) (233) 218 Discontinued Operations — — 818 — (818) Total CenterPoint Energy $ 867 $ 1,008 $ 1,391 $ (141) $ (383) (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. 2023 Compared to 2022 Net Income. 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 net income of $51 million for the Electric reportable segment, as further discussed below; • an increase in net income 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 11 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 $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. 2022 Compared to 2021 Net Income. CenterPoint Energy reported income available to common shareholders of $1,008 million for 2022 compared to income available to common shareholders of $1,391 million for 2021. Income available to common shareholders decreased $383 million primarily due to the following items: • an increase in net income of $128 million for the Electric reportable segment, as further discussed below; • an increase in net income of $89 million for the Natural Gas reportable segment, as further discussed below; • an increase in income available to common shareholders of $218 million for Corporate and Other, primarily due to a $28 million pre-tax payment related to the impact of Board-implemented governance changes announced in July 2021, the net gain of $86 million in 2022 and a net loss of $122 million in December 2021 on the sale of Energy Transfer equity securities discussed further in Note 11 to the consolidated financial statements, partially offset by a $34 million loss in Enable Series A Preferred Unit distributions in 2021 discussed in Note 4, and a decrease in income allocated to 50 preferred shareholders of $46 million, primarily due to the conversion of the Series B Preferred Stock to Common Stock during 2021; and • a decrease in income of $818 million from discontinued operations, discussed further in Note 4 to the consolidated financial statements. Income Tax Expense. For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 51 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 The following table provides summary data of CenterPoint Energy’s Electric reportable segment: Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues $ 4,290 $ 4,108 $ 3,763 $ 182 $ 345 Expenses: Utility natural gas, fuel and purchased power 176 222 186 46 (36) Operation and maintenance 1,880 1,864 1,761 (16) (103) Depreciation and amortization 872 793 775 (79) (18) Taxes other than income taxes 272 275 268 3 (7) Total expenses 3,200 3,154 2,990 (46) (164) Operating Income 1,090 954 773 136 181 Other Income (Expense): Interest expense and other finance charges (303) (235) (226) (68) (9) Other income (expense), net 56 31 23 25 8 Income before income taxes 843 750 570 93 180 Income tax expense 189 147 95 (42) (52) Net income $ 654 $ 603 $ 475 $ 51 $ 128 Throughput (in GWh): Residential 35,166 35,074 32,067 — % 9 % Total 108,766 105,541 103,000 3 % 2 % Weather (percentage of normal weather for service area): Cooling degree days 114 % 110 % 108 % 4 % 2 % Heating degree days 90 % 121 % 82 % (31) % 39 % Number of metered customers at end of period: Residential 2,588,510 2,534,730 2,493,832 2 % 2 % Total 2,916,028 2,858,203 2,814,859 2 % 2 % 52 The following table provides variance explanations by major income statement caption for the Electric reportable segment: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Customer rates and impact of the change in rate design $ 167 $ 38 Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers, partially offset in operation and maintenance below 122 157 Customer growth 26 28 Refund of protected and unprotected EDIT, offset in income tax expense — 32 Impacts from increased peak demand in the prior year, collected in rates in the current year — 2 Energy efficiency, partially offset in operation and maintenance below — (3) Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (5) 2 Pass-through revenues, offset in operation and maintenance below (13) 21 Miscellaneous revenues, primarily related to service connections and off-system sales (14) 11 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items below (27) (33) Weather, efficiency improvements and other usage impacts (28) 54 Cost of fuel and purchased power, offset in utility natural gas, fuel and purchased power below (46) 36 Total $ 182 $ 345 Utility natural gas, fuel and purchased power Cost of purchased power, offset in revenues above $ 30 $ 12 Cost of fuel, including coal, natural gas, and fuel oil, offset in revenues above 16 (48) $ 46 $ (36) Operation and maintenance Transmission costs billed by transmission providers, offset in revenues above $ (26) $ (77) Contract services (21) (2) Energy efficiency, offset in revenues above (8) 4 Support services (8) 20 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items — 3 Labor and benefits 7 7 Pass through expenses, offset in revenues above 11 (19) All other operation and maintenance expense, including materials and supplies and insurance 29 (39) Total $ (16) $ (103) Depreciation and amortization Ongoing additions to plant-in-service $ (106) $ (40) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items 27 22 Total $ (79) $ (18) Taxes other than income taxes Incremental capital projects placed in service, and the impact of changes to tax rates $ 2 $ (14) Franchise fees and other taxes 1 7 Total $ 3 $ (7) Interest expense and other finance charges Changes in outstanding debt $ (76) $ (32) Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above (4) 8 Other, primarily AFUDC and impacts of regulatory deferrals 12 15 Total $ (68) $ (9) Other income (expense), net Other income, including AFUDC - equity $ 21 $ 8 Bond Companies and SIGECO Securitization Subsidiary, offset in other line items above 4 — Total $ 25 $ 8 Income Tax Expense. For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated financial statements. 53 NATURAL GAS The following table provides summary data of CenterPoint Energy’s Natural Gas reportable segment: Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues $ 4,279 $ 4,946 $ 4,336 $ (667) $ 610 Expenses: Utility natural gas, fuel and purchased power 1,888 2,665 1,941 777 (724) Non-utility cost of revenues, including natural gas 3 4 18 1 14 Operation and maintenance 949 919 979 (30) 60 Depreciation and amortization 513 466 527 (47) 61 Taxes other than income taxes 245 261 253 16 (8) Total expenses 3,598 4,315 3,718 717 (597) Operating Income 681 631 618 50 13 Other Income (Expense) Gain on sale — 303 8 (303) 295 Interest expense and other finance charges (188) (137) (141) (51) 4 Other income (expense), net 15 (62) (2) 77 (60) Income from Continuing Operations Before Income Taxes 508 735 483 (227) 252 Income tax expense (benefit) (25) 243 80 268 (163) Net Income $ 533 $ 492 $ 403 $ 41 $ 89 Throughput (in Bcf): Residential 199 240 241 (17) % — % Commercial and industrial 418 424 428 (1) % (1) % Total Throughput 617 664 669 (7) % (1) % Weather (percentage of 10-year average for service area): Heating degree days 86 % 106 % 91 % (20) % 15 % Number of customers at end of period: Residential 4,010,113 3,964,221 4,372,428 1 % (9) % Commercial and industrial 303,841 301,834 354,602 1 % (15) % Total 4,313,954 4,266,055 4,727,030 1 % (10) % 54 The following table provides variance explanations by major income statement caption for the Natural Gas reportable segment: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (754) $ 923 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale (38) (457) Gross receipts tax, offset in taxes other than income taxes below (17) 19 Weather and usage (7) 22 Refund of protected and unprotected EDIT, offset in income tax expense 3 6 Non-volumetric and miscellaneous revenue 14 26 Energy efficiency and other pass-through, offset in operation and maintenance below 17 3 Non-utility revenues, including impacts of MES disposal 18 (17) Customer growth 20 16 Customer rates and impact of the change in rate design, exclusive of the TCJA impact below 77 69 Total $ (667) $ 610 Utility natural gas, fuel and purchased power Cost of natural gas, offset in revenues above $ 754 $ (923) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 23 199 $ 777 $ (724) Non-utility costs of revenues, including natural gas Non-utility cost of revenues, including natural gas $ 1 $ 14 $ 1 $ 14 Operation and maintenance Miscellaneous operations and maintenance expenses, including bad debt expense $ (36) $ (21) Energy efficiency and other pass-through, offset in revenues above (17) (3) Contract services (3) (14) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 3 125 Labor and benefits, primarily due to headcount 11 (5) Corporate support services 12 (22) Total $ (30) $ 60 Depreciation and amortization Incremental capital projects placed in service $ (49) $ (23) Lower depreciation rates in Indiana from 2021 rate order — 18 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 2 66 Total $ (47) $ 61 Taxes other than income taxes Gross receipts tax, offset in revenues above $ 17 $ (19) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 1 23 Incremental capital projects placed in service (2) (12) Total $ 16 $ (8) Gain on Sale Gain on Sale of Arkansas and Oklahoma Natural Gas businesses in 2022 $ (303) $ 295 Total $ (303) $ 295 Interest expense and other finance charges Changes in outstanding debt $ (59) $ (11) Other, primarily AFUDC and impacts of regulatory deferrals 8 15 Total $ (51) $ 4 Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 60 $ (66) AFUDC - Equity, primarily from increased capital spend 10 3 Other miscellaneous non-operating income (expenses) 7 3 Total $ 77 $ (60) Income Tax Expense (Benefit). For a discussion of effective tax rate per period by Registrant, see Note 14 to the consolidated financial statements. 55 Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. 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, please read “Risk Factors” in Item 1A of Part I of this report. Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues: TDU $ 3,514 $ 3,205 $ 2,894 $ 309 $ 311 Bond Companies 163 207 240 (44) (33) Total revenues 3,677 3,412 3,134 265 278 Expenses: Operation and maintenance, excluding Bond Companies 1,669 1,647 1,591 (22) (56) Depreciation and amortization, excluding Bond Companies 593 479 429 (114) (50) Taxes other than income taxes 262 261 251 (1) (10) Bond Companies 159 194 219 35 25 Total 2,683 2,581 2,490 (102) (91) Operating Income 994 831 644 163 187 Interest expense and other finance charges (259) (202) (183) (57) (19) Interest expense on Securitization Bonds (8) (13) (21) 5 8 Other income, net 34 19 17 15 2 Income before income taxes 761 635 457 126 178 Income tax expense 168 125 76 (43) (49) Net income $ 593 $ 510 $ 381 $ 83 $ 129 Throughput (in GWh): Residential 33,830 33,676 30,650 — % 10 % Total 103,862 100,062 96,898 4 % 3 % Weather (percentage of 10-year average for service area): Cooling degree days 114 % 110 % 109 % 4 % 1 % Heating degree days 92 % 120 % 80 % (28) % 40 % Number of metered customers at end of period: Residential 2,455,309 2,402,329 2,359,168 2 % 2 % Total 2,763,535 2,706,598 2,660,938 2 % 2 % 56 The following table provides variance explanations by major income statement caption for Houston Electric: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Customer rates and impact of the change in rate design $ 187 $ 30 Transmission Revenues, including TCOS and TCRF and impact of the change in rate design, inclusive of costs billed by transmission providers 120 157 Customer growth 25 27 Energy efficiency, partially offset in operation and maintenance below 1 (3) Refund of protected and unprotected EDIT, offset in income tax expense — 32 Impacts from increased peak demand in the prior year, collected in rates in the current year — 2 Miscellaneous revenues (4) 5 Equity return, related to the annual true-up of transition charges for amounts over or under collected in prior periods (5) 1 Weather impacts and other usage (15) 60 Bond Companies, offset in other line items below (44) (33) Total $ 265 $ 278 Operation and maintenance, excluding Bond Companies Transmission costs billed by transmission providers, offset in revenues above $ (26) $ (77) Contract services (23) 3 Energy efficiency program costs, offset in revenues above (8) 3 Support services (6) 24 Labor and benefits 3 12 All other operation and maintenance expense, including materials and supplies and insurance 38 (21) Total $ (22) $ (56) Depreciation and amortization, excluding Bond Companies Ongoing additions to plant-in-service $ (114) $ (50) Total $ (114) $ (50) Taxes other than income taxes Franchise fees and other taxes $ (2) $ 4 Incremental capital projects placed in service, and the impact of changes to tax rates 1 (14) Total $ (1) $ (10) Bond Companies expense Operations and maintenance and depreciation expense, offset by revenues above $ 35 $ 25 Total $ 35 $ 25 Interest expense and other finance charges Changes in outstanding debt $ (64) $ (32) Other, primarily AFUDC and impacts of regulatory deferrals 7 13 Total $ (57) $ (19) Interest expense on Securitization Bonds Lower outstanding principal balance, offset by revenues above $ 5 $ 8 Total $ 5 $ 8 Other income, net Other income, including AFUDC - equity $ 11 $ 2 Bond Companies 4 — Total $ 15 $ 2 Income Tax Expense. For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements. 57 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, please read “Risk Factors” in Item 1A of Part I of this report. Year Ended December 31, Favorable (Unfavorable) 2023 2022 2021 2023 to 2022 2022 to 2021 (in millions, except throughput, weather and customer data) Revenues: 4,149 4,800 4,200 (651) 600 Expenses: Utility natural gas 1,856 2,607 1,885 751 (722) Non-utility cost of revenues, including natural gas 3 4 17 1 13 Operation and maintenance 904 886 973 (18) 87 Depreciation and amortization 493 448 483 (45) 35 Taxes other than income taxes 243 257 249 14 (8) Total expenses 3,499 4,202 3,607 703 (595) Operating Income 650 598 593 52 5 Other Income (Expense) Gain on sale — 557 11 (557) 546 Interest expense and other finance charges (178) (130) (134) (48) 4 Other income (expense), net 14 (64) (4) 78 (60) Income Before Income Taxes 486 961 466 (475) 495 Income tax expense (benefit) (26) 236 76 262 (160) Net Income $ 512 $ 725 $ 390 $ (213) $ 335 Throughput (in BCF): Residential 194 233 235 (17) % (1) % Commercial and industrial 386 389 396 (1) % (2) % Total Throughput 580 622 631 (7) % (1) % Weather (percentage of 10-year average for service area): Heating degree days 86 % 106 % 91 % (20) % 15 % Number of customers at end of period: Residential 3,905,388 3,859,726 4,268,385 1 % (10) % Commercial and industrial 293,235 291,184 336,828 1 % (14) % Total 4,198,623 4,150,910 4,605,213 1 % (10) % 58 The following table provides variance explanations by major income statement caption for CERC: Favorable (Unfavorable) 2023 to 2022 2022 to 2021 (in millions) Revenues Cost of natural gas, offset in utility natural gas, fuel and purchased power below $ (728) $ 921 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale (38) (457) Gross receipts tax, offset in taxes other than income taxes (15) 19 Weather and usage (7) 22 Refund of protected and unprotected EDIT, offset in income tax expense 3 6 Energy efficiency and other pass-through, offset in operation and maintenance 8 8 Non-volumetric and miscellaneous revenue 13 26 Non-utility revenues, including impacts of MES disposal 18 (17) Customer growth 20 16 Customer rates and impact of the change in rate design, exclusive of the TCJA impact 75 56 Total $ (651) $ 600 Utility natural gas Cost of natural gas, offset in revenues above $ 728 $ (921) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 23 199 Total $ 751 $ (722) Non-utility costs of revenues, including natural gas Other, primarily non-utility cost of revenues $ 1 $ 13 Total $ 1 $ 13 Operation and maintenance Miscellaneous operations and maintenance expenses, including bad debt expense $ (36) $ (20) Energy efficiency and other pass-through, offset in revenues above (8) (8) Contract services — (8) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 3 125 Labor and benefits 11 (4) Corporate Support Services 12 2 Total $ (18) $ 87 Depreciation and amortization Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale Incremental capital projects placed in service $ (47) $ (44) Indiana lower depreciation rates from recent rate order — 13 Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 2 66 Total $ (45) $ 35 Taxes other than income taxes Gross receipts tax, offset in revenues $ 15 $ (19) Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale 1 23 Incremental capital projects placed in service (2) (12) Total 14 (8) Gain on sale Net gain on sale of Arkansas and Oklahoma Natural Gas businesses $ (557) $ 546 Total $ (557) $ 546 Interest expense and other finance charges Changes in outstanding debt $ (56) $ (11) Other, primarily AFUDC and impacts of regulatory deferrals 8 15 Total $ (48) $ 4 Other income (expense), net Changes to non-service benefit cost, primarily settlement cost incurred in 2022 $ 60 $ (65) Increase in Equity AFUDC 9 2 Other miscellaneous non-operating income (expenses) 9 — Nine days in January 2022 for Arkansas and Oklahoma Natural Gas businesses due to sale — 3 Total $ 78 $ (60) 59 Income Tax Expense (Benefit). For a discussion of effective tax rate per period, see Note 14 to the consolidated financial statements. Subsequent Events. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. LIQUIDITY AND CAPITAL RESOURCES Historical Cash Flows The net cash provided by (used in) operating, investing and financing activities for 2023, 2022 and 2021 is as follows: Year Ended December 31, 2023 2022 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Cash provided by (used in): Operating activities $ 3,877 $ 1,401 $ 2,312 $ 1,810 $ 966 $ 856 $ 22 $ 770 $ (1,219) Investing activities (4,233) (2,503) (1,643) (1,628) (2,435) 406 (1,851) (1,617) (1,287) Financing activities 374 1,103 (668) (345) 1,324 (1,277) 1,916 926 2,515 Operating Activities. The following items contributed to increased (decreased) net cash provided by operating activities: Year Ended December 31, 2023 compared to 2022 2022 compared to 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Changes in net income after adjusting for non-cash items $ 394 $ 235 $ 170 $ (492) $ 211 $ (169) Changes in working capital 917 229 358 (615) (177) (107) Changes in net regulatory assets and liabilities (1) 809 (89) 908 2,529 196 2,339 Changes in equity in earnings of unconsolidated affiliates (2) — — — 339 — — Changes in distributions from unconsolidated affiliates (2) — — — (155) — — Lower pension contribution 3 — — 26 — — Other (56) 60 20 156 (34) 12 $ 2,067 $ 435 $ 1,456 $ 1,788 $ 196 $ 2,075 (1) The change in net regulatory assets and liabilities at CenterPoint Energy and CERC is primarily due to securitization of the incurred natural gas costs associated with the February 2021 Winter Storm Event. See Note 7 to the consolidated financial statements for more information on the February 2021 Winter Storm Event. (2) In September 2021, CenterPoint Energy’s equity investment in Enable met the held for sale criteria and is reflected as discontinued operations on CenterPoint Energy’s Statements of Consolidated Income. For further information, see Note 4 to the consolidated financial statements. 60 Investing Activities. The following items contributed to (increased) decreased net cash used in investing activities: Year Ended December 31, 2023 compared to 2022 2022 compared to 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Proceeds from the sale of equity securities $ (702) $ — $ — $ (618) $ — $ — Net change in capital expenditures 18 157 42 (1,255) (817) (337) Transaction costs related to the Enable Merger — — — 49 — — Cash received related to Enable Merger — — — (5) — — Net change in notes receivable from unconsolidated affiliates — (238) (1) — — — Proceeds from divestitures (1,931) — (2,075) 2,053 — 2,053 Other 10 13 (15) (1) (1) (23) $ (2,605) $ (68) $ (2,049) $ 223 $ (818) $ 1,693 Financing Activities. The following items contributed to (increased) decreased net cash used in financing activities: Year Ended December 31, 2023 compared to 2022 2022 compared to 2021 CenterPoint Energy Houston Electric CERC CenterPoint Energy Houston Electric CERC (in millions) Net changes in commercial paper outstanding $ (981) $ — $ (227) $ (1,206) $ — $ (646) Net changes in long-term debt outstanding, excluding commercial paper 2,560 373 (778) (1,231) 386 (936) Net changes in debt and equity issuance costs (19) 4 — 2 (5) (4) Net changes in short-term borrowings (462) — (462) 479 — 479 Redemption of Series A Preferred Stock (800) — — — — — Increased payment of Common Stock dividends (45) — — (55) — — Decreased (increased) payment of Preferred Stock dividends (1) — — 58 — — Payment of obligation for finance lease 485 485 — (306) (306) — Net change in notes payable from affiliated companies — (772) 1,517 — (374) (2,007) Contribution from parent — (258) 211 — 1,013 149 Dividend to parent — (51) 348 — (316) (827) Other (18) (2) — (2) — — $ 719 $ (221) $ 609 $ (2,261) $ 398 $ (3,792) Future Sources and Uses of Cash The Registrants expect that anticipated 2024 cash needs will be met with borrowings under their credit facilities, proceeds from the issuance of long-term debt, proceeds from sales of Common Stock under the Equity Distribution Agreement further described in Note 21 to the consolidated financial statements, anticipated cash flows from operations, and with respect to CenterPoint Energy and CERC, proceeds from commercial paper. Discretionary financing or refinancing may result in the issuance of equity securities of CenterPoint Energy or debt securities of the Registrants in the capital markets or the arrangement of additional credit facilities or term bank loans. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available on acceptable terms. Material Current and Long-term Cash Requirements . The liquidity and capital requirements of the Registrants are affected primarily by results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Capital expenditures are expected to be used for investment in infrastructure for electric and natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety, increase resiliency and 61 expand our systems through value-added projects. In addition to dividend payments on CenterPoint Energy’s Common Stock and interest payments on debt, the Registrants’ principal anticipated cash requirements for 2024 include the following: CenterPoint Energy Houston Electric CERC (in millions) Estimated capital expenditures $ 3,669 $ 1,895 $ 1,385 Maturing CenterPoint Energy senior notes 850 — — Scheduled principal payments on Securitization Bonds 178 161 — Maturing SIGECO first mortgage bonds 22 — — Minimum contributions to pension plans and other post-retirement plans 17 1 4 The following table sets forth the Registrants’ estimates of the Registrants’ capital expenditures currently planned for projects for 2024 through 2028. See Note 17 to the consolidated financial statements for CenterPoint Energy’s actual capital expenditures by reportable segment for 2023. 2024 2025 2026 2027 2028 CenterPoint Energy (in millions) Electric $ 2,205 $ 3,341 $ 3,589 $ 3,080 $ 3,018 Natural Gas 1,450 1,432 1,604 1,469 1,344 Corporate and Other 14 20 20 20 20 Total $ 3,669 $ 4,793 $ 5,213 $ 4,569 $ 4,382 Houston Electric (1) $ 1,895 $ 2,598 $ 2,663 $ 2,822 $ 2,816 CERC (1) $ 1,385 $ 1,370 $ 1,486 $ 1,391 $ 1,271 (1) Houston Electric and CERC each consist of a single reportable segment. Capital Expenditures for Climate-Related Projects . As part of its approximately $44.5 billion 10-year capital expenditure plan, which concludes in 2030, CenterPoint Energy anticipates spending over $3 billion in cleaner energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion. The following table summarizes the Registrants’ material current and long-term cash requirements as of December 31, 2023. Total 2024 2025-2026 2027-2028 2029 and thereafter (in millions) CenterPoint Energy Securitization Bonds (1) $ 502 $ 178 $ 27 $ 29 $ 268 Other long-term debt (1) (2) 18,282 872 2,311 3,894 11,205 Interest payments — Securitization Bonds (3) 187 27 32 29 99 Interest payments — other long-term debt (3) 9,238 835 1,652 1,317 5,434 Short-term borrowings 4 4 — — — Commodity and other commitments (4) 6,749 993 2,002 982 2,772 Total cash requirements $ 34,962 $ 2,909 $ 6,024 $ 6,251 $ 19,778 Houston Electric Securitization Bonds (1) $ 161 161 — — — Other long-term debt (1) 7,513 — 300 800 6,413 Interest payments — Securitization Bonds (3) 4 4 — — — Interest payments — other long-term debt (3) 5,340 306 610 583 3,841 Total cash requirements $ 13,018 $ 471 $ 910 $ 1,383 $ 10,254 62 Total 2024 2025-2026 2027-2028 2029 and thereafter (in millions) CERC Long-term debt $ 4,700 $ — $ 70 $ 1,740 $ 2,890 Interest payments — long-term debt (3) 2,213 240 478 398 1,097 Short-term borrowings 4 4 — — — Commodity and other commitments (4) 4,245 679 1,083 799 1,684 Total cash requirements $ 11,162 $ 923 $ 1,631 $ 2,937 $ 5,671 (1) Balances reflect aggregate principal amounts outstanding and do not include unamortized discounts, premiums or issuance costs. See Note 13 to the consolidated financial statements for additional information. (2) ZENS obligations are included in the 2029 and thereafter column at their contingent principal amount of $18 million as of December 31, 2023. 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 ($538 million as of December 31, 2023), as discussed in Note 11 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, 2023. 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 15(a) to the consolidated financial statements. The table above does not include the following: • estimated future payments for expected future AROs primarily estimated to be incurred after 2026. See Note 3(c) to the consolidated financial statements for further information. • expected contributions to pension plans and other postretirement plans in 2024. See Note 8(g) to the consolidated financial statements for further information. • operating leases. See Note 20 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 (see Note 13 to the consolidated financial statements) and short-term leases, the Registrants have no off-balance sheet arrangements. Regulatory Matters 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 is 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, 63 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 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 project as a clean energy project under Ind. Code Ch. 8-1-8.8, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs have exceeded the agreed upon levels in the BTA. Once pricing is updated and parties determine whether to continue with the project, Indiana Electric may have to refile for approval of the project with the IURC, which could delay the in-service date from 2025 to 2026. If Indiana Electric is not able to reach a mutually acceptable solution with the developers of the Pike County Solar project, Indiana Electric may seek to terminate 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 has approval to recover the costs of the wind facility via the CECA mechanism, which is expected to be placed in service by the end of 2026. On June 6, 2023 the IURC issued an order approving the CPCN, and thereby authorizing Indiana Electric to purchase the wind generating facility. However, as of the date 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 could be delayed from 2025 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 2021 PPA with certain modifications. On February 22, 2023 the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date could be delayed from 2024 to 2025. On January 17, 2023, Indiana Electric filed a request with the IURC to amend the previously approved 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 could be delayed from 2025 to 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 64 estimated $334 million turbine facility is being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and will 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. The period to challenge FERC’s certificate in a federal district court expired on February 20, 2023. 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. Recovery of the proposed natural gas combustion turbines and regulatory asset is 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 regarding uncertainties related to our solar projects, see Item 1A of Part I 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 October 23, 2023, Indiana Electric filed rebuttal testimony with the IURC and an evidentiary hearing was held on November 2, 2023. Indiana Electric expects a decision from the IURC in the first half of 2024. Space City Solar Transmission Interconnection Project (CenterPoint Energy and Houston Electric) On December 17, 2020, Houston Electric filed a CPCN with the PUCT for approval to build a 345 kV transmission line in Wharton County, Texas connecting the Hillje substation on Houston Electric’s transmission system to the planned 610 MW Space City Solar Generation facility being developed by third-party developer EDF Renewables. In November 2021, the PUCT approved a route that was estimated to cost $25 million and issued a final order on January 12, 2022. There have been project delays due to supply chain constraints in the developer acquiring solar panels. Houston Electric substantially completed construction in the fall of 2023, and the transmission line is expected to be energized shortly after the generation facility is complete, which is anticipated to occur in the first quarter of 2025. 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. 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 and have been estimated to be $60 million to $99 million. A decision on the approval of the project in the PUCT proceeding is expected in the first quarter of 2024. 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. 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 and have been estimated to be $61 million to $90 million. A decision on the approval of the project in the PUCT proceeding is expected in the second or third quarter of 2024. Texas Legislation (CenterPoint Energy, Houston Electric and CERC) Houston Electric and CERC are reviewing legislation passed in 2023 and associated PUCT rulemaking projects, including the following pieces of legislation that became law during the 88th Texas Legislature, including: 65 • House Bill 1500 is effective 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; • House Bill 2263 is effective June 12, 2023 and authorizes local distribution companies to offer programs to promote energy conservation and to recover costs prudently incurred to implement such programs under Railroad Commission authority; • House Bill 2555 is effective June 13, 2023 and allows an electric utility to create a transmission and distribution system resiliency plan with the PUCT and associated cost recovery to enhance its system through hardening, undergrounding certain lines, flood mitigation measures, and vegetation management. On January 18, 2024 the PUCT issued an Order adopting its Resiliency Plan Rule (16 TAC 25.62); • Senate Bill 947 is effective September 1, 2023 and creates severe criminal offenses for intentional damage to critical infrastructure facilities that create extended power outages; • Senate Bill 1015 is effective 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 is effective 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 is effective 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. 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 which could 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 greenhouse gas 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 January 15, 2024, reply comments are due March 15, 2024 and supplemental comments are due May 15, 2024; CERC anticipates the MPUC will hear this matter after the final comments are received. 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 a DOC investigation on anti-dumping and countervailing duties petition filed by a domestic solar manufacturer, (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 December 2, 2022, the DOC issued its preliminary determination, finding four of the eight companies being investigated are attempting to bypass U.S. duties. On August 18, 2023, the DOC announced its final determination and found that five of the eight companies investigated are attempting to bypass U.S. duties by doing minor 66 processing in one of the Southeast Asian countries before shipment to the United States. Pursuant to President Biden’s executive order issued in June 2022, duties will not be collected on any solar module and cell imports from these Southeast Asian countries until June 2024, as long as the imports are consumed in the U.S. market within six months of the termination of the executive order. The executive order could be subject to legal challenges and its effects remain uncertain. The resolution of these issues will determine what additional costs or delays our solar projects will be subject to. These impacts have resulted in cost increases for certain projects, and may result in cost increases in other projects, and such impacts have resulted in, or are expected to result in, the need for us to 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 “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 pursuant to Ind. Code ch. 8-1-39 (TDSIC Plan). Intervenors filed their case in chief on August 16, 2023 and Indiana Electric filed rebuttal on August 29, 2023. A hearing was held on September 13, 2023 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. 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, Registrants are periodically involved in proceedings to adjust its capital tracking mechanisms (e.g., CSIA, DCRF, DRR, GRIP, TCOS, ECA, CECA and TDSIC), its cost of service adjustments (e.g., RSP and RRA), its decoupling mechanism (e.g., Decoupling and SRC), and its energy efficiency cost trackers (e.g., CIP, DSMA, EECR, EECRF, EEFC and EEFR). Houston Electric Rate Case. Texas law mandates that electric utilities file a base rate proceeding no later than every four years from the date of their last base rate proceeding final order. Houston Electric’s most recent base rate proceeding order was approved by the PUCT on March 9, 2020, in Docket No. 49421. Therefore, Houston Electric is required to file its next base rate proceeding no later than March 9, 2024. 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 requested increase is approximately 3.1% or $37 million based on an historical test year ending June 30, 2023. 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 10.50% ROE on a 60.61% equity ratio. Intervenor testimony is due in early March 2024, followed by staff testimony. Rebuttal testimony is due in late March 2024 and a hearing on the merits is scheduled for mid-April 2024. A final order is expected in Q2 2024. Minnesota 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 of $69 million were implemented as of January 1, 2024. A decision on 2025 interim rates was delayed until the fourth quarter of 2024. 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 that is being made to ensure the safety and reliability of the system and normal increases in operating expenses. The rate case 67 reflects a proposed 10.4% ROE on a 55% equity ratio. A hearing is scheduled for late-April through mid-May 2024. A final order is expected in the fourth quarter of 2024. The table below reflects significant applications pending or completed since the Registrants’ combined 2022 Form 10-K was filed with the SEC through February 20, 2024. Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and Houston Electric (PUCT) DCRF (1) 86 December 2023 TBD TBD Based on the net change in distribution invested capital since its last base rate proceeding of approximately $2.5 billion for the period January 1, 2019 through September 30, 2023 for a revenue increase of $86 million, adjusted for load growth. This is the second DCRF filing made in 2023; filing two DCRFs in a year was authorized in 2023 legislative session. A request for interim rates to be implemented on February 12, 2024 was also made on December 14, 2023; the interim rate request was denied on January 9, 2024. On December 28, 2023, an intervenor requested a good cause extension, on January 5, 2024, certain parties supported it, and it was granted on January 9, 2024. On January 24, 2024, certain intervenors requested an evidentiary hearing, and the request was denied on January 25, 2024. On February 5, 2024, Houston Electric notified the ALJ that the parties have reached an agreement in principle on all issues in this proceeding, and filed an agreed expedited motion for interim rates. On February 6, 2024, the PUCT ALJ issued an order denying to abate the proceeding and retaining the procedural schedule already established. On February 7, 2024, Houston Electric on behalf of itself and all parties responded to the February 6, 2024 order to clarify that the abatement request was not intended to alter the statutory timeframe for a decision. On February 9, 2024, the PUCT ALJ issued an order setting filing deadlines and requesting briefing on interim rates. On February 13, 2024, interim rates designed to collect $220 million ($73 million incremental) were approved, to be effective April 2024. TCOS 44 August 2023 October 2023 October 2023 Based on net change in invested capital of $405 million for the period February 1, 2023 through June 30, 2023. Notice of Approval issued October 6, 2023. EECRF (1) 16 June 2023 March 2024 November 2023 The requested $53 million is comprised primarily of the following: 2024 program costs of $38 million; a credit of $2 million related to the over-recovery of 2022 program costs; the 2022 earned bonus of $16 million; and 2024 projected evaluation, measurement and verification costs of $1 million. An order approving performance bonus and rates was issued November 3, 2023. DCRF 70 April 2023 September 2023 September 2023 The net change in distribution invested capital since its last base rate proceeding of approximately $1.9 billion for the period January 1, 2019 through December 31, 2022 for a revenue increase of $85 million, adjusted for load growth. On July 14, 2023 a settlement was filed that results in a revenue increase of $70 million adjusted for load growth. Order approving the rates included in the settlement was issued September 14, 2023. TEEEF (1) 114 April 2023 December 2023 February 2024 A total Rider TEEEF revenue requirement of $188 million for cost incurred through December 31, 2022. The revenue change between the rates resulting from the 2022 TEEEF and this application is $149 million. Interim rates effective September 1, 2023. Settlement in principle announced and motion to abate filed October 12, 2023 and updated interim rates were effective December 15, 2023. The settlement incorporates an 8 1/2 year amortization period. The PUCT approved the settlement in its order that was issued February 1, 2024. TCOS 40 March 2023 May 2023 May 2023 Based on net change in invested capital of $367 million for the period August 1, 2022 through January 31, 2023. DCRF and TEEEF 117 April 2022 April 2023 April 2023 Original filing included both capital that has traditionally been recovered under DCRF and TEEEF capital; the filing was separated into traditional DCRF and TEEEF in June 2022. The traditional DCRF portion revenue requirement of $78 million was approved and was implemented September 1, 2022. A final order was issued on April 5, 2023 approving a TEEEF revenue requirement of $39 million with rates effective April 15, 2023. On April 28, 2023 and May 1, 2023 certain intervenors filed motions for rehearing of the PUCT’s April 5, 2023 order. On May 25, 2023 the PUCT issued its order on rehearing which clarified some of the findings, but did not change the approval of TEEEF cost recovery. On June 19, 2023 certain intervenors filed motions for rehearing of the May 25, 2023 order on rehearing. The PUCT denied the motions for rehearing in an order issued on August 3, 2023. See Note 7 to the consolidated financial statements for further information. CenterPoint Energy and CERC - Beaumont/East Texas, South Texas, Houston and Texas Coast (Railroad Commission) GRIP 60 March 2023 June 2023 June 2023 Based on net change in invested capital for calendar year 2022 of $390 million. Rate Case (1) 37 October 2023 TBD TBD See discussion above under Texas Gas Rate Case. 68 Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and CERC - Louisiana (LPSC) RSP 6 September 2022 May 2023 April 2023 Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band, is $3 million based on a test year ended June 2022 and adjusted ROE of 7.05%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band, is $5 million based on a test year ended June 2022 and adjusted ROE of 4.19%. The TCJA refund impact to North Louisiana and South Louisiana was $1 million and $1 million, respectively. North Louisiana and South Louisiana also seek to recover regulatory assets due to COVID-19 bad debt expenses in the amounts of $0.7 million and $0.3 million, respectively. On April 5, 2023 the LPSC issued an order approving a joint settlement for $2.7 million in North Louisiana and $4.6 million in South Louisiana in addition to the full impacts of TCJA and COVID-19 recoveries. Implementation occurred in May 2023 upon approval of compliance tariff. RSP (1) 12 September/October 2023 TBD TBD Based on ROE of 9.95% with 50 basis point (+/-) earnings band. The North Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $8 million based on a test year ended June 2023 and adjusted ROE of 3.67%. The South Louisiana increase, net of TCJA effects considered outside of the earnings band and completion of COVID-19 asset recovery, is $5 million based on a test year ended June 2023 and adjusted ROE of 5.47%. The TCJA refund impact to North Louisiana and South Louisiana was $0.6 million and $0.4 million, respectively. South Louisiana interim rates were implemented on December 28, 2023, subject to refund. North Louisiana interim rates were implemented on January 29, 2024. Staff reports issued on January 31, 2024 recommended disallowances of $0.3 million and $0.2 million in North and South Louisiana, respectively. CenterPoint Energy and CERC - Minnesota (MPUC) CIP Financial Incentive 8 May 2023 September 2023 October 2023 CIP Financial Incentive based on 2022 CIP program activity. Rate Case (1) 136 November 2023 TBD TBD See discussion above under Minnesota Rate Case. CenterPoint Energy and CERC - Mississippi RRA 7 May 2023 October 2023 October 2023 Based ROE of 10.098% with 100 basis point (+/-) earnings band. Revenue increase of approximately $8 million based on 2022 test year adjusted earned ROE of 5.66%. Interim increase of approximately $1 million implemented May 31, 2023. Settled increase of approximately $7 million approved and implemented October 3, 2023. Order authorized recovery of regulatory assets due to COVID-19 in the amount of $0.3 million over the 2024 calendar year. CenterPoint Energy - Indiana South - Gas (IURC) CSIA 3 April 2023 July 2023 July 2023 Requested an increase of $33 million to rate base, which reflects approximately $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. Also included are unrecovered deferred operations and maintenance expenses of $9 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony filed June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023. CSIA 3 October 2023 February 2024 January 2024 Requested an increase of $31 million to rate base, which reflects approximately $3 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. OUCC filed on December 8, 2023, recommending disallowance of two projects for customer-side replacements. Engineering rebuttal testimony was filed December 15, 2023, stating why costs were necessary for safety and integrity of customers and system. Responded to IURC docket entry requesting additional information on January 2, 2024. A hearing was held January 3, 2024. The IURC issued an order on January 31, 2024, approving the CSIA with the exception of the two projects for customer-side replacements which are not authorized for recovery. Indiana South filed revised revenue requirement schedules removing the two project costs with its compliance filing. Revised rates were effective February 1, 2024. 69 Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information CenterPoint Energy and CERC - Indiana North - Gas (IURC) CSIA 9 April 2023 July 2023 July 2023 Requested an increase of $95 million to rate base, which reflects approximately $9 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $5 million annually. Also included are unrecovered deferred operations and maintenance expenses of $20 million. OUCC filed on June 2, 2023, recommending approval of the proposed CSIA rates and updated plan as filed, with non-cost recommendations. Rebuttal testimony was filed on June 16, 2023. A hearing was held June 28, 2023. The IURC issued an Order approving the CSIA on July 26, 2023. CSIA 9 October 2023 January 2024 January 2024 Requested an increase of $98 million to rate base, which reflects approximately $9 million annual increase in current revenues. 80% of revenue requirement is included in requested rate increase and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $1 million annually. OUCC filed on December 8, 2023, recommending approval as filed. Responded to IURC Docket entry requesting additional information on January 2, 2024. A hearing was held January 3, 2024. The IURC issued an Order approving the CSIA on January 31, 2024 with rates effective January 31, 2024. CenterPoint Energy and CERC - Ohio (PUCO) DRR (1) 6 May 2023 September 2023 August 2023 Requested an increase of $46 million to rate base for investments made in 2022, which reflects a $6 million annual increase in current revenues. A change in (over)/under-recovery variance of $0.3 million annually is also included in rates. PUCO staff review and recommendation filed June 29, 2023, recommending approval as proposed. VEDO statement of issues resolved in case filed July 14, 2023. PUCO issued a Finding & Order approving the DRR August 23, 2023, and revised rates effective September 1, 2023. CenterPoint Energy - Indiana Electric (IURC) TDSIC 2 February 2023 June 2023 May 2023 Requested an increase of $31 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC filed on April 3, 2023, recommending approval of the proposed TDSIC rates and updated plan as filed. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the TDSIC rates and updated plan as filed with rates effective June 1, 2023. CECA — February 2023 June 2023 May 2023 Requested an increase of less than $1 million to rate base, which reflects an annual increase of less than $1 million in current revenues. The mechanism also includes a change in (over)/under-recovery variance of less than ($1 million). OUCC filed on March 31, 2023, recommending approval of the proposed CECA cost recovery with a reduction of approximately $0.3 million. Rebuttal testimony was filed on April 6, 2023. A hearing was held on May 3, 2023. On May 30, 2023, the IURC issued an order approving the CECA rates with a cost recovery reduction of approximately $0.3 million with rates effective June 6, 2023. ECA (1) 1 May 2023 February 2024 February 2024 Requested an increase of $51 million to rate base, which reflects a $1 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance of less than $1 million. A hearing was held on October 24, 2023. Indiana Electric filed a proposed order on October 31, 2023. The OUCC filed a proposed order on November 8, 2023. Indiana Electric filed a response to the OUCC proposed order on November 15, 2023. A final order was issued February 7, 2024 with rates effective February 8, 2024. DSMA (1) 16 July 2023 January 2024 November 2023 The requested $45 million is comprised primarily of the following: 2024 program costs of $11 million and $26 million of lost revenue, $3 million related to the over-recovery of 2022 program costs and $11 million under-recovery related to a prior period variance adjustment; the requested $45 million is an increase of $16 million compared to the prior DSMA. A settlement between Indiana Electric and the OUCC was reached concerning the $11 million under-recovery which resolves all issues related to the DSMA for January through December 2024 including the $11 million under-recovery. The settlement provides that the IURC should approve the DSMA and that Indiana Electric will arrange for educational training on demand side management offerings. A settlement hearing was held on October 24, 2023. The IURC issued an Order approving the settlement on November 22, 2023, with rates effective January 1, 2024. 70 Mechanism Annual Increase (Decrease) (1) (in millions) Filing Date Effective Date Approval Date Additional Information TDSIC (1) 3 August 2023 November 2023 November 2023 Requested an increase of $27 million to rate base, which reflects a $3 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($0.2 million). OUCC filed on October 2, 2023 recommending approval of the proposed TDSIC rates. A hearing was held on October 31, 2023. The IURC issued an Order approving the TDSIC on November 29, 2023, with rates effective November 30, 2023. Rate Case (1) 119 December 2023 TBD TBD See discussion above under Indiana Electric Rate Case. TDSIC (1) 5 February 2024 TBD TBD Requested an increase of $36 million to rate base, which reflects a $5 million annual increase in current revenues. 80% of the revenue requirement is included in requested rate increase and 20% is deferred until next rate case. The mechanism also includes a change in (over)/under-recovery variance and a tax reform credit for a total of ($1 million). OUCC is expected to file testimony on April 2, 2024 and a hearing is scheduled for April 30, 2024. CECA (1) — February 2024 TBD TBD Requested a decrease of $1 million to rate base, which reflects no change in current revenues. The mechanism also includes a change in (over)/under-recovery variance of $0.1 million. (1) Represents proposed increases (decreases) when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates. Inflation Reduction Act (IRA) On August 16, 2022, the IRA was signed into law. The new law extends or creates tax-related energy incentives for solar, wind and alternative clean energy sources, implements, subject to certain exceptions, a 1% tax on share repurchases after December 31, 2022, and implements a 15% CAMT based on the adjusted financial statement income of certain large corporations. Corporations are entitled to a CAMT credit to the extent CAMT liability exceeds regular tax liability, which can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT. The IRA did not have a material impact on the Registrants’ 2023 financial results. It is likely that CenterPoint Energy and the Registrant Subsidiaries will owe CAMT in excess of their regular tax liability beginning in 2024. As a result, CenterPoint Energy and the Registrant Subsidiaries expect a temporary increase in federal cash tax payments due to this provision. Greenhouse Gas Regulation and Compliance (CenterPoint Energy) On August 3, 2015, the EPA released its CPP rule, which required a 32% reduction in carbon emissions from 2005 levels. The final rule was published in the Federal Register on October 23, 2015, and that action was immediately followed by litigation ultimately resulting in the U.S. Supreme Court staying implementation of the rule. On July 8, 2019, the EPA published the ACE rule, which (i) repealed the CPP rule; (ii) replaced the CPP rule with a program that requires states to implement a program of energy efficiency improvement targets for individual coal-fired electric generating units; and (iii) amended the implementing regulations for Section 111(d) of the Clean Air Act. On January 19, 2021, the majority of the ACE rule — including the CPP repeal, CPP replacement, and the timing-related portions of the Section 111(d) implementing rule — was struck down by the U.S. Court of Appeals for the D.C. Circuit and on October 29, 2021, the U.S. Supreme Court agreed to consider four petitions filed by various coal interests and a coalition of 19 states. On June 30, 2022, the U.S. Supreme Court ruled that the EPA exceeded its authority in promulgating the CPP. On May 11, 2023, the EPA announced proposed emission limits and guidelines for carbon dioxide from fossil fuel-fired power plants under Section 111 of the Clean Air Act which, if finalized, apply new GHG performance standards for those existing coal-fired units expected to continue operation beyond December 31, 2029. We will continue to evaluate the applicability of the rule to existing and new gas-fired generating units, but would note that CenterPoint Energy does not currently have plans to operate any of its coal-fired units beyond December 2029. The Biden administration recommitted the United States to the Paris Agreement, which has driven a renewed regulatory push to require further GHG emission reductions from the energy sector and proceeded to lead negotiations at the global climate conference in Glasgow, Scotland. On April 22, 2021, President Biden announced new goals of 50% reduction of economy-wide GHG emissions, and 100% carbon-free electricity by 2035, which formed the basis of the U.S. commitments announced in Glasgow. 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. 71 Because Texas is an unregulated market, CenterPoint Energy’s Scope 2 estimates do not take into account Texas electric transmission and distribution assets in the line loss calculation and, in addition, exclude emissions related to purchased power in Indiana between 2024 and 2026 as estimated. CenterPoint Energy’s Scope 3 emissions estimates are based on the total natural gas supply delivered to residential and commercial customers as reported in the U.S. Energy Information Administration (EIA) Form EIA-176 reports and do not take into account the emissions of transport customers and emissions related to upstream extraction. These emission goals are expected to be used to position CenterPoint Energy to comply with anticipated future regulatory requirements from the current and future administrations to further reduce GHG emissions. 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, and the EPA has proposed new regulations targeting reductions in methane emissions, which if implemented will increase costs related to production, transmission and storage of natural gas. Houston Electric, in contrast to some electric utilities including Indiana Electric, does not generate electricity, other than 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. 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. 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 fossil 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 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. 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 emissions goals, CenterPoint Energy is expected 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. Climate Change Trends and Uncertainties As a result of increased awareness regarding climate change, coupled with adverse economic conditions, availability of alternative energy sources, including private solar, microturbines, fuel cells, energy-efficient buildings and energy storage devices, and new regulations restricting emissions, including potential regulations of methane emissions, some consumers and companies may use less energy, meet their own energy needs through alternative energy sources or avoid expansions of their facilities, including natural gas facilities, resulting in less demand for the Registrants’ services. As these technologies become a more cost-competitive option over time, whether through cost effectiveness or government incentives and subsidies, certain customers may choose to meet their own energy needs and subsequently decrease usage of the Registrants’ systems and services, which may result in, among other things, Indiana Electric’s generating facilities becoming less competitive and economical. Further, evolving investor sentiment related to the use of fossil fuels and initiatives to restrict continued production of fossil fuels have had significant impacts on CenterPoint Energy’s electric generation and natural gas businesses. For example, because Indiana Electric’s current generating facilities substantially rely on coal for their operations, certain financial institutions choose not to participate in CenterPoint Energy’s financing arrangements. Conversely, demand for the Registrants’ 72 services may increase as a result of customer changes in response to climate change. For example, as the utilization of electric vehicles increases, demand for electricity may increase, resulting in increased usage of CenterPoint Energy’s systems and services. Any negative opinions with respect to CenterPoint Energy’s environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, investors, legislators or other stakeholders could harm its reputation. To address these developments, CenterPoint Energy announced its net zero emissions goals for both Scope 1 emissions and certain Scope 2 emissions by 2035. 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 continues to execute on its 2019/2020 IRP and has received initial approvals for 756 MWs of the 700-1,000 MWs identified within Indiana Electric’s 2019/2020 IRP. Additionally, as reflected in its 10-year capital plan announced in September 2021, CenterPoint Energy anticipates spending over $3 billion in cleaner energy investments and enablement, which may be used to support, among other things, renewable energy generation and electric vehicle expansion. CenterPoint Energy believes its planned investments in renewable energy generation and corresponding planned reduction in its GHG emissions as part of its net zero emissions goals support global efforts to reduce the impacts of climate change. Indiana Electric has conducted a new IRP, which was submitted to the IURC in May 2023, to identify an appropriate generation resource portfolio to satisfy the needs of its customers and comply with environmental regulations. The proposed preferred portfolio is the second evolution to the generation transition plan to move away from coal-fired generation to a more sustainable portfolio of resources. Indiana Electric plans to convert its last remaining coal unit to natural gas by 2027 and to add a significant amount of additional renewable resources through 2033. For more information regarding CenterPoint Energy’s net zero emission goals and the risks associated with them, see “Risk Factors — Risk Factors Affecting Regulatory, Environmental and Legal Risks — CenterPoint Energy is subject to operational and financial risks...” To the extent climate changes result in warmer temperatures in the Registrants’ service territories, financial results from the Registrants’ businesses could be adversely impacted. For example, CenterPoint Energy’s and CERC’s Natural Gas could be adversely affected through lower natural gas sales. On the other hand, warmer temperatures in CenterPoint Energy’s and Houston Electric’s electric service territory may increase revenues from transmission and distribution and generation through increased demand for electricity used for cooling. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes and flooding, including such storms as the February 2021 Winter Storm Event. Since many of the Registrants’ facilities are located along or near the Texas gulf coast, increased or more severe hurricanes or tornadoes could increase costs to repair damaged facilities and restore service to customers. CenterPoint Energy’s current 10-year capital plan includes capital expenditures to maintain reliability and safety and increase resiliency of its systems as climate change may result in more frequent significant weather events. Houston Electric does not own or operate any electric generation facilities other than, since September 2021, its operation of TEEEF. Houston Electric transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. To the extent adverse weather conditions affect the Registrants’ suppliers, results from their energy delivery businesses may suffer. For example, in Texas, the February 2021 Winter Storm Event caused an electricity generation shortage that was severely disruptive to Houston Electric’s service territory and the wholesale generation market and also caused a reduction in available natural gas capacity. When the Registrants cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Registrants’ financial results can be impacted by lost revenues, and they generally must seek approval from regulators to recover restoration costs. To the extent the Registrants are unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Registrants’ future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact our ability to secure cost-efficient insurance. Other Matters Credit Facilities The Registrants may draw on their respective revolving credit facilities from time to time to provide funds used for general corporate and limited liability company purposes, including to backstop CenterPoint Energy’s and CERC’s commercial paper programs. The facilities may also be utilized to obtain letters of credit. For further details related to the Registrants’ revolving credit facilities, please see Note 13 to the consolidated financial statements. Based on the consolidated debt to capitalization covenant in the Registrants’ revolving credit facilities, the Registrants would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated approximately $4.0 billion as of December 31, 2023. 73 As of February 12, 2024, the Registrants had the following revolving credit facilities and utilization of such facilities: Amount Utilized as of February 12, 2024 Registrant Size of Facility Loans Letters of Credit Commercial Paper Weighted Average Interest Rate Termination Date (in millions) CenterPoint Energy $ 2,400 $ — $ — $ 1,272 5.51% December 6, 2027 CenterPoint Energy (1) 250 — — — —% December 6, 2027 Houston Electric 300 — — — —% December 6, 2027 CERC 1,050 — 1 359 5.49% December 6, 2027 Total $ 4,000 $ — $ 1 $ 1,631 (1) This credit facility was issued by SIGECO. Borrowings under each of the revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower makes representations prior to borrowing as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the revolving credit facilities, the spread to SOFR and the commitment fees fluctuate based on the borrower’s credit rating. Each of the Registrant’s credit facilities provide for a mechanism to replace SOFR with possible alternative benchmarks upon certain benchmark replacement events. The borrowers are currently in compliance with the various business and financial covenants in the four revolving credit facilities. Debt Transactions For detailed information about the Registrants’ debt transactions in 2023, see Note 13 to the consolidated financial statements. Securities Registered with the SEC On May 17, 2023, the Registrants filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of Houston Electric’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of shares of Common Stock, shares of preferred stock, depositary shares, as well as stock purchase contracts and equity units. The joint shelf registration statement will expire on May 17, 2026. For information related to the Registrants’ debt issuances in 2023, see Note 13 to the consolidated financial statements. Temporary Investments As of February 12, 2024, the Registrants had no temporary investments. Money Pool The Registrants participate in a money pool through which they and certain of their subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the CenterPoint Energy money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The net funding requirements of the CERC money pool are expected to be met with borrowings under CERC’s revolving credit facility or the sale of CERC’s commercial paper. The money pool may not provide sufficient funds to meet the Registrants’ cash needs. The table below summarizes CenterPoint Energy money pool activity by Registrant as of February 12, 2024: Weighted Average Interest Rate Houston Electric CERC (in millions) Money pool investments 5.57% $ 60 $ — 74 Impact on Liquidity of a Downgrade in Credit Ratings The interest rate on borrowings under the Registrants’ credit facilities is based on their respective credit ratings. As of February 12, 2024, Moody’s, S&P and Fitch had assigned the following credit ratings to senior debt of the Registrants: Moody’s S&P Fitch Registrant Borrower/Instrument Rating Outlook (1) Rating Outlook (2) Rating Outlook (3) CenterPoint Energy CenterPoint Energy Senior Unsecured Debt Baa2 Stable BBB Stable BBB Stable CenterPoint Energy Vectren Corp. Issuer Rating n/a n/a BBB+ Stable n/a n/a CenterPoint Energy SIGECO Senior Secured Debt A1 Stable A Stable n/a n/a Houston Electric Houston Electric Senior Secured Debt A2 Stable A Stable A Stable CERC CERC Corp. Senior Unsecured Debt A3 Stable BBB+ Stable A- Stable CERC Indiana Gas Senior Unsecured Debt n/a n/a BBB+ Stable n/a n/a (1) A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term. (2) An S&P outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period. The Registrants cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. The Registrants note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold the Registrants’ securities and may be revised or withdrawn at any time by the rating agency. 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 a material adverse impact on the Registrants’ ability to obtain short- and long-term financing, the cost of such financings and the execution of the Registrants’ commercial strategies. A decline in credit ratings could increase borrowing costs under the Registrants’ revolving credit facilities. If the Registrants’ credit ratings had been downgraded one notch by S&P and Moody’s from the ratings that existed as of December 31, 2023, the impact on the borrowing costs under the four revolving credit facilities would have been insignificant. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact the Registrants’ ability to complete capital market transactions and to access the commercial paper market. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of CenterPoint Energy’s and CERC’s Natural Gas reportable segments. Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC might need to provide cash or other collateral of as much as $256 million as of December 31, 2023. The amount of collateral will depend on seasonal variations in transportation levels. ZENS and Securities Related to ZENS (CenterPoint Energy) If CenterPoint Energy’s creditworthiness were to drop such that ZENS holders thought its liquidity was adversely affected or the market for the ZENS were to become illiquid, some ZENS holders might decide to exchange their ZENS for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of ZENS-Related Securities that CenterPoint Energy owns or from other sources. 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. ZENS exchanges result in a cash outflow because tax deferrals related to the ZENS and shares of ZENS-Related Securities would typically cease when ZENS are exchanged or otherwise retired and shares of ZENS-Related Securities are sold. The ultimate tax liability related to the ZENS and ZENS-Related Securities continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement or exchange of the ZENS. If all ZENS had been exchanged for cash on December 31, 2023, deferred taxes of approximately $728 million would have been payable in 2023. If all the ZENS-Related Securities had been sold on December 31, 2023, capital gains taxes of approximately $81 million 75 would have been payable in 2023 based on 2023 tax rates in effect. For additional information about ZENS, see Note 11 to the consolidated financial statements. Cross Defaults Under each of CenterPoint Energy’s, Houston Electric’s and CERC’s respective revolving credit facilities and CERC’s term loan agreement, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $125 million by the borrower or any of their respective significant subsidiaries will cause a default under such borrower’s respective credit facility or term loan agreement. Under SIGECO’s revolving credit facility, a payment default on, or a non-payment default, event or condition that permits acceleration of, any indebtedness for borrowed money and certain other specific types of obligations (including guarantees) exceeding $75 million by SIGECO or any of its significant subsidiaries will cause a default under SIGECO’s credit facility. A default by CenterPoint Energy would not trigger a default under its subsidiaries’ debt instruments or revolving credit facilities. Possible Acquisitions, Divestitures and Joint Ventures From time to time, the Registrants consider the acquisition or the disposition of assets or businesses or possible joint ventures, strategic initiatives or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. The Registrants may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to the Registrants at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions. CenterPoint Energy has increased its planned capital expenditures in its Electric and Natural Gas businesses multiple times over the recent years to support rate base growth. The Registrants may continue to explore asset sales as a means to efficiently finance a portion of its increased capital expenditures in the future, subject to the conditions listed above. For further information, see Note 4. 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 local distribution company businesses. The transaction is expected to close in the first quarter of 2025. For further information, see Note 21 to the consolidated financial statements. Hedging of Interest Expense for Future Debt Issuances From time to time, the Registrants may enter into interest rate agreements to hedge, in part, volatility in the U.S. treasury rates by reducing variability in cash flows related to interest payments. For further information, see Note 9(a) to the consolidated financial statements. Collection of Receivables from REPs (CenterPoint Energy and Houston Electric) Houston Electric’s receivables from the distribution of electricity are collected from REPs that supply the electricity Houston Electric distributes to their customers. Before conducting business, a REP must register with the PUCT and must meet certain financial qualifications. Nevertheless, adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for Houston Electric’s services or could cause them to delay such payments. Houston Electric depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect Houston Electric’s cash flows. In the event of a REP’s default, Houston Electric’s tariff provides a number of remedies, including the option for Houston Electric to request that the PUCT suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, Houston Electric remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were 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 against Houston Electric involving payments it had received from such REP. If a REP were to file for bankruptcy, Houston Electric may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, PUCT regulations authorize utilities, such as Houston Electric, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity. 76 Other Factors that Could Affect Cash Requirements In addition to the above factors, the Registrants’ liquidity and capital resources could also be negatively affected by: • cash collateral requirements that could exist in connection with certain contracts, including weather hedging arrangements, and natural gas purchases, natural gas price and natural gas storage activities of CenterPoint Energy’s and CERC’s Natural Gas reportable segment; • acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased natural gas prices, and concentration of natural gas suppliers (CenterPoint Energy and CERC); • increased costs related to the acquisition of natural gas (CenterPoint Energy and CERC); • increases in interest expense in connection with debt refinancings and borrowings under credit facilities or term loans or the use of alternative sources of financings on capital and other financial markets; • various legislative or regulatory actions; • incremental collateral, if any, that may be required due to regulation of derivatives (CenterPoint Energy and CERC); • the ability of REPs, including REP affiliates of NRG and Vistra Energy Corp., to satisfy their obligations to CenterPoint Energy and Houston Electric; • slower customer payments and increased write-offs of receivables due to higher natural gas prices, changing economic conditions, public health threats or severe weather events (CenterPoint Energy and CERC); • the satisfaction of any obligations pursuant to guarantees; • the outcome of litigation, including litigation related to the February 2021 Winter Storm Event; • contributions to pension and postretirement benefit plans; • restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and • various other risks identified in “Risk Factors” in Item 1A of Part I of this report. Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money Certain provisions in certain note purchase agreements relating to debt issued by CERC have the effect of restricting the amount of secured debt issued by CERC and debt issued by subsidiaries of CERC Corp. Additionally, Houston Electric and SIGECO are limited in the amount of mortgage bonds they can issue by the General Mortgage and SIGECO’s mortgage indenture, respectively. For information about the total debt to capitalization financial covenants in the Registrants’ and SIGECO’s revolving credit facilities, see Note 13 to the consolidated financial statements. CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of the Registrants’ financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in the Registrants’ historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require the Registrants to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that the Registrants could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of their financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. The Registrants base their estimates on historical experience and on various other assumptions that they believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Registrants’ operating environment changes. The Registrants’ significant accounting policies are discussed in Note 2 to the consolidated financial statements. The Registrants believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of CenterPoint Energy’s Board of Directors. Accounting for Rate Regulation Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. CenterPoint Energy, for its Electric and Natural Gas reportable segments, Houston Electric and CERC apply this 77 accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items wil