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SOUTHERN INDIANA GAS & ELECTRIC COMPANY CONSOLIDATED FINANCIAL STATEMENTS As of and for the years ended December 31, 2024 and 2023 Contents Page Number Audited Consolidated Financial Statements Glossary 1-2 Independent Auditor's Report 3-4 Consolidated Balance Sheets 5 Statements of Consolidated Income 6 Statements of Consolidated Cash Flows 7 Statements of Consolidated Changes in Equity 8 Notes to the Consolidated Financial Statements 9-34 Exhibit 99.1

GLOSSARY AFUDC Allowance for funds used during construction AGC Alcoa Generating Corporation, a subsidiary of Alcoa, Inc. AMAs Asset Management Agreements Arevon Arevon Energy, Inc., which was formed through the combination of Capital Dynamics, Inc.’s U.S. Clean Energy Infrastructure business unit and Arevon Asset Management ARO Asset Retirement Obligation ARP Alternative Revenue Program ASC Accounting Standards Codification ASU Accounting Standard Update BTA Build Transfer Agreement CAMT Corporate Alternative Minimum Tax CCR Coal Combustion Residuals CCR Legacy Rule The final rule titled Hazardous and Solid Waste Management System: Disposal of Coal Combustion Residuals from Electric Utilities; Legacy CCR Surface Impoundments published in the federal register by the EPA in May 2024 CECA Clean Energy Cost Adjustment CODM Chief Operating Decision Maker CPCN Certificate of Public Convenience and Necessity Credit Agreement Credit Agreement, dated as of December 6, 2022, by and among CEI South, as borrower, Wells Fargo Bank, National Association, as administrative agent, the financial institutions as banks parties thereto and the other parties thereto CSIA Compliance and System Improvement Adjustment DSMA Demand Side Management Adjustment DOC U.S. Department of Commerce ECA Environmental Cost Adjustment EEFC Energy Efficiency Funding Component ELG Effluent Limitation Guidelines EPA Environmental Protection Agency Extension Agreement Extension Agreement to the Credit Agreement, dated as of January 29, 2025, by and among CEI South, Wells Fargo Bank, National Association, as administrative agent and the banks party thereto FASB Financial Accounting Standards Board FERC Federal Energy Regulation Commission GAAP Generally Accepted Accounting Principles GHG Greenhouse gases IDEM Indiana Department of Environmental Management IRA Inflation Reduction Act of 2022 IRP Integrated Resource Plan IRS Internal Revenue Service IURC Indiana Utility Regulatory Commission LIBOR London Interbank Offered Rate LIFO Last In - First Out inventory method 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 1

MGP Manufactured gas plant MISO Midcontinent Independent System Operator MW Megawatts NYMEX New York Mercantile Exchange Oriden Oriden LLC Origis Origis Energy USA Inc. Posey Solar Posey Solar, LLC, a Delaware limited liability company Posey Solar Merger Agreement Agreement and Plan of Merger, dated as of March 7, 2025, among CEI South and Posey Solar PowerTeam Services PowerTeam Services, LLC, a Delaware limited liability company, now known as Artera Services, LLC PPA Power purchase agreement PRP Potentially responsible parties PTCs Production Tax Credits RCRA Resource Conservation and Recovery Act of 1976 ROE Return on equity 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 Securitization Bonds Securitization Subsidiary’s Series 2023-A Senior Secured Securitization Bonds Securitization Subsidiary SIGECO Securitization I, LLC, a direct, wholly-owned subsidiary of the Company SOFR Secured Overnight Financing Rate SRC Sales Reconciliation Component TCJA Tax reform legislation informally called the Tax Cuts and Jobs Act of 2017 TDSIC Transmission, Distribution and Storage System Improvement Charge 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, Inc. as of the Merger Date, and, after the Restructuring, is held indirectly by CenterPoint Energy through Vectren Affiliated Utilities, Inc. VIE Variable interest entity VRP Voluntary Remediation Program VUH Vectren Utility Holdings, LLC, which converted its corporate structure from Vectren Utility Holdings, Inc. to a limited liability company on June 30, 2022, a wholly- owned subsidiary of Vectren LLC VUSI Vectren Utility Services, Inc., a wholly-owned subsidiary of Vectren 2

INDEPENDENT AUDITOR'S REPORT To the Management of Southern Indiana Gas and Electric Company Opinion We have audited the consolidated financial statements of Southern Indiana Gas and Electric Company (a wholly owned subsidiary of Vectren Utility Holdings, LLC) (the "Company"), which comprise the consolidated balance sheets as of December 31, 2024 and 2023, and the related consolidated statements of income, changes in equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements (collectively referred to as the "financial statements"). In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America. Basis for Opinion We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Responsibilities of Management for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company's ability to continue as a going concern for one year after the date that the financial statements are issued. Auditor's Responsibilities for the Audit of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements. In performing an audit in accordance with GAAS, we: • Exercise professional judgment and maintain professional skepticism throughout the audit. • Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, no such opinion is expressed. • Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements. • Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company's ability to continue as a going concern for a reasonable period of time. 3

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit. Other Information Included in the Financial and Operational Data of Southern Indiana Gas & Electric Company Management is responsible for the other information included in the Financial and Operational Data of Southern Indiana Gas & Electric Company. The other information comprises the information included in the Financial and Operational Data of Southern Indiana Gas & Electric Company but does not include the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon. In connection with our audits of the financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report. /s/ DELOITTE & TOUCHE LLP Houston, Texas March 18, 2025 4

FINANCIAL STATEMENTS SOUTHERN INDIANA GAS & ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31, 2024 2023 (in millions) ASSETS Current Assets: Cash and cash equivalents ($7 and $14 related to VIEs, respectively) $ 9 $ 14 Accounts receivable ($1 and $2 related to VIEs, respectively), less allowance for credit losses of $2 and $2, respectively 54 47 Accrued unbilled revenues ($2 and $2 related to VIEs, respectively), less allowance for credit losses of $-0- and $-0-, respectively 46 45 Accounts and notes receivable - affiliated companies 17 — Inventories 79 96 Prepaid expenses and other current assets ($2 and $2 related to VIEs, respectively) 18 44 Total current assets 223 246 Property, Plant and Equipment, Net: Property, plant and equipment 4,773 4,625 Less: accumulated depreciation and amortization 1,524 1,636 Property, Plant and Equipment, net 3,249 2,989 Other Assets: Goodwill 6 6 Regulatory assets ($313 and $329 related to VIEs, respectively) 561 547 Other non-current assets 61 52 Total other assets 628 605 Total Assets $ 4,100 $ 3,840 LIABILITIES AND SHAREHOLDER'S EQUITY Current Liabilities: Accounts payable $ 82 $ 95 Accounts and notes payable - affiliated companies 31 75 Accrued liabilities 89 93 Current maturities of long-term debt - VIE Securitization Bonds 13 17 Current maturities of long-term debt - third parties 41 23 Current maturities of long-term debt - affiliated companies 106 — Total current liabilities 362 303 Other Liabilities: Deferred income taxes 343 309 Regulatory liabilities 250 300 Other non-current liabilities 227 206 Total other liabilities 820 815 Long-Term Debt: Long-term debt - VIE Securitization Bonds, net 308 320 Long-term debt - third parties, net 939 821 Long-term debt - affiliated companies 150 256 Total long-term debt, net 1,397 1,397 Commitments and Contingencies (Note 8) Shareholder's Equity: Common stock (no par value) 644 539 Retained earnings 877 786 Total shareholder's equity 1,521 1,325 Total Liabilities and Shareholder's Equity $ 4,100 $ 3,840 The accompanying notes are an integral part of these financial statements 5

SOUTHERN INDIANA GAS & ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED INCOME Year Ended December 31, 2024 2023 (in millions) Revenues: Electric utility revenues $ 617 $ 595 Gas utility revenues 121 128 Securitization Subsidiary 33 17 Total 771 740 Expenses: Fuel and purchased power 198 176 Utility natural gas 29 30 Operation and maintenance 179 251 Depreciation and amortization, excluding Securitization Subsidiary 120 138 Amortization - Securitization Subsidiary 16 8 Taxes other than income taxes 12 12 Total 554 615 Operating Income 217 125 Other Income (Expense): Interest expense, excluding Securitization Subsidiary (50) (50) Interest expense - Securitization Subsidiary (17) (9) Other income, net 19 35 Income Before Income Taxes 169 101 Income tax expense 22 21 Net Income $ 147 $ 80 The accompanying notes are an integral part of these financial statements 6

SOUTHERN INDIANA GAS & ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED CASH FLOWS Year Ended December 31, 2024 2023 Cash Flows from Operating Activities: (in millions) Net income $ 147 $ 80 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 136 146 Deferred income taxes and investment tax credits 11 8 Changes in working capital accounts: Accounts receivable and accrued unbilled revenue (10) 8 Accounts receivables/payable-affiliated companies — 13 Accounts payable (6) (13) Inventories 17 6 Net regulatory assets and liabilities (32) (23) Other current assets and liabilities 21 11 Other non-current assets and liabilities (2) 1 Other operating activities, net (10) (11) Net cash provided by operating activities 272 226 Cash Flows from Investing Activities: Capital expenditures (389) (495) Increase in notes receivable–affiliated companies (11) — Other investing activities, net 3 4 Net cash used in investing activities (397) (491) Cash Flows from Financing Activities: Net change in short-term notes payable - affiliated companies (50) 14 Payment of long-term notes payable - affiliated companies — (524) Proceeds from long-term debt - third parties 160 650 Payment of long-term debt - third parties, including make-whole premiums (22) (102) Proceeds of VIE Securitization Bonds — 341 Payment of VIE Securitization Bonds (17) — Debt issuance cost (1) (9) Contribution from VUH 105 — Dividends to VUH (56) (93) Net cash provided by financing activities 119 277 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash (6) 12 Cash, Cash Equivalents and Restricted Cash at Beginning of Year 17 5 Cash, Cash Equivalents and Restricted Cash at End of Year $ 11 $ 17 The accompanying notes are an integral part of these financial statements 7

SOUTHERN INDIANA GAS & ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY Common Stock Retained Earnings Total Shareholder's Equity (in millions) Balance at January 1, 2023 $ 539 $ 799 $ 1,338 Net income — 80 80 Dividends to VUH — (93) (93) Balance at December 31, 2023 $ 539 $ 786 $ 1,325 Net income — 147 147 Contribution from VUH 105 — 105 Dividends to VUH — (56) (56) Balance at December 31, 2024 $ 644 $ 877 $ 1,521 The accompanying notes are an integral part of these financial statements 8

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (1) Background and Basis of Presentation Background. Southern Indiana Gas and Electric Company (the "Company" or "CEI South"), an Indiana corporation, provides energy delivery services to 153,407 electric customers and 115,991 gas customers located near Evansville in southwestern Indiana. Of these customers, 88,017 receive combined electric and gas distribution services. The Company also owns and operates electric generation assets to serve its electric customers and optimizes those assets in the wholesale power market. The Company is a direct, wholly-owned subsidiary of VUH (the Company's parent). VUH is a direct, wholly owned subsidiary of Vectren. Vectren, an indirect, wholly owned subsidiary of CenterPoint Energy, Inc. (collectively with its subsidiaries, "CenterPoint Energy"), is an energy holding company headquartered in Evansville, Indiana. Basis of Presentation and Principles of Consolidation. The accompanying consolidated financial statements are prepared in conformity with GAAP. The accounts of the Company and its wholly-owned subsidiary are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. As of December 31, 2024, the Company had a VIE Securitization Subsidiary, which is consolidated. The consolidated VIE is a wholly-owned, bankruptcy-remote, special purpose entity that was formed solely for the purpose of facilitating the securitization financing of qualified costs. The Company has a controlling financial interest in the Securitization Subsidiary and is the VIE’s primary beneficiary. For further information, see Note 9. Creditors of the Company have no recourse to any assets or revenues of the Securitization Subsidiary, as applicable. The Securitization Bonds issued by the VIE are payable only from and secured by securitization property and the bondholders have no recourse to the general credit of the Company. (2) Summary of Significant Accounting Policies (a) Use of Estimates The preparation of the consolidated financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the amounts reported in these financial statements and related footnotes. Examples of transactions for which estimation techniques are used include valuing deferred tax obligations, unbilled revenue, uncollectible accounts, regulatory assets and liabilities, asset retirement obligations, and derivatives and other financial instruments. Estimates also impact the depreciation of property, plant and equipment and the testing of goodwill and other assets for impairment. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Actual results could differ from those estimates. (b) Cash and Cash Equivalents and Restricted Cash For purposes of reporting cash flows, the Company considers cash equivalents to be short-term, highly-liquid investments with maturities of three months or less from the date of purchase. Cash and cash equivalents held by the Company's Securitization Subsidiary (which is a VIE) solely to support servicing the Securitization Bonds as of December 31, 2024 and 2023 are reflected on the Company's Consolidated Balance Sheets. Cash and cash equivalents are stated at cost plus accrued interest to approximate fair value. In connection with the issuance of Securitization Bonds, the Company was required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds and are not included in cash and cash equivalents. For more information on restricted cash, see Note 13. (c) Accounts Receivable and Allowance for Credit Losses Accounts receivable are recorded at the invoiced amount and do not bear interest. The Company reviews historical write-offs, current available information, and reasonable and supportable forecasts to estimate and establish allowance for credit losses. Account balances are charged off against the allowance when the Company determines it is probable that the receivable will not be recovered. 9

(d) Inventories The Company's inventory consists principally of materials and supplies, coal, and natural gas. Materials and supplies are valued at the lower of average cost or market, and are recorded to inventory when purchased and subsequently charged to expense or capitalized to plant when installed. Inventory related to regulated operations is valued at historical cost consistent with ratemaking treatment. Coal inventory is valued at average cost. Natural gas in storage is recorded using the last in, first out ("LIFO") method. Balances in inventories were as follows: December 31, 2024 2023 (in millions) Materials and supplies $ 43 $ 56 Coal and oil for electric generation 15 19 Natural gas in storage 21 21 Total inventories $ 79 $ 96 Based on the average cost of natural gas purchased during December 2024, the cost of replacing natural gas in storage carried at LIFO cost was $5 million less than the carrying value at December 31, 2024. The Company sources most of its coal supply from one third party and also purchases most of its natural gas from a different single third party. Rates charged to natural gas customers contain a gas cost adjustment clause and electric rates contain a fuel adjustment clause that allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel. (e) Long-lived Assets The Company records property, plant and equipment at historical cost and expenses repair and maintenance costs as incurred. The Company periodically evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Recoverability of long-lived assets is assessed by determining if a capital disallowance from a regulator is probable through monitoring the outcome of rate cases and other proceedings. No long-lived asset impairments or disallowances were recorded in 2024 or 2023. The Company computes depreciation and amortization using the straight-line method based on economic lives or regulatory- mandated recovery periods. Amortization expense includes amortization of certain regulatory assets. (f) Goodwill The Company performs goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Goodwill is evaluated for impairment by performing a qualitative assessment or using a quantitative test. If the Company chooses to perform a qualitative assessment and determines it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the quantitative test is then performed; otherwise, no further testing is required. The quantitative test, if required, is performed by comparing the fair value of each reporting unit with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is primarily determined based on an income approach or a weighted combination of income and market approaches. When the carrying amount is in excess of the estimated fair value of the reporting unit, the excess amount is recorded as an impairment charge, not to exceed the carrying amount of goodwill. The Company includes deferred tax assets and liabilities within its reporting unit’s carrying value for the purposes of annual and interim impairment tests, regardless of whether the estimated fair value reflects the disposition of such assets and liabilities. Goodwill is reported in the Company's Natural Gas reporting segment. The Company performed the annual goodwill impairment tests in the third quarter of 2024 and determined that no goodwill impairment charge was required. (g) Capitalization of AFUDC and Deferral of Interest The Company capitalizes AFUDC as a component of projects under construction and amortizes it over the assets’ estimated useful lives once the assets are placed in service. Additionally, the Company defers interest costs into a regulatory asset when amounts are probable of recovery. Deferred debt interest is amortized over the recovery period for rate-making purposes. AFUDC represents the composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction as the Company applies the guidance for accounting for regulated operations. Although AFUDC increases both property, plant and 10

equipment and earnings, it is realized in cash when the assets are included in rates. The table below sets forth capitalized AFUDC and deferred debt interest costs for the periods presented: Year Ended December 31, 2024 2023 (in millions) AFUDC – borrowed funds (1) $ 6 $ 8 AFUDC – equity funds (2) 16 16 Deferred debt interest (3) 5 5 (1) Included in Interest expense, excluding Securitization Subsidiary on the Company's Statements of Consolidated Income. (2) Included in Other income, net on the Company’s Statements of Consolidated Income. (3) Represents the amount of deferred debt interest on certain regulatory assets that are authorized to earn a return, such as debt post in-service carrying costs on property, plant and equipment and is included in Interest expense, excluding Securitization Subsidiary on the Company's Statements of Consolidated Income. (h) Regulation Retail public utility operations are subject to regulation by the IURC. The Company is subject to FERC regulation as an electric public utility. The Company’s accounting policies give recognition to the ratemaking and accounting practices authorized by these agencies. (i) Refundable or Recoverable Gas Costs and Cost of Fuel and Purchased Power All metered gas rates contain a gas cost adjustment clause that allows the Company to charge for changes in the cost of purchased gas. Metered electric rates contain a fuel adjustment clause that allows for adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to a variable benchmark based on NYMEX natural gas prices, is also recovered through regulatory proceedings. The Company records any under or over-recovery resulting from gas and fuel adjustment clauses each month in revenues. A corresponding regulatory asset or liability is recorded until the under or over-recovery is billed or refunded to utility customers. The cost of gas sold is charged to operating expense as delivered to customers, and the cost of fuel and purchased power for electric generation is charged to operating expense when consumed. (j) Regulatory Assets and Liabilities The Company applies the guidance for accounting for regulated operations within its Electric reportable segment and the Natural Gas reportable segment. The Company's rate-regulated subsidiaries may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. The Company's rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. In addition, a portion of the amount of removal costs collected from customers that relate to AROs has been reflected as an asset retirement liability in accordance with accounting guidance for AROs. For further detail on the Company's regulatory assets and liabilities, see Note 5. (k) Environmental Costs The Company (i) expenses or capitalizes environmental expenditures, as appropriate, depending on their future economic benefit; (ii) expenses amounts that relate to an existing condition caused by past operations that do not have future economic benefit; and (iii) records undiscounted liabilities related to these future costs when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. (l) Income Taxes The Company does not file federal or state income tax returns separate from those filed by Vectren or CenterPoint Energy. Vectren is included in CenterPoint Energy's U.S. federal consolidated income tax return. Vectren and certain subsidiaries are also included in various unitary or consolidated state income tax returns with CenterPoint Energy. In other state jurisdictions, Vectren and certain subsidiaries continue to file separate state tax returns. The Company records income taxes for each jurisdiction on a separate company basis. 11

Deferred income taxes are provided for temporary differences between the tax basis (adjusted for related unrecognized tax benefits, if any) of an asset or liability and its reported amount in the financial statements. Deferred tax assets and liabilities are computed based on the currently-enacted statutory income tax rates that are expected to be applicable when the temporary differences are scheduled to reverse. The Company recognizes regulatory liabilities for deferred taxes provided in excess of the current statutory tax rate and regulatory assets for deferred taxes provided at rates less than the current statutory tax rate. Such tax-related regulatory assets and liabilities are reported at the revenue requirement level and amortized to income as the related temporary differences reverse, generally over the lives of the related properties. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the deferred tax assets will be realized. Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company reports interest and penalties associated with unrecognized tax benefits within Income taxes in the Statements of Income and reports tax liabilities related to unrecognized tax benefits as part of Other non-current liabilities. Investment tax credits are deferred and amortized to income over the approximate lives of the related property. Production tax credits extended by the IRA may be used to reduce current federal income taxes payable. (m) Revenue Revenue is recognized when obligations under the terms of a contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring goods or providing services. The satisfaction of performance obligation occurs when the transfer of goods and services occur, which may be at a point in time or over time, resulting in revenue being recognized over the course of the underlying contract or at a single point in time based upon the delivery of services to customers. For further discussion, see Note 3. (n) MISO Transactions The Company is a member of the MISO. 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, in which net purchases within that interval are recorded as Utility natural gas and Fuel and purchased power, and net sales within that interval are recorded as Electric utility revenues on the Company's Statements of Consolidated Income. On occasion, prior period transactions are resettled outside the routine process due to a change in the MISO’s tariff or a material interpretation thereof. Expenses associated with resettlements are recorded once the resettlement is probable and the resettlement amount can be estimated. Revenues associated with resettlements are recognized when the amount is determinable and collectability is reasonably assured. The Company also receives transmission revenue that results from transmission customers’ use of the Company’s transmission system. These revenues are also included in Electric utility revenues on the Company's Statements of Consolidated Income. 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 / refunded to retail customers through tracking mechanisms. (o) Fair Value Measurements Certain assets and liabilities are valued and disclosed at fair value. Nonfinancial assets and liabilities include the initial measurement of an asset retirement obligation or the use of fair value in goodwill and long-lived assets impairment tests. FASB guidance provides the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are described as follows: 12

Level 1 Inputs to the valuation methodology are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access. Level 2 Inputs to the valuation methodology include · quoted prices for similar assets or liabilities in active markets; · quoted prices for identical or similar assets or liabilities in inactive markets; · inputs other than quoted prices that are observable for the asset or liability; · inputs that are derived principally from or corroborated by observable market data by correlation or other means If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability. Level 3 Inputs to the valuation methodology are unobservable and significant to the fair value measurement. The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used maximize the use of observable inputs and minimize the use of unobservable inputs. (p) Other Significant Policies Included elsewhere in these notes are significant accounting policies related to retirement plans and other postretirement benefits, intercompany allocations and income taxes. See Note 6 for further information. (q) Recent Accounting Pronouncements On December 31, 2024, the Company adopted ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”), which updates segment disclosure requirements through enhanced disclosures around significant segment expenses. The Company applied the provision retrospectively to all periods presented for the Company's reportable segments as further described. See Note 12 for further discussion of the Company's segment reporting. In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income (Topic 220): Expense Disaggregation Disclosures (“ASU 2024-03”). This ASU improves disclosure of a public business entity’s expense by requiring disaggregated disclosure of expenses in commonly presented expense captions. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and for interim periods beginning after December 15, 2027. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements. In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures (“ASU 2023-09”). This ASU enhances the transparency of income tax disclosures related to rate reconciliation and income taxes. ASU 2023-09 is effective for annual periods beginning after December 15, 2024. Early adoption is permitted. The Company is currently evaluating the impact of this ASU on its consolidated financial statements. Management believes that all other recently adopted and recently issued accounting standards that are not yet effective will not have a material impact on the Company's financial position, results of operations or cash flows upon adoption. (3) Revenue Recognition In accordance with ASC 606, Revenue from Contracts with Customers, revenue is recognized when a customer obtains control of promised goods or services. The amount of revenue recognized reflects the consideration to which the Company expects to be entitled to receive in exchange for these goods or services. ARPs are contracts between the utility and its regulators, not between the utility and a customer. The Company recognizes ARP revenue as other revenues when the regulator-specified conditions for recognition have been met. Upon recovery of ARP revenue through incorporation in rates charged for utility service to customers, ARP revenue is reversed and recorded as revenue from contracts with customers. The recognition of ARP revenues and the reversal of ARP revenues upon recovery through rates charged for utility service may not occur in the same period. The Company provides commodity service to customers at rates, charges, and terms and conditions included in tariffs approved by regulators. The Company bills customers monthly and has the right to consideration from customers in an amount that corresponds directly with the performance obligation satisfied to date. The performance obligation is satisfied and revenue is recognized upon the delivery of services to customers. The Company records revenues for services and goods delivered but not 13

billed at the end of an accounting period in Accrued unbilled revenues on the Consolidated Balance Sheets, derived from estimated unbilled consumption and tariff rates or in a regulatory asset, as applicable. The Company's revenues are also adjusted for the effects of regulation including tracked operating expenses, infrastructure replacement mechanisms, decoupling mechanisms, and lost margin recovery. Decoupling and lost margin recovery mechanisms are considered ARPs, which are excluded from the scope of ASC 606. Customers are billed monthly and payment terms, set by the regulator, require payment within a month of billing. These revenues are not subject to significant returns, refunds, or warranty obligations. The following tables disaggregate revenues by reportable segment and major source: Year Ended December 31, 2024 Electric (1) Natural Gas Total (in millions) Revenue from contracts with customers $ 628 $ 121 $ 749 Other (2) 22 2 24 Eliminations — (2) (2) Total Revenues $ 650 $ 121 $ 771 Year Ended December 31, 2023 Electric Natural Gas Total (in millions) Revenue from contracts with customers $ 591 $ 124 $ 715 Other (2) 21 4 25 Total revenues $ 612 $ 128 $ 740 (1) Includes Securitization Subsidiary revenues from contracts with customers. (2) Primarily consists of income from ARPs. Contract Balances The Company does not have any material contract balances (right to consideration for services already provided or obligations to provide services in the future for consideration already received). Substantially all the Company's accounts receivable results from contracts with customers. The opening and closing balances of Accounts receivable and Accrued unbilled revenue are as follows: Accounts Receivable Other Accrued Unbilled Revenues (in millions) Opening balance as of December 31, 2023 $ 47 $ 45 Closing balance as of December 31, 2024 54 46 Increase $ 7 $ 1 Allowance for Credit Losses and Bad Debt Expense The Company segregates financial assets that fall under the scope of ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, primarily trade receivables due in one year or less, into portfolio segments based on shared risk characteristics, such as geographical location and regulatory environment, for evaluation of expected credit losses. Historical and current information, such as average write-offs, are applied to each portfolio segment to estimate the allowance for losses on uncollectible receivables. Additionally, the allowance for losses on uncollectible receivables is adjusted for reasonable and supportable forecasts of future economic conditions, which can include changing weather, commodity prices, regulations, and macroeconomic factors, among others. 14

The table below summarizes the bad debt expense, net of regulatory deferrals: Year Ended December 31, 2024 2023 (in millions) Bad debt expense $ 4 $ 2 (4) Property, Plant and Equipment (a) Property, Plant and Equipment Property, plant and equipment includes the following: December 31, 2024 December 31, 2023 Weighted Average Useful Lives Property, Plant and Equipment, Gross Accumulated Depreciation and Amortization Property, Plant and Equipment, Net Property, Plant and Equipment, Gross Accumulated Depreciation and Amortization Property, Plant and Equipment, Net (in years) (in millions) Electric transmission and distribution 34 $ 2,742 $ 1,163 $ 1,579 $ 2,351 $ 1,121 $ 1,230 Electric generation (1) 25 1,107 154 953 1,381 315 1,066 Natural gas distribution 42 924 207 717 893 200 693 Total $ 4,773 $ 1,524 $ 3,249 $ 4,625 $ 1,636 $ 2,989 (1) The Company and AGC owned a 300 MW unit at the Warrick Power Plant as tenants in common as of December 31, 2023. The Company’s share of the cost of this unit as of December 31, 2023, was $198 million with accumulated depreciation totaling $171 million. Under the operating agreement, AGC and the Company shared equally in the cost of operation and output of the unit. The Company’s share of operating costs was included in Operation and maintenance expense in the Company's Statements of Consolidated Income. The Company exited joint operations of the Warrick Power Plant on January 1, 2024. (b) Depreciation and Amortization The following table presents depreciation and amortization expense: Year Ended December 31, 2024 2023 (in millions) Depreciation $ 120 $ 137 Amortization of regulatory assets (1) 16 9 Total $ 136 $ 146 (1) For the years ended December 31, 2024 and 2023, amount includes amortization expense of $16 million and $8 million, respectively, related to the Securitization Subsidiary, which are reflected on the Company's Statements of Consolidated Income. (c) ARO A portion of removal costs related to interim retirements of gas utility pipeline and electric utility poles, and reclamation activities meet the definition of an ARO. The Company accounts for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the timing of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Company recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. The estimates of future liabilities are developed using a discounted cash flow model based upon estimates and assumptions of future costs, interest rates, credit-adjusted risk-free rates and the estimated timing of settlement. 15

The Company recorded AROs relating to the closure of the ash ponds at A.B. Brown and F.B. Culley as well as certain sites in Indiana pursuant to the CCR Legacy Rule; see Note 8(c) for further discussion. The Company also recorded AROs relating to treated wood poles for electric distribution, underground fuel storage tanks, and gas pipelines abandoned in place. A reconciliation of the changes in the ARO liability recorded in Other non-current liabilities in the Company’s Consolidated Balance Sheets is as follows: Year Ended December 31, 2024 2023 (in millions) Beginning balance $ 152 $ 139 Additions 11 — Accretion expense (1) 4 9 Revisions in estimates — 4 Ending balance $ 167 $ 152 (1) Reflected in Regulatory assets on the Company’s Consolidated Balance Sheets. (5) Regulatory Assets and Liabilities The following is a list of regulatory assets and liabilities reflected on the Company’s Balance Sheets as of December 31, 2024 and 2023: December 31, 2024 2023 (in millions) Regulatory Assets: Future amounts recoverable from ratepayers related to: Asset retirement obligations and other $ 45 $ 39 Net deferred income taxes 27 13 Total future amounts recoverable from ratepayers 72 52 Amounts deferred for future recovery related to: Cost recovery riders 71 48 Total amounts deferred for future recovery 71 48 Amounts currently recovered through customer rates related to: Authorized trackers and cost deferrals (1) 398 424 Gas recovery costs (2) 1 — Unamortized loss on reacquired debt and hedging 20 23 Total amounts recovered in customer rates 419 447 Total Regulatory Assets $ 562 $ 547 Total Current Regulatory Assets (2) $ 1 $ — Total Non-Current Regulatory Assets $ 561 $ 547 Regulatory Liabilities: Regulatory liabilities related to TCJA $ 170 $ 175 Estimated removal costs 56 81 Other regulatory liabilities 24 44 Total Regulatory Liabilities $ 250 $ 300 (1) Includes the securitized regulatory assets discussed below in Securitization of Generation Retirements. (2) Included in Prepaid expenses and other current assets on the Company’s Consolidated Balance Sheets. Of the $419 million currently being recovered in rates charged to customers, $7 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $33 million, is 19 years. Regulatory assets not earning a return with perpetual or undeterminable lives have been excluded from the weighted average recovery period calculation. The remainder of the regulatory assets are being recovered timely through periodic recovery mechanisms. The Company has rate orders for all deferred costs not yet in rates and therefore believes future recovery is probable. 16

Regulatory assets for asset retirement obligations are primarily a result of costs incurred for expected retirement activity for the Company's ash ponds beyond what has been recovered in rates. See Notes 4 and 10 for further information. The Company believes the recovery of these assets are probable as the costs are currently being recovered in rates. The deferred tax related regulatory liability is primarily the revaluation of deferred taxes at the reduced federal corporate tax rate that was enacted on December 22, 2017. These regulatory liabilities are being refunded to customers over time following regulatory commission approval. For further information about the Company's regulatory matters, see Note 9. Securitization of Generation Retirements On January 4, 2023, the IURC issued an order in accordance with Indiana Senate Enrolled Act 386 authorizing the issuance of up to $350 million in securitization bonds to securitize qualified costs associated with the retirements of the Company’s A.B. Brown coal-fired generation facilities. Accordingly, the Company determined that the retirement of property, plant and equipment became probable upon the issuance of the order. No loss on abandonment was recognized in connection with issuance of the order as there was no disallowance of all or part of the cost of the abandoned property, plant and equipment. In the first quarter of 2023, upon receipt of the order, the Company reclassified property, plant and equipment to be recovered through securitization to a regulatory asset and such amounts continued to earn a full return until recovered through securitization. The Securitization Subsidiary issued $341 million aggregate principal amount of the Securitization Bonds on June 29, 2023. The Securitization Subsidiary used a portion of the net proceeds from the issuance to purchase the securitization property from the Company. No gain or loss was recognized. The Securitization Bonds are secured by the securitization property, which includes the right to recover, through non- bypassable securitization charges payable by the Company’s retail electric customers, the qualified costs of the Company authorized by the IURC order. The Securitization Subsidiary, and not the Company, is the owner of the securitization property, and the assets of the Securitization Subsidiary are not available to pay the creditors of the Company or its affiliates, other than the Securitization Subsidiary. The Company has no payment obligations with respect to the Securitization Bonds except to remit collections of securitization charges as set forth in a servicing agreement between the Company and the Securitization Subsidiary. The non-bypassable securitization charges are subject to a true-up mechanism. (6) Transactions with Other Vectren Companies and Affiliates Support Services Affiliates of CenterPoint Energy provide corporate services to the Company and allocate certain costs to the Company. The costs of services have been charged directly to the Company using methods that management believes are reasonable. These methods include usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. Affiliates of CenterPoint Energy provide certain services to the Company, including geographic services and other miscellaneous services. These services are billed at actual cost, either directly or as an allocation. These charges are not necessarily indicative of what would have been incurred had CenterPoint Energy's subsidiaries not been affiliates. Amounts owed for support services at December 31, 2024 and 2023 are included in Accounts and notes payable - affiliated companies on the Company’s Consolidated Balance Sheets. The table below presents amounts charged for these services, which are included primarily in Operation and maintenance expenses the Company’s Statements of Consolidated Income, for the periods presented: Year Ended December 31, 2024 2023 (in millions) Corporate service charges $ 39 $ 41 Property, Plant and Equipment The Company purchased certain property, plant and equipment assets from VUH at their net carrying value of $4 million and $13 million in 2024 and 2023, respectively. 17

Defined Benefit Plans and Postretirement Benefits As of December 31, 2024, CenterPoint Energy and Vectren maintain four qualified defined benefit pension plans, three of which are closed to new participants (the Pension Plan for Hourly Employees of Southern Indiana Gas and Electric Company, which is sponsored by the Company, The Indiana Gas Company, Inc. Bargaining Unit Retirement Plan which is sponsored by Indiana Gas Company, Inc., a wholly-owned subsidiary of CenterPoint Energy, Inc., and the CenterPoint Energy Retirement Plan, which is sponsored by CenterPoint Energy, Inc.) and one of which is frozen (the Vectren Corporation Combined Non-Bargaining Retirement Plan, which is sponsored by Vectren). The plans are primarily non-contributory. In addition to the qualified defined benefit plans, CenterPoint Energy, through Vectren, also maintains a frozen nonqualified supplemental executive retirement plan covering certain former executives of Vectren, and a postretirement benefit plan, which covers certain eligible Company retirees. The postretirement benefit plan provides health care and life insurance benefits, which are a combination of self-insured and fully insured programs, on both a contributory and non-contributory basis. Effective in 2021, certain participants of the Vectren Corporation Combined Non-Bargaining Retirement Plan and all liabilities and assets associated with the accrued benefits of such participants were transferred to the CenterPoint Energy Retirement Plan. CenterPoint Energy and Vectren account for the identified qualified defined benefit pension plans, the postretirement benefit plan, and the nonqualified supplemental executive retirement plan consistent with FASB guidance related to "multiemployer" benefit accounting. CenterPoint Energy and Vectren allocate periodic cost calculated pursuant to GAAP associated with the qualified defined benefit pension plans, the supplemental executive retirement plan, and the postretirement benefit plan to their subsidiaries, including the Company, using a labor cost allocation, which is also how the Company recovers periodic costs through base rates. As a result, periodic cost is allocated to both operating expense and capital projects. For the years ended December 31, 2024 and 2023, periodic costs totaling less than $1 million and $1 million, respectively, were charged to the Company from CenterPoint Energy and Vectren. Neither plan assets nor plan obligations as calculated pursuant to GAAP are allocated to the individual subsidiaries of CenterPoint Energy and Vectren, except for current portions of postretirement benefit plan obligations which are allocated to their individual subsidiaries. CenterPoint Energy and Vectren satisfy the future funding requirements for their funded plans and the payment of benefits for unfunded plans from general corporate assets and, as necessary, rely on the Company to support the funding of these obligations. The Company's parent contributed less than $1 million to the CenterPoint Energy defined benefit pension plan in 2024 and 2023 for Vectren participants. The Company contributed $1 million in both 2024 and 2023 to Vectren's supplemental executive retirement plan and postretirement benefit plan, respectively. No additional contributions were made to the remaining plans, in which the Company participates, for 2024 or 2023 respectively. The combined funded status of Vectren’s qualified defined benefit pension plans (which consist of the identified qualified defined benefit pension plans except the CenterPoint Energy Retirement Plan) was approximately 101 percent and 97 percent as of December 31, 2024 and 2023, respectively. The funded status of the CenterPoint Energy Retirement Plan was approximately 76 percent and 78 percent as of December 31, 2024 and 2023, respectively. The Company's labor allocation methodology is also used to compute the Company's funding of the qualified defined benefit pension plans, the supplemental executive retirement plan, and the postretirement benefit plan to CenterPoint Energy and Vectren, which is consistent with the regulatory ratemaking processes of the Company. Any difference between the Company’s funding requirement to CenterPoint Energy or Vectren and allocated periodic cost is recognized by the Company as prepaid asset or accrued cost. The balances of the prepaid pension asset and accrued cost was as follows: Year Ended December 31, 2024 2023 (in millions) Prepaid pension asset: Qualified defined benefit pension plans (1) $ 17 $ 16 Total prepaid pension asset $ 17 $ 16 Accrued cost: Postretirement benefit plan (2) $ 15 $ 16 Nonqualified supplemental executive retirement plan (2) 1 1 Total accrued cost $ 16 $ 17 18

(1) Net of prepaid pension asset and accrued cost for all qualified defined benefit pension plans which are included in Other non-current assets and Other non-current liabilities on the Company's Consolidated Balance Sheets respectively. (2) Included in Other non-current liabilities on the Company's Consolidated Balance Sheets. Cash Management Arrangements The Company participates in the centralized cash management program with affiliates of Vectren. As of December 31, 2024, the Company had an investment in the VUH money pool of $11 million, included in Accounts and notes receivable - affiliated companies on the Consolidated Balance Sheets. As of December 31, 2023, the Company had borrowings from the VUH money pool of $50 million, included in Accounts and notes payable - affiliated companies on the Consolidated Balance Sheets. See Note 7 for further information regarding intercompany borrowing arrangements. Income Taxes The Company does not file federal or state income tax returns separate from those filed by Vectren or CenterPoint Energy. Vectren is included in CenterPoint Energy's U.S. federal consolidated income tax return. Vectren and/or certain of its subsidiaries are also included in various unitary or consolidated state income tax returns with CenterPoint Energy. In other state jurisdictions, Vectren and certain subsidiaries continue to file separate state tax returns. Pursuant to a tax sharing agreement and for financial reporting purposes, the Company records income taxes on a separate company basis. The Company's allocated share of tax effects resulting from it being a part of Vectren's consolidated tax group are recorded at the Company's parent level. Current taxes payable/receivable are settled with Vectren in cash quarterly and after filing the consolidated federal and state income tax returns. The components of income tax expense and amortization of investment tax credits were as follows: Year Ended December 31, 2024 2023 (in millions) Current income tax expense: Federal $ 9 $ 13 State 2 — Total current income tax expense 11 13 Deferred income tax expense: Federal 5 6 State 7 3 Total deferred income tax expense 12 9 Investment tax credit amortization (1) (1) Total income tax expense $ 22 $ 21 A reconciliation of the federal statutory rate to the effective income tax rate was as follows: Year Ended December 31, 2024 2023 Statutory rate 21 % 21 % State and local taxes, net of federal benefit 4 2 Regulatory liability amortization settled through rates (7) (5) Audit Adjustments (3) 5 AFUDC Equity (2) (3) All other - net — 1 Effective tax rate 13 % 21 % 19

Significant components of the net deferred tax liability were as follows: December 31, 2024 2023 (in millions) Non-current deferred tax assets: Net operating loss and other carryforwards $ 97 $ 45 Regulatory liabilities settled through future rates 40 44 Employee benefit obligations 4 4 Asset retirement obligations 3 — Other – net 21 7 Total deferred tax assets 165 100 Non-current deferred tax liabilities: Depreciation and cost recovery timing differences 485 380 Regulatory assets recoverable through future rates 8 13 Deferred fuel costs 15 16 Total deferred tax liabilities 508 409 Net deferred tax liability $ 343 $ 309 As of December 31, 2024, the Company has $27 million investment tax credit carryforward that will expire in 2041. As of December 31, 2024 and 2023, deferred investment tax credits totaling $26 million and $27 million, respectively, are included in Other non-current liabilities on the Consolidated Balance Sheets. Uncertain Tax Positions The Company has no unrecognized tax benefits for the years ended December 31, 2024, 2023, and 2022. Tax Audits and Settlements The Company's parent and certain of its subsidiaries file income tax returns in the U.S. federal jurisdiction and various states. Tax years through 2022 have been audited and settled with the IRS for CenterPoint Energy. For the tax years 2023 and 2024, CenterPoint Energy and its subsidiaries are participants in the IRS’s Compliance Assurance Process. 20

(7) Borrowing Arrangements and Other Financing Transactions Long-Term Debt Long-term senior unsecured obligations and first mortgage bonds outstanding are as follows: Securitization Bonds 2036, 2025 Series-A Securitization Bond Tranche A-1, 5.026% $ 198 $ 215 2041, 2036 Series-A Securitization Bond Tranche A-1, 5.172% 126 126 Total Securitization Bonds 324 341 Current maturities (13) (17) Unamortized debt issuance cost (3) (4) Total long-term debt - VIE Securitization Bonds, net $ 308 $ 320 First Mortgage Bonds Payable to Third Parties: 2024, 2013 Series D, 3.50%, tax-exempt $ — $ 23 2025, 2014 Series B, 3.45%, tax-exempt 41 41 2037, 2013 Series E, 3.55%, tax-exempt 22 22 2038, 2013 Series A, 4.00%, tax-exempt 22 22 2043, 2013 Series B, 4.00%, tax-exempt 40 40 2044, 2014 Series A, 4.00%, tax-exempt 11 11 2055, 2015 Series Mt. Vernon, 4.25%, tax-exempt 23 23 2055, 2015 Series Warrick County, 4.25%, tax-exempt 15 15 2028, 2023 Series A, 4.98% 100 100 2033, 2023 Series A, 5.04% 80 80 2029, 2023 Series B, 5.75% 180 180 2030, 2023 Series B, 5.91% 105 105 2034, 2023 Series B, 6.00% 185 185 2034, 2024 Series 2024A, 5.18% 100 — 2036, 2024 Series 2024A, 5.28% 60 — Total First Mortgage Bond payable to third parties 984 847 Current maturities (41) (23) Unamortized debt issuance cost (4) (3) Total long-term debt - third parties, net $ 939 $ 821 Fixed Rate Senior Unsecured Notes Payable to Affiliated Companies 2025, 1.21% $ 106 $ 106 2030, 1.72%. 75 75 2032, 3.26% 75 75 Total long-term debt payable - affiliated companies 256 256 Current maturities (106) — Total long-term debt - affiliated companies, net $ 150 $ 256 December 31, 2024 2023 (in millions) 21

Debt Transactions Debt Issuances. During 2024, the following debt instruments were issued or incurred: Issuance Date Debt Instrument Aggregate Principal Amount Interest Rate Maturity Date (in millions, except for interest rates) August 2024 First Mortgage Bonds (1) $ 100 5.18% 2034 August 2024 First Mortgage Bonds (1) 60 5.28% 2036 $ 160 (1) Total proceeds from the Company’s August 2024 issuances of first mortgage bonds, net of transaction expenses and fees, of approximately $159 million were used for general corporate purposes, including repaying short-term debt and long- term debt at maturity or otherwise. See Note 14 for additional information. Debt Repayments and Redemptions. During 2024, the following debt instrument was repaid at maturity or redeemed prior to maturity: Repayment/Redemption Date Debt Instrument Aggregate Principal Interest Rate Maturity Date (in millions) March 2024 First Mortgage Bonds (1) $ 22 3.50% 2024 $ 22 (1) On February 6, 2024, the Company provided notice of redemption and on March 1, 2024, the Company paid down the outstanding principal of $22 million aggregate principal amount of the Company’s outstanding first mortgage bonds due 2024 at a redemption price equal to 100% of the principal amount of the first mortgage bonds to be redeemed plus accrued and unpaid interest thereon, if any, to, but excluding, the redemption date. Securitization Bonds. As of December 31, 2024, the Company had a special purpose subsidiary, the Securitization Subsidiary, which is consolidated. The 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 the A.B. Brown coal generation facilities through the issuance of securitization bonds and activities incidental thereto. The Securitization Bonds are payable only through the imposition of securitization charges payable by the Company’s retail electric customers, which are non-bypassable charges to provide recovery of the qualified costs of the Company authorized by the IURC order. The Company has no payment obligations in respect of the Securitization Bonds other than to remit the applicable securitization charges it collects as set forth in servicing agreements among the Company, the Securitization Subsidiary and other parties. The special purpose entity is the sole owner of the right to impose, collect and receive the applicable 22

securitization charges securing the bonds issued. Creditors of the Company have no recourse to any assets or revenues of the Securitization Subsidiary and the bondholders have no recourse to the general credit of the Company. Credit Facilities. The Company had the following revolving credit facility as of December 31, 2024: Execution Date Size of Facility Draw Rate of SOFR plus (1) Financial Covenant Limit on Debt for Borrowed Money to Capital Ratio Debt for Borrowed Money to Capital Ratio as of December 31, 2024 (2) Termination Date (3) (in millions) December 6, 2022 $ 250 1.125% 65% 44.8% December 6, 2027 (1) Based on credit ratings as of December 31, 2024. (2) As defined in the revolving credit facility agreement, excluding Securitization Bonds. (3) See Note 14 for discussion of subsequent events associated with the revolving credit facility. There were no borrowings outstanding under the revolving credit facility as of December 31, 2024 and 2023. Future Long-Term Debt Sinking Fund Requirements and Maturities. As of December 31, 2024, the Company had approximately $984 million aggregate principal amount of first mortgage bonds outstanding. Generally, all of the Company’s real and tangible property is subject to the lien of its mortgage indenture, which was amended and restated effective as of January 1, 2023. As of December 31, 2024, the Company was permitted to issue additional bonds under its mortgage indenture up to 70% of then unfunded property additions and approximately $899 million of additional first mortgage bonds could be issued on this basis. Maturities. As of December 31, 2024, maturities of long-term debt, excluding discounts, premiums and issuance costs, were as follows: Affiliate Debt Third Party Debt Securitization Bonds Total Debt (in millions) 2025 $ 106 $ 41 $ 13 $ 160 2026 — — 14 14 2027 — — 14 14 2028 — 100 15 115 2029 — 180 16 196 2030 and thereafter 150 663 252 1,065 Covenants. Both long-term and short-term borrowing arrangements contain customary default provisions; restrictions on liens, sale-leaseback transactions, mergers or consolidations, and sales of assets; and restrictions on leverage, among other restrictions. Multiple debt agreements contain a covenant that the ratio of consolidated total debt to consolidated total capitalization will not exceed 65 percent. As of December 31, 2024, the Company was in compliance with all financial debt covenants. (8) Commitments and Contingencies (a) Purchase Obligations Commitments include minimum purchase obligations related to the Company's Electric reportable segment and Natural Gas reportable segment. Contracts with minimum payment provisions have various quantity requirements and durations and are not classified as non-trading derivative assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2024 and 2023 because these contracts meet an exception as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas and coal supply commitments also include transportation contracts that do not meet the definition of a derivative. 23

As of December 31, 2024, the Company had the following undiscounted minimum purchase obligations: Electric Supply (1) Natural Gas Supply (in millions) 2025 $ 83 $ 4 2026 130 4 2027 135 4 2028 97 4 2029 94 3 Thereafter 1,303 19 Total $ 1,842 $ 38 (1) Related to PPAs with commitments ranging from 15 years to 25 years. Excluded from the table above are estimates for cash outlays from other PPAs that do not have minimum thresholds but do require payment when energy is generated by the provider. Costs arising from certain of these commitments are pass-through costs, generally collected dollar-for-dollar from retail customers through regulator-approved cost recovery mechanisms. For further details about the Company's BTAs and PPAs, see Note 9. (b) AMAs The Company continues to utilize AMAs associated with its utility distribution service in Indiana. Pursuant to the provisions of the agreements, the Company 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. Generally, AMAs are contracts between the Company and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, the Company agrees to release transportation and storage capacity to other parties to manage natural gas storage, supply and delivery arrangements for the Company and to use the released capacity for other purposes when it is not needed for the Company. The Company may receive compensation from the asset manager through payments made over the life of the AMAs. The Company has an obligation to purchase its winter storage requirements that have been released to the asset manager under these AMAs. (c) Environmental Matters MGP Sites. The Company and its predecessors operated MGPs in the past. The costs the Company expects to incur to fulfill its obligations are estimated by management using assumptions based on actual costs incurred, the timing of expected future payments and inflation factors, among others. While the Company has recorded obligations for all costs which are probable and estimable, including amounts it is presently obligated to incur in connection with activities at these sites, it is possible that future events may require remedial activities which are not presently foreseen, and those costs may not be subject to PRP or insurance recovery. Indiana MGPs. The Company has identified its involvement in five manufactured gas plant sites in its service territory, all of which are currently enrolled in the IDEM’s VRP. The Company is currently conducting some level of remedial activities, including groundwater monitoring at certain sites. Total costs that may be incurred in connection with addressing these sites cannot be determined at this time. The estimated accrued costs are limited to the Company's share of the remediation efforts and are therefore net of exposures of other PRPs. The estimated range of possible remediation costs for the sites for which the Company believes it may have responsibility was based on remediation continuing for the minimum time frame given in the table below: December 31, 2024 (in millions, except years) Amount accrued for remediation $ 2 Minimum estimated remediation costs 1 Maximum estimated remediation costs 8 Minimum years of remediation 5 Maximum years of remediation 20 24

The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will depend on the number of sites to be remediated, the participation of other PRPs, if any, and the remediation methods used. The Company does not expect the ultimate outcome of these matters to have a material adverse effect on its financial condition, results of operations or cash flows. CCR Rule. In April 2015, the EPA finalized its CCR Rule, which regulates ash as non-hazardous material under the RCRA. The final rule allows beneficial reuse of ash, and a portion of the ash generated by the Company's generating plants will continue to be reused. The Company has three ash ponds, two at the F.B. Culley facility (Culley East and Culley West) and one at the A.B. Brown facility. Under the CCR Rule, the Company is required to perform integrity assessments, including groundwater monitoring, at its F.B. Culley and A.B. Brown generating stations. Pursuant to the CCR Rule, both the Culley East and A.B. Brown facilities were taken out of service in a timely manner per the commitments made to the EPA in the extension requests filed for both ponds. On April 24, 2019, the Company received an order from the IURC approving recovery in rates of costs associated with the closure of the Culley West pond, which has already completed closure activities. On August 14, 2019, the Company filed its petition with the IURC for recovery of costs associated with the closure of the A.B. Brown ash pond, which would include costs associated with the excavation and recycling of ponded ash. This petition was subsequently approved by the IURC on May 13, 2020. On October 28, 2020, the IURC approved the Company's ECA proceeding, which included the initiation of recovery of the federally mandated project costs. On November 1, 2022, the Company filed for a CPCN to recover federally mandated costs associated with closure of the Culley East Pond, its third and final ash pond. The Company sought accounting and ratemaking relief for the project, and on June 8, 2023, the Company filed a revised CPCN for recovery of the federally mandated ash pond costs. On February 7, 2024, the IURC approved the federally mandated costs, both incurred and projected, of $52 million in capital costs, plus an estimated $133,000 in annual operation and maintenance expenses, for recovery through the ECA. As of December 31, 2024, the Company has recorded an approximate $121 million ARO, which represents the discounted value of future cash flow estimates to close the ponds at A.B. Brown and F.B. Culley. This estimate is subject to change due to the contractual arrangements; continued assessments of the ash, closure methods, and the timing of closure; implications of the Company's generation transition plan; changing environmental regulations; and proceeds received from the settlements in a previously settled insurance proceeding. In addition to these AROs, the Company also anticipates equipment purchases of between $60 million and $80 million to complete the A.B. Brown closure project. On April 25, 2024, the EPA released its final CCR Legacy Rule. The CCR Legacy Rule requires companies to investigate previously closed impoundments that were used historically for ash disposal or locations which have had ash placed on them in amounts set forth in the CCR Legacy Rule. The Company has completed its preliminary review of potential sites that will require further investigation under the CCR Legacy Rule and identified certain sites in Indiana for further evaluation. During 2024, the Company recorded an approximate $11 million ARO with a corresponding increase of $11 million to Property, plant and equipment for amounts recoverable for electric generation stations that are currently in service. These estimates reflect the discounted value of future estimated capping costs for an area of historic ash placement at F.B. Culley. The Company will continue to refine the assumptions, engineering analyses and resulting cost estimates associated with this ARO and such refinement could materially impact the amount of the estimated ARO. Clean Water Act Permitting of Groundwater and Power Plant Discharges. In April 2020, the U.S. Supreme Court issued an opinion providing that indirect discharges via groundwater or other non-point sources are subject to permitting and liability under the Clean Water Act when they are the functional equivalent of a direct discharge. On November 27, 2023, the EPA published draft guidance regarding the application of the "functional equivalent" analysis as related to permitting of certain discharges through groundwater to surface waters. The Company does not currently anticipate impacts from this guidance, but groundwater monitoring continues under the CCR Rule. In 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards which set more stringent wastewater discharge limits and effectively prohibited further wet disposal of coal ash in ash ponds. In February 2019, the IURC approved the Company’s ELG Compliance Plan for its F.B. Culley Generating Station, which was completed in compliance with the requirements of the ELG. On April 25, 2024, the EPA released its final Supplemental ELG and Standards for the Steam Electric Generating Point Source Category. The Company currently anticipates that it will be in compliance with the Supplemental ELG Guidelines at the Culley facility due to previous wastewater treatment upgrades. 25

Other Environmental. From time to time, the Company identifies the presence of environmental contaminants during operations or on property where its predecessors have conducted operations. Other such sites involving contaminants may be identified in the future. The Company has and expects to continue to remediate any identified sites consistent with state and federal legal obligations. From time to time, the Company has received notices, and may receive notices in the future, from regulatory authorities or others regarding status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been, or may be, named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect these matters, either individually or in the aggregate, to have a material adverse effect on its financial condition, results of operations or cash flows. (d) Other Proceedings The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. From time to time, the Company is also a defendant in legal proceedings with respect to claims brought by various plaintiffs against broad groups of participants in the energy industry. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable and reasonably estimable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows. (9) Regulatory Matters Securitization of Generation Retirements For further information about the issuance of Securitization Bonds, see Note 5. BTAs On February 23, 2021, the Company 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 the Company 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, the Company, along with Arevon, the developer, announced plans in January 2022 to downsize the Posey Solar project to 191 MW. The Company collaboratively agreed to the scope change, and on February 1, 2023, the Company entered into an amended and restated BTA that was contingent on further IURC review and approval. On February 7, 2023, the Company filed a CPCN with the IURC to approve the amended BTA. With the passage of the IRA, the Company can now pursue PTCs for solar projects. The Company requested that project costs, net of PTCs, be recovered in rate base rather than a levelized rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. On September 6, 2023, the IURC issued an order approving the CPCN. The Posey Solar project is expected to be placed in service in the second quarter of 2025 and recovered through base rates. See Note 14 for additional detail. On July 5, 2022, the Company 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 the Company 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 the Company 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 applicable Indiana regulations, approved the proposed levelized rate and associated ratemaking and accounting treatment. Due to inflationary pressures, the developer disclosed that costs exceeded the agreed upon levels in the BTA. After negotiations, the Company and the developer were not able to agree upon updated pricing. As a result, on March 15, 2024, the Company provided notice to the IURC that it was exercising its right to terminate the BTA, which terminated all further obligations of the Company with respect to the project. On January 10, 2023, the Company 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. The Company received approval from the IURC to recover the costs of the wind facility via the CECA mechanism, which the developer believes can be placed in service by the end of 2026. On June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing the Company to purchase the wind generating facility. However, 26

as of the date of these financial statements, the Company 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 The Company 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 the Company were compelled to renegotiate terms of the agreement to increase the PPA price. On January 17, 2023, the Company filed a request with the IURC to amend the previously approved PPA with certain modifications. Revised purchase power costs are requested to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026. On August 25, 2021, the Company 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 the Company to enter into both PPAs. In March 2022, when the results of the MISO interconnection study were completed, Origis advised the Company 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, the Company and Origis entered into an amended PPA, which reiterated the terms contained in the previously approved Knox County solar PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in-service date will be delayed to 2026. On January 17, 2023, the Company filed a request with the IURC to amend the previously approved Vermillion County solar PPA with Oriden with certain modifications. Revised purchase power costs were approved to be recovered through the fuel adjustment clause proceedings over the term of the amended PPA with Oriden. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2026. On May 1, 2024, the Company filed with the IURC seeking approval to purchase 147 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Knox County, Illinois. On November 6, 2024, the IURC approved the Knox County wind PPA, which provided for the recovery of the purchase power costs through the fuel adjustment clause proceedings over the term of the PPA. The facility is targeted to be in operation in early 2026. Natural Gas Combustion Turbines On June 17, 2021, the Company filed a CPCN with the IURC seeking approval to construct two natural gas combustion turbines to replace portions of its existing coal-fired generation fleet. On June 28, 2022, the IURC approved the CPCN. The estimated $334 million turbine facility is being constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana and will provide a combined output of 460 MW. The Company received approval for depreciation expense and post in- service carrying costs to be deferred in a regulatory asset until the date the Company'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 Company granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. On January 7, 2025, the United States Court of Appeals for the D.C. Circuit affirmed the FERC’s order granting the certificate. The facility is targeted to be operational by mid-year 2025. On February 6, 2025, the EPC contractor for the Company’s proposed natural gas combustion turbines provided a notice to the Company that the EPC contractor was identifying the impacts of the proposed tariffs on the project and intended to seek an equitable adjustment to the contract price for the project. Recovery of the proposed natural gas combustion turbines and regulatory asset was included in the forecasted test year in the Company's rate case, which was filed with the IURC on December 5, 2023. See "Rate Change Applications" below for further detail on the Company's rate case. Culley Unit 3 Operations In June 2022, F.B. Culley Unit 3, the Company's 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 the Company did not act prudently which led to the unplanned outage and recommended disallowances between $21 million to $27 million. On July 3, 2024, the IURC issued an order finding the Company acted reasonably and 27

prudently with respect to the events that gave rise to the Culley Unit 3 outage and, in addition, did not approve the intervenors proposed disallowance. The order is now final and non-appealable. Solar Panel Issues The Company’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 the Company's solar projects have been primarily due to (i) unavailability of solar panels and other uncertainties related to DOC antidumping and countervailing duties investigation(s), (ii) the December 2021 Uyghur Forced Labor Prevention Act on solar modules and other products manufactured in China's Xinjiang Uyghur Autonomous Region and (iii) persistent general global supply chain and labor availability issues. On May 15, 2024, based on a petition filed by the American Alliance for Solar Manufacturing Trade Committee, the DOC announced the initiation of antidumping and countervailing duty investigations of silicon photovoltaic cells from Cambodia, Malaysia, Thailand, and Vietnam. On October 1, 2024, the DOC’s preliminary countervailing duty determination affirmed the petition and established preliminary duty rates. A final determination is expected in the second quarter of 2025. On November 29, 2024, the DOC announced its preliminary affirmative determination in the antidumping investigation and established preliminary dumping rates. A final determination is expected in the second quarter of 2025. These impacts could result in cost increases for certain projects, and such impacts may require that we seek additional regulatory review and approvals. Additionally, significant changes to project costs and schedules as a result of these factors could impact the viability of the projects. TDSIC 2.0 On May 24, 2023, the Company filed its petition and case-in-chief with the IURC requesting, among other things, approval of its five-year plan for transmission, distribution, and storage improvements (TDSIC Plan) and an order approving the TDSIC Plan was issued on December 27, 2023. The approved five-year TDSIC Plan, covering the period January 1, 2024 through December 31, 2028, consists of approximately $454 million in proposed investments across seven different programs: (1) Distribution 12kV Circuit Rebuild, (2) Distribution Underground Rebuild, (3) Distribution Automation, (4) Wood Pole Replacement, (5) Transmission Line Rebuild, (6) Substation Rebuild, and (7) Substation Physical Security. Rate Change Applications The Company is routinely involved in rate change applications before state regulatory authorities. Those applications include general rate cases, where the entire cost of service of the utility is assessed and reset. In addition, the Company is periodically involved in proceedings in Indiana to adjust its capital tracking mechanisms (CSIA for gas and TDSIC, ECA and CECA for electric), its decoupling mechanism in Indiana (SRC for gas), and its energy efficiency cost tracker in Indiana (EEFC for gas and DSMA for electric). Rate Case. On December 5, 2023, the Company filed a petition with the IURC for authority to modify its rates and charges for electric utility service through a phase-in of rates. The requested increase was approximately 16% or $119 million based on a forward looking 2025 test year. The need for a rate increase was primarily driven by the continuing investment in the safety and reliability of the system and normal increases in operating expenses. The initial filing of the rate case reflected a proposed 10.4% ROE on a forecasted 55% equity ratio. The Company reached a settlement agreement with less than all parties and submitted the agreement to the IURC on May 20, 2024. The settlement reflected a proposed 9.8% ROE on a forecasted 55% equity ratio. The requested increase was lowered to $80 million, an 11% increase. The Company received a final order on February 3, 2025 approving the settlement with one modification that effectively capped the residential increase to 1.15% of the total increase, allocating the difference to other commercial and industrial customers. The final order approves the 9.8% ROE on a forecasted 55% equity ratio and increases revenues by $80 million. 28

The table below reflects significant applications pending or completed since the Company’s 2023 financial statements were furnished to the SEC on Current Report 8-K dated March 8, 2024 through March 18, 2025. Gas (IURC) CSIA 4 April 2024 August 2024 July 2024 Requested an increase of $35 million to rate base, which reflects approximately $3.6 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $0.03 million annually. The final IURC order was issued July 31, 2024, approving CSIA rates as proposed effective August 1, 2024. CSIA 2 October 2024 February 2025 January 2025 Requested an increase of $18 million to rate base, which reflects approximately $2.4 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under-recovery variance of $(1.0) million annually. The final IURC order was issued January 29, 2025 approving rates as filed with the correction filing effective February 1, 2025. Electric (IURC) Rate Case 80 December 2023 February 2025 February 2025 See discussion above under Indiana Electric Rate Case. TDSIC 5 February 2024 May 2024 May 2024 Requested an increase of $36 million to rate base, which reflects a $5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until next rate case. An order approving the request was issued on May 17, 2024 and was effective May 16, 2024. CECA — February 2024 May 2024 June 2024 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. The final order was issued May 29, 2024, approving rates effective June 1, 2024. ECA 6 May 2024 August 2024 August 2024 Requested an increase of $48 million to rate base, which reflects a $6 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until next rate case. The mechanism also includes a reduction in the under-recovery variance of $1 million. The OUCC filed testimony on July 1, 2024 recommending approval. A final order approving the request was issued on August 28, 2024. TDSIC 5 August 2024 November 2024 November 2024 Requested an increase of $30 million to rate base, which reflects a $5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The final order was issued on November 27, 2024 approving rates effective November 28, 2024. Mechanism Annual Increase (1) (in millions) Filing Date Effective Date Approval Date Additional Information (1) Represents proposed increases when effective date and/or approval date is not yet determined. Approved rates could differ materially from proposed rates. 29

(10) Environmental and Sustainability Matters IRA On August 16, 2022, the IRA was signed into law. The 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 Company will owe CAMT in excess of its regular tax liability beginning in 2024. As a result, the Company expects a temporary increase in federal cash tax liability due to this provision beginning in 2024. On September 12, 2024, the IRS issued proposed regulations addressing the application of the CAMT. The proposed regulations offer guidance for computing an entity’s adjusted financial statement income, in addition to addressing other provisions of the CAMT. At this time, the Company does not anticipate changes to the applicability of CAMT as a result of the proposed regulations. Greenhouse Gas Regulation and Compliance There is increasing attention being paid in the United States and worldwide to the issue of climate change. As a result, from time to time, regulatory agencies have considered the modification of existing laws or regulations or the adoption of new laws or regulations addressing the emissions of GHG on the state, federal, or international level. The Company'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 the Company's operations or would have the effect of reducing the consumption of natural gas. Additionally, the Methane Emissions Reduction Program established by the IRA and the new regulations published by the EPA on March 8, 2024 targeting reductions in methane emissions may increase costs related to production, transmission and storage of natural gas. The Company'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 its service territory. Likewise, incentives to conserve energy or to use energy sources other than natural gas could result in a decrease in demand for the Company's services. Further, requirements and/or incentives to reduce energy consumption by certain specified dates in the Company's service areas could have a significant impact on its operations. Further, the Company's third-party suppliers, vendors and partners may also be impacted by climate change laws and regulations, which could impact its business by, among other things, causing permitting and construction delays, project cancellations or increased project costs passed on to the Company. Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emissions characteristics would be expected to benefit its natural gas-related businesses. At this time, however, the Company cannot quantify the magnitude of the impacts from possible new regulatory actions related to GHG emissions, either positive or negative, on the Company's business. Compliance costs and other effects associated with climate change, reductions in GHG emissions and obtaining renewable energy sources remain uncertain; nevertheless, any new regulation or legislation relating to climate change will likely result in an increase in compliance costs. The Company will continue to monitor regulatory activity regarding GHG emission standards that may affect its business. Currently, the Company does not purchase carbon credits. In connection with its net zero emissions goals, the Company is expected to purchase carbon credits in the future; however, the Company 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 Company's 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 Company's systems and services, which may result in, among other things, the Company'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 the Company's electric generation and natural gas businesses. For example, because the Company currently relies on coal for a portion of its generation capacity, certain financial institutions choose not to participate in the Company's financing arrangements. Conversely, demand for the Company's services may increase as a result of customer changes in response to climate 30

change. For example, the expected expansion of energy export facilities, including hydrogen facilities, and electrification of industrial processes and transport and logistics, among others, in the Company's service territory could lead to an increase in demand for electricity, resulting in increased usage of the Company's systems and services. Any negative opinions with respect to the Company's environmental practices or its ability to meet the challenges posed by climate change formed by regulators, customers, legislators or other stakeholders could harm its reputation. To address these developments, CenterPoint Energy announced its net zero emissions goals for both 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. The Company'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. The Company continues to execute on its 2019/2020 IRP and has received initial approvals for 626 MWs of the 700-1,000 MWs of solar generation and 200 MWs of the 300 MWs of wind generation identified within its 2019/2020 IRP through a combination of BTAs and PPAs. The Company believes its planned investments in renewable energy generation and corresponding planned reduction in its Scope 1 and certain Scope 2 emissions as part of CenterPoint Energy's net zero emissions goals, as well as its planned reduction in Scope 3 emissions as part of CenterPoint Energy's goal to reduce certain Scope 3 GHG emissions by 20-30% by 2035 as compared to 2021 levels, support global efforts to reduce the impacts of climate change. The Company's 2022/2023 IRP, which was submitted to the IURC in May 2023, was conducted to identify an appropriate generation resource portfolio to satisfy the needs of its customers and comply with environmental regulations. The proposed preferred portfolio under the 2022/2023 IRP was the second evolution to the generation transition plan to move away from coal-fired generation to a more sustainable portfolio of resources. The Company's 2022/2023 IRP proposed preferred portfolio called for the conversion of the Company's last remaining coal unit, F.B. Culley Unit 3, to natural gas and to add a significant amount of additional renewable resources through 2033. The Company has since received approval for a PPA for 147 MWs of wind generation consistent with the preferred portfolio identified in the 2022/2023 IRP. Additionally, in February 2025, the Company launched its 2025 IRP process to assist the Company in setting its long-term strategy for electric generation and power needs for its customers. The conversion of F.B. Culley Unit 3 to natural gas has been paused and will be reevaluated in the 2025 IRP process. To the extent climate changes result in warmer temperatures in the Company’s service territory, financial results from its business could be adversely impacted. For example, the Company could be adversely affected through lower natural gas sales. Another possible result of climate change is more frequent and more severe weather events, such as hurricanes, tornadoes, floods, microbursts, severe winter weather conditions, including ice storms, wildfires, thunderstorms, high winds, hail, derecho events, or extreme temperatures. To the extent adverse weather conditions affect the Company’s suppliers, results from its natural gas business may suffer. When the Company cannot deliver electricity or natural gas to customers, or customers cannot receive services, the Company’s financial results can be impacted by lost revenues, and it generally must seek approval from regulators to recover restoration costs. To the extent the Company is unable to recover those costs, or if higher rates resulting from recovery of such costs result in reduced demand for services, the Company’s future financial results may be adversely impacted. Further, as the intensity and frequency of significant weather events continues, it may impact the Company’s ability to secure cost-efficient insurance. ELG For further information about the Company's ELG compliance plan for its F.B. Culley Generating Station and the EPA's final Supplemental ELG and Standards for the Steam Electric Generating Point Source Category, see Note 8(c). 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. The Company is currently completing the required ecological studies and anticipates timely compliance at its F.B. Culley facility in 2025. (11) Fair Value Measurements Certain methods and assumptions must be used to estimate the fair value of financial instruments. The fair value of the Company's long-term debt was estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for instruments with similar characteristics. Because of the maturity dates of cash and cash equivalents, those carrying amounts approximate fair value. Because of the inherent difficulty of estimating interest rate and other market risks, the methods used to estimate fair value may not always be indicative of actual realizable value, and different methodologies could 31

produce different fair value estimates at the reporting date. Both the carrying values and estimated fair values of the Company's natural gas derivatives was less than $1 million and $2 million as of December 31, 2024 and 2023, respectively, using primarily Level 2 assumptions. In addition, the carrying values and estimated fair values of the Company's other financial instruments were as follows: December 31, 2024 2023 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt, including current maturities: VIE Securitization Bonds $ 321 $ 322 $ 337 $ 337 Third parties 980 1,007 844 979 Affiliated companies 256 128 256 227 Total long-term debt, including current maturities $ 1,557 $ 1,457 $ 1,437 $ 1,543 (1) Included in Accrued liabilities on the Consolidated Balance Sheets. (12) Reportable Segments The Company’s determination of reportable segments considers the strategic operating units under which its CODM manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company's CODM views net income as the measure of profit or loss for the reportable segments. As of December 31, 2024, reportable segments and information about the Company's CODM were as follows: • The Electric segment provides electric generation, transmission and distribution services primarily to southwestern Indiana, and includes the Company’s power generating and wholesale power operations. • The Natural Gas segment provides natural gas distribution and transportation services to primarily southwestern Indiana. The Company’s CODM is the President and Chief Executive Officer of CenterPoint Energy. The CODM uses segment net income to allocate resources as part of the budgeting and forecasting process as well as during periodic budget-to-actual reviews. Financial data for reportable segments is as follows: Year Ended December 31, 2024 Electric Natural Gas Total Reportable Segments Eliminations Total (in millions) Revenues from external customers $ 650 $ 121 $ 771 $ — $ 771 Intersegment revenues 2 2 (2) — Fuel and purchased power 198 — 198 — 198 Utility natural gas — 31 31 (2) 29 Operation and maintenance 146 33 179 — 179 Depreciation and amortization 116 20 136 — 136 Taxes other than income taxes 10 2 12 — 12 Interest expense 57 10 67 — 67 Interest income (1) — (1) — (1) Other income, net (17) (1) (18) — (18) Income tax expense 18 4 22 — 22 Net income $ 123 $ 24 $ 147 $ — $ 147 32

Year Ended December 31, 2023 Electric Natural Gas Total Reportable Segments Eliminations Total (in millions) Revenues from external customers $ 612 $ 128 $ 740 $ — $ 740 Fuel and purchased power 176 — 176 — 176 Utility natural gas — 30 30 — 30 Operation and maintenance 207 44 251 — 251 Depreciation and amortization 125 21 146 — 146 Taxes other than income taxes 10 2 12 — 12 Interest expense 47 12 59 — 59 Interest income (5) — (5) — (5) Other income, net (27) (3) (30) — (30) Income tax expense 20 1 21 — 21 Net income $ 59 $ 21 $ 80 $ — $ 80 Year Ended December 31, 2024 2023 (in millions) Capital Expenditures Electric $ 361 $ 360 Natural Gas 39 132 Total capital expenditures $ 400 $ 492 December 31, 2024 2023 (in millions) Total Assets Electric $ 3,280 $ 3,037 Natural Gas 820 803 Total assets $ 4,100 $ 3,840 Year Ended December 31, 2024 2023 (in millions) Revenues by Products and Services Retail electric sales $ 622 $ 569 Electric delivery 24 23 Wholesale electric sales 4 20 Retail gas sales 121 128 Total $ 771 $ 740 33

(13) Supplemental Cash Flow Information The table below provides supplemental disclosure of cash flow information: Year Ended December 31, 2024 2023 (in millions) Cash Payments: Income tax payments $ 5 $ 23 Interest 82 43 Non-cash transactions: Accounts payable related to capital expenditures $ 15 $ 20 The table below provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets to the amount reported in the Statements of Consolidated Cash Flows: December 31, 2024 2023 (in million) Cash and cash equivalents (1) $ 9 $ 14 Restricted cash included in Prepaid expenses and other current assets 2 3 Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows $ 11 $ 17 (1) Included $7 million and $14 million related to the VIE as of December 31, 2024 and 2023, respectively. (14) Subsequent Events Management performs a review of subsequent events for any events occurring after the balance sheet date but prior to the date the financial statements are issued. The Company's management has performed a review of subsequent events through March 18, 2025, the date the financial statements were issued. Credit Facilities On January 29, 2025, the Company entered into an Extension Agreement to, among other things, extend the maturity date of the lenders’ commitments under its Credit Agreement by one year, from December 6, 2027 to December 6, 2028. First Mortgage Bonds On January 31, 2025, the Company issued $165 million aggregate principal amount of 5.69% First Mortgage Bonds, Series 2025A, Tranche A due 2055. Total net proceeds, net of transaction expenses and fees, were approximately $164 million, which were used for the acquisition of Posey Solar discussed below. Posey Solar Acquisition On March 7, 2025, the Company completed the acquisition of Posey Solar from Arevon for a purchase price of approximately $357 million. Subsequent to the acquisition, and pursuant to the Posey Solar Merger Agreement, Posey Solar was merged in the Company. 34