# EDGAR Filing Document

**Accession Number:** 0001130310
**File Stem:** 0001130310-26-000021
**Filing Date:** 2026-3
**Character Count:** 117316
**Document Hash:** 5f56a9519d2592dd31837da0efabd940
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001130310-26-000021.hdr.sgml**: 20260319

**ACCESSION NUMBER**: 0001130310-26-000021

**CONFORMED SUBMISSION TYPE**: 8-K

**PUBLIC DOCUMENT COUNT**: 52

**CONFORMED PERIOD OF REPORT**: 20260319

**ITEM INFORMATION**: Regulation FD Disclosure

**ITEM INFORMATION**: Financial Statements and Exhibits

**FILED AS OF DATE**: 20260319

**DATE AS OF CHANGE**: 20260319

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** CENTERPOINT ENERGY INC
- **CENTRAL INDEX KEY:** 0001130310
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 740694415
- **STATE OF INCORPORATION:** TX
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 8-K
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-31447
- **FILM NUMBER:** 26774183

**BUSINESS ADDRESS:**
- **STREET 1:** 1111 LOUISIANA ST.
- **CITY:** HOUSTON
- **STATE:** TX
- **ZIP:** 77002
- **BUSINESS PHONE:** 7132073000

**MAIL ADDRESS:**
- **STREET 1:** 1111 LOUISIANA ST.
- **CITY:** HOUSTON
- **STATE:** TX
- **ZIP:** 77002

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** RELIANT ENERGY REGCO INC
- **DATE OF NAME CHANGE:** 20001220

?xml version='1.0' encoding='ASCII'? cnp-20260319

    

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

Washington, D.C. 20549

**FORM 8-K** 

**CURRENT REPORT**

**Pursuant to Section 13 or 15(d)**

**of the Securities Exchange Act of 1934**

Date of Report (Date of earliest event reported): **March 19, 2026** 

**CENTERPOINT ENERGY, INC.** 

(Exact name of registrant as specified in its charter)

**_______________________________**

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Texas** | | **1-31447** | | | **74-0694415** |
| (State or other jurisdiction |  | (Commission File Number) |  |  | (IRS Employer |
| of incorporation) |  |  |  |  | Identification No.) |
| **&nbsp;&nbsp;&nbsp;&nbsp; 1111 Louisiana** | **&nbsp;&nbsp;&nbsp;&nbsp; 1111 Louisiana** |  |  |  |  |
| **Houston** | **Texas** |  | **77002** | **77002** |  |
| &nbsp;&nbsp;&nbsp;&nbsp; (Address of principal executive offices) | &nbsp;&nbsp;&nbsp;&nbsp; (Address of principal executive offices) |  | (Zip Code) | (Zip Code) |  |
| Registrant's telephone number, including area code: | Registrant's telephone number, including area code: | Registrant's telephone number, including area code: | **(713)** | **207-1111** |  |

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&nbsp;&nbsp;&nbsp;&nbsp;Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (*see* General Instruction A.2. below):

&nbsp;&nbsp;&nbsp;&nbsp;☐&nbsp;&nbsp;&nbsp;&nbsp;Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

&nbsp;&nbsp;&nbsp;&nbsp;☐&nbsp;&nbsp;&nbsp;&nbsp;Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

&nbsp;&nbsp;&nbsp;&nbsp;☐&nbsp;&nbsp;&nbsp;&nbsp;Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

&nbsp;&nbsp;&nbsp;&nbsp;☐&nbsp;&nbsp;&nbsp;&nbsp;Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

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| | | |
|:---|:---|:---|
| Securities registered pursuant to Section 12(b) of the Act: | Securities registered pursuant to Section 12(b) of the Act: | Securities registered pursuant to Section 12(b) of the Act: |
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common Stock, $0.01 par value | CNP | The New York Stock Exchange |
| Common Stock, $0.01 par value | CNP | NYSE Texas |

---

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2).

Emerging Growth Company ☐

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

    

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**Item 7.01.** &nbsp;&nbsp;&nbsp;&nbsp;**Regulation FD Disclosure.**

Included herein is financial information related to Southern Indiana Gas and Electric Company ("CEI South"). CEI South is a wholly-owned subsidiary of Vectren Utility Holdings, LLC ("VUH"). VUH is a wholly-owned subsidiary of Vectren, LLC ("Vectren"), which in turn, is an indirect, wholly-owned subsidiary of CenterPoint Energy, Inc. ("CenterPoint Energy").

Exhibit 99.1 to this Current Report on Form 8-K includes audited financial statements for the years ended December 31, 2025 and 2024 for CEI South. These financial statements are not intended to comply with Regulation S-X or Regulation S-K. Exhibit 99.2 includes certain supplementary financial and operational data of CEI South for the years ended December 31, 2025 and 2024.

Each of Exhibits 99.1 and 99.2 is furnished, not filed, pursuant to Item 7.01. Accordingly, none of the information will be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to the liability of that section, as amended, and the information in Exhibits 99.1 and 99.2 will not be incorporated by reference into any registration statement filed by CenterPoint Energy under the Securities Act of 1933, as amended, unless specifically identified as being incorporated by reference.

**Item 9.01.** &nbsp;&nbsp;&nbsp;&nbsp;**Financial Statements and Exhibits.** 

Each of Exhibits 99.1 and 99.2 is furnished, not filed, pursuant to Item 7.01. Accordingly, none of the information will be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, as amended, and the information in Exhibits 99.1 and 99.2 will not be incorporated by reference into any registration statement filed by CenterPoint Energy under the Securities Act of 1933, as amended, unless specifically identified as being incorporated by reference.

 (d) Exhibits.

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| | |
|:---|:---|
| **EXHIBIT**<br>**<u>NUMBER</u>** | **<u>EXHIBIT DESCRIPTION</u>** |
| 99.1 | <u>[Reporting Package of Southern Indiana Gas and Electric Company](a991reportingpackageofsi.htm)</u> |
| 99.2 | <u>[Financial and Operational Data of Southern Indiana Gas and Electric Company](a992financialandoperatio.htm)</u> |
| 104 | Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document |

---

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SIGNATURE

&nbsp;&nbsp;&nbsp;&nbsp;Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

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| | | |
|:---|:---|:---|
| | **CENTERPOINT ENERGY, INC.** | **CENTERPOINT ENERGY, INC.** |
| Date: March 19, 2026 | By: | /s/ Russell K. Wright |
|  |  | Russell K. Wright |
|  |  | Vice President and Chief Accounting Officer |

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## Exhibit 99.1

![](a991reportingpackageofsi001.jpg)

SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONSOLIDATED FINANCIAL STATEMENTS As of and for the years ended December 31, 2025 and 2024 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 9-31 Exhibit 99.1

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GLOSSARY AFUDC Allowance for funds used during construction 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 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 CEOH Vectren Energy Delivery of Ohio, LLC, doing business as CenterPoint Energy Ohio, which converted its corporate structure from Vectren Energy Delivery of Ohio, Inc. to an Ohio limited liability company on June 13, 2022, formerly a wholly-owned subsidiary of VUH, acquired by CERC on June 30, 2022 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 the Company, 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 EPC Engineering, Procurement and Construction Extension Agreement Extension Agreement to the Credit Agreement, dated as of January 29, 2025, by and among the Company, 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 Indiana Gas Indiana Gas Company, Inc., formerly a wholly-owned subsidiary of VUH, acquired by CERC on June 30, 2022 IRA Inflation Reduction Act of 2022 IRS Internal Revenue Service ITC International Trade Commission IURC Indiana Utility Regulatory Commission kV Kilovolt LIFO Last In - First Out inventory method MGP Manufactured gas plant MISO Midcontinent Independent System Operator MW Megawatts 1

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NYMEX New York Mercantile Exchange Oriden Oriden LLC Origis Origis Energy USA Inc. OUCC Indiana Office of Utility Consumer Counselor 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 the Company and Posey Solar PPA Power purchase agreement PRP Potentially responsible parties PTCs Production Tax Credits RCRA Resource Conservation and Recovery Act of 1976 ROE Return on equity SEC Securities and Exchange Commission 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 of February 1, 2019, and, after CERC Corp's common control acquisition of Indiana Gas and CEOH from VUH on June 30, 2022, is held indirectly by CenterPoint Energy, Inc. through Vectren Affiliated Utilities, Inc., together with its subsidiaries 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 2

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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) and its subsidiary (the "Company"), which comprise the consolidated balance sheets as of December 31, 2025 and 2024, 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, 2025 and 2024, 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

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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 and Electric Company Management is responsible for the other information included in the Financial and Operational Data of Southern Indiana Gas and Electric Company. The other information comprises the information included in the Financial and Operational Data of Southern Indiana Gas and 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 19, 2026 4

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CONSOLIDATED FINANCIAL STATEMENTS SOUTHERN INDIANA GAS AND ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS December 31, 2025 2024 (in millions) ASSETS Current Assets: Cash and cash equivalents ($9 and $7 related to VIEs, respectively) $9 $9 Accounts receivable ($1 and $1 related to VIEs, respectively), less allowance for credit losses of $3 and $2, respectively 65 54 Accrued unbilled revenues ($2 and $2 related to VIEs, respectively) 59 46 Accounts and notes receivable - affiliated companies 146 17 Inventories 97 79 Prepaid expenses and other current assets ($2 and $2 related to VIEs, respectively) 12 18 Total current assets 388 223 Property, Plant and Equipment, Net: Property, plant and equipment 5,543 4,773 Less: accumulated depreciation and amortization 1,559 1,524 Property, Plant and Equipment, net 3,984 3,249 Other Assets: Goodwill 6 6 Regulatory assets ($299 and $313 related to VIEs, respectively) 552 561 Other non-current assets 94 61 Total other assets 652 628 Total Assets $5,024 $4,100 LIABILITIES AND SHAREHOLDER'S EQUITY Current Liabilities: Accounts payable $103 $82 Accounts payable - affiliated companies 34 31 Other current liabilities ($6 and $6 related to VIEs, respectively) 99 89 Current maturities of long-term debt - VIE Securitization Bonds 14 13 Current maturities of long-term debt - third parties — 41 Current maturities of long-term debt - affiliated companies — 106 Total current liabilities 250 362 Other Liabilities: Deferred income taxes, net 378 343 Regulatory liabilities 225 250 Other non-current liabilities 317 227 Total other liabilities 920 820 Long-Term Debt: Long-term debt - VIE Securitization Bonds, net 294 308 Long-term debt - third parties, net 1,452 939 Long-term debt - affiliated companies 150 150 Total long-term debt, net 1,896 1,397 Commitments and Contingencies (Note 9) Shareholder's Equity: Common stock (no par value) 1,010 644 Retained earnings 948 877 Total shareholder's equity 1,958 1,521 Total Liabilities and Shareholder's Equity $5,024 $4,100 The accompanying notes are an integral part of these consolidated financial statements 5

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SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED INCOME Year Ended December 31, 2025 2024 (in millions) Revenues: Electric utility revenues $751 $617 Gas utility revenues 139 121 Securitization Subsidiary 31 33 Total 921 771 Expenses: Fuel and purchased power 270 198 Utility natural gas 41 29 Operation and maintenance 206 179 Depreciation and amortization, excluding Securitization Subsidiary 149 120 Amortization - Securitization Subsidiary 14 16 Taxes other than income taxes 12 12 Total 692 554 Operating Income 229 217 Other Income (Expense): Interest expense, excluding Securitization Subsidiary (68) (50) Interest expense - Securitization Subsidiary (17) (17) Other income, net 30 19 Income Before Income Taxes 174 169 Income tax expense 24 22 Net Income $150 $147 The accompanying notes are an integral part of these consolidated financial statements 6

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SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED CASH FLOWS Year Ended December 31, 2025 2024 Cash Flows from Operating Activities: (in millions) Net income $150 $147 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 163 136 Deferred income taxes and investment tax credits 22 11 Changes in other assets and liabilities: Accounts receivable and accrued unbilled revenue, net (27) (10) Accounts receivables/payable-affiliated companies (2) — Accounts payable 24 (6) Inventories (17) 17 Other current assets (1) 24 Other current liabilities 14 (5) Other non-current assets (33) (35) Other non-current liabilities 36 3 Other operating activities, net (16) (10) Net cash provided by operating activities 313 272 Cash Flows from Investing Activities: Capital expenditures, excluding AFUDC equity (469) (389) Payment for asset acquisition (357) — Increase in notes receivable–affiliated companies (122) (11) Other investing activities, net (2) 3 Net cash used in investing activities (950) (397) Cash Flows from Financing Activities: Net change in short-term notes payable - affiliated companies — (50) Payment of long-term debt - affiliated companies (106) — Proceeds from long-term debt - third parties 515 160 Payment of long-term debt - third parties (41) (22) Payment of long-term debt - VIE Securitization Bonds (13) (17) Payment of debt issuance costs (2) (1) Contribution from parent 366 105 Dividends to parent (79) (56) Other financing activities, net (2) — Net cash provided by financing activities 638 119 Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 1 (6) Cash, Cash Equivalents and Restricted Cash at Beginning of Year 11 17 Cash, Cash Equivalents and Restricted Cash at End of Year $12 $11 The accompanying notes are an integral part of these consolidated financial statements 7

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SOUTHERN INDIANA GAS AND ELECTRIC COMPANY STATEMENTS OF CONSOLIDATED CHANGES IN EQUITY Common Stock Retained Earnings Total Shareholder's Equity (in millions) Balance at January 1, 2024 $539 $786 $1,325 Net income — 147 147 Contribution from parent 105 — 105 Dividends to parent — (56) (56) Balance at December 31, 2024 $644 $877 $1,521 Net income — 150 150 Contribution from parent 366 — 366 Dividends to parent — (79) (79) Balance at December 31, 2025 $1,010 $948 $1,958 The accompanying notes are an integral part of these consolidated financial statements 8

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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"), an Indiana corporation, provides energy delivery services to 154,422 electric customers and 116,163 natural gas customers located in and near Evansville in southwestern Indiana. Of these customers, 88,282 receive combined electric and natural 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. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation. As of December 31, 2025, the Company had a VIE, the 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 its primary beneficiary. Creditors of the Company have no recourse to any assets or revenues of the Securitization Subsidiary. The Securitization Bonds issued by the Securitization Subsidiary are payable only from and secured by securitization property and the bondholders have no recourse to the general credit of the Company. For further information, see Note 6. (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 reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (b) Revenue The Company records revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on actual AMS meter data, supply volumes, estimated line loss and applicable tariff rates. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. For further discussion, see Note 4. (c) 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 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. 9

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(d) 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. (e) 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 solely to support servicing the Securitization Bonds as of December 31, 2025 and 2024 are reflected on the Company's Consolidated Balance Sheets. 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 12. (f) 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. (g) Inventory 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 for the periods presented: December 31, 2025 2024 (in millions) Materials and supplies $47 $43 Coal for electric generation 30 15 Natural gas in storage 20 21 Total inventories $97 $79 Based on the average cost of natural gas purchased during December 2025, the cost of replacing natural gas in storage carried at LIFO cost was less than the carrying value by less than $1 million as of December 31, 2025. 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. (h) 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 were recorded in 2025 or 2024. 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. 10

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(i) 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. The Company performed the annual goodwill impairment tests in the third quarter of 2025 and determined that no goodwill impairment charge was required. (j) Regulatory Assets and Liabilities 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. The Company applies the guidance for accounting for regulated operations within the Electric reportable segment and the Natural Gas reportable segment. The Company may collect revenues subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded that reflect management's current judgment of the ultimate outcomes of the proceedings. The Company recognizes 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 6. (k) Capitalization and Deferral of Interest, including AFUDC The Company capitalizes interest and 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 equipment and earnings, it is realized in cash when the assets are included in rates. The table below includes interest capitalized or deferred for the periods presented: Year Ended December 31, 2025 2024 (in millions) Capitalized interest and AFUDC debt (1) $9 $6 AFUDC – equity (2) 22 16 Deferred debt interest (3) 2 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. 11

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(l) Leases An arrangement is determined to be a lease at inception based on whether the Company has the right to control the use of an identified asset. ROU assets represent the Company's right to use the underlying asset for the lease term and lease liabilities represent the Company's obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term, including payments at commencement that depend on an index or rate. Most leases in which the Company is the lessee do not have a readily determinable implicit rate, so an incremental borrowing rate, based on the information available at the lease commencement dates, is utilized to determine the present value of lease payments. When a secured borrowing rate is not readily available, unsecured borrowing rates are adjusted for the effects of collateral to determine the incremental borrowing rate. Lease expense and lease income are recognized on a straight- line basis over the lease term for operating leases. The Company has lease agreements with lease and non-lease components and has elected the practical expedient to combine lease and non-lease components for certain classes of leases, such as office buildings. For classes of leases in which lease and non- lease components are not combined, consideration is allocated between components based on the stand-alone prices. The Company's lease agreements do not contain any material residual value guarantees, material restrictions or material covenants. There are no material lease transactions with related parties. Because risk is minimal, the Company does not take any significant actions to manage risk associated with the residual value of its leased assets. The Company's operating lease agreements are primarily equipment and real property leases, including land and office facility leases. The Company's lease terms may include options to extend or terminate a lease when it is reasonably certain that those options will be exercised. The Company has elected an accounting policy that exempts leases with terms of one year or less from the recognition requirements of ASC 842. For further details, see Note 13. (m) 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. 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 Consolidated 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. (n) 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 12

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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. (o) Fair Value Measurements Assets and liabilities that are recorded at fair value in the Company's Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows: Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including the Company's own data. (p) Other Significant Policies Included elsewhere in these notes are significant accounting policies related to intercompany allocations and income taxes. See Note 7 for further information. (q) Recent Accounting Pronouncements In September 2025, the FASB issued ASU 2025-06, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software ("ASU 2025-06"). This ASU modernizes the accounting for software costs to adapt to an incremental and iterative software development method. ASU 2025-06 is effective for annual periods beginning after December 15, 2027, and may be applied using a prospective, modified prospective or retrospective transition approach. The Company is currently evaluating the impact of this ASU on its respective consolidated financial statements. 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 adopted this ASU on December 31, 2025, on a retrospective basis. The adoption of this ASU did not have a material impact on the Company's respective consolidated financial statements. See Note 7 for additional disclosures related to effective tax rate reconciliation and Note 12 for additional disclosures related to income taxes paid. 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. 13

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(3) Acquisition Acquisition of Posey Solar. On March 7, 2025, the Company acquired 100% of the equity interests in Posey Solar, which was constructing a 191 MW solar array in Posey County, Indiana, for approximately $357 million. The purchase represents an asset acquisition. The lease obligations related to Posey Solar were approximately $35 million at the time of acquisition. The purchase was subject to terms and conditions in an order approved by the IURC on September 6, 2023, allowing the Company to recover project costs, net of PTCs, in rate base rather than a levelized rate, through base rates or the CECA mechanism, depending on which provides more timely recovery. Posey Solar was placed into service on May 30, 2025. The Company began recovering on the asset through updated base rates on June 17, 2025. On February 3, 2025, the IURC approved the Company's request to convey PTCs to customers through the new tax adjustment rider. (4) 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 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 major source: Year Ended December 31, 2025 2024 Revenue from contracts with customers $916 $749 Other (1) 7 24 Eliminations (2) (2) Total revenues $921 $771 (1) Primarily consists of income from ARPs. 14

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Contract Balances The Company does not have any material contract balances. Substantially all the Company's accounts receivable and accrued unbilled revenues are derived from contracts with customers. 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. The table below summarizes the bad debt expense, net of regulatory deferrals: Year Ended December 31, 2025 2024 (in millions) Bad debt expense $6 $4 (5) Property, Plant and Equipment (a) Property, Plant and Equipment Property, plant and equipment includes the following: December 31, 2025 December 31, 2024 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 $2,994 $1,188 $1,806 $2,742 $1,163 $1,579 Electric generation 35 1,569 169 1,400 1,107 154 953 Natural gas distribution 37 980 202 778 924 207 717 Total $5,543 $1,559 $3,984 $4,773 $1,524 $3,249 (b) Depreciation and Amortization The following table presents depreciation and amortization expense: Year Ended December 31, 2025 2024 (in millions) Depreciation $147 $120 Amortization of regulatory assets (1) 16 16 Total $163 $136 (1) For the years ended December 31, 2025 and 2024, amount includes amortization expense of $14 million million and $16 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 15

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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. 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 9(b) 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, 2025 2024 (in millions) Beginning balance $167 $152 Additions 4 11 Accretion expense (1) 11 4 Revisions in estimates (2) 45 — Ending balance $227 $167 (1) Reflected in Regulatory assets on the Company's Consolidated Balance Sheets. (2) The Company's revision in its ARO liability was primarily attributable to increases in estimated future cash flows. (6) Regulatory Assets and Liabilities The following is a list of regulatory assets and liabilities reflected on the Company's Consolidated Balance Sheets as of the dates presented: December 31, 2025 2024 (in millions) Regulatory Assets: Future amounts recoverable from ratepayers related to: Asset retirement obligations and other $50 $45 Net deferred income taxes 36 27 Total future amounts recoverable from ratepayers 86 72 Amounts deferred for future recovery related to: Cost recovery riders 15 78 Unrecognized equity return (1) (4) (7) Total amounts deferred for future recovery 11 71 Amounts currently recovered in customer rates related to: Authorized trackers and cost deferrals (2) 481 456 Gas recovery costs 2 1 Unamortized loss on reacquired debt and hedging 17 20 Unrecognized equity return (1) (43) (58) Total amounts recovered in customer rates 457 419 Total Regulatory Assets $554 $562 Total Current Regulatory Assets (3) $2 $1 Total Non-Current Regulatory Assets $552 $561 Regulatory Liabilities: Regulatory liabilities related to TCJA $157 $170 Estimated removal costs 44 56 Other regulatory liabilities 24 24 Total Regulatory Liabilities $225 $250 16

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(1) Represents the Company's allowed equity return on post in-service carrying cost. (2) Includes the securitized regulatory assets discussed below in Securitization of Generation Retirements. (3) Included in Prepaid expenses and other current assets on the Company's Consolidated Balance Sheets. Of the $457 million currently being recovered in rates charged to customers, $27 million is earning a return. The weighted average recovery period of regulatory assets currently being recovered in base rates, which totals $430 million, is 12 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. 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 Note 5 and Note 9 for further information. 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 10. 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. The Securitization Subsidiary issued $341 million aggregate principal amount of the Securitization Bonds on June 29, 2023 and used a portion of the net proceeds from the issuance of the Securitization Bonds 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. (7) 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, 2025 and 2024 are included in Accounts 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, 2025 2024 (in millions) Corporate service charges $72 $39 17

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Property, Plant and Equipment The Company purchased certain property, plant and equipment assets from VUH at their net carrying value of $2 million and $4 million in 2025 and 2024, respectively. Cash Management Arrangements The Company participates in the centralized cash management program with affiliates of Vectren. See Note 8 for further information regarding intercompany borrowing arrangements. The table below summarizes the Company's money pool activity as of the dates presented: December 31, 2025 2024 (in millions, except interest rates) Money pool investments (1) $133 $11 Weighted average interest rate 3.83 % 4.65 % (1) Included in Accounts and notes receivable–affiliated companies in the Consolidated Balance Sheets as of December 31, 2025 and December 31, 2024. 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. As of December 31, 2025, the Company had an income tax payable to Vectren of $5 million, which is included in Other current liabilities in the Company's Consolidated Balance Sheet. The components of income tax expense and amortization of investment tax credits were as follows: Year Ended December 31, 2025 2024 (in millions) Current income tax expense (benefit): Federal $6 $9 State (4) 2 Total current income tax expense 2 11 Deferred income tax expense (benefit): Federal 28 5 State (5) 7 Total deferred income tax expense 23 12 Investment tax credit amortization (1) (1) Total income tax expense $24 $22 18

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A reconciliation of the federal statutory rate to the effective income tax rate was as follows: Year Ended December 31, 2025 2024 Amount Percent Amount Percent (in millions, except percentages) Income before income taxes $174 $169 Federal statutory rate 37 21 % 35 21 % Increase (decrease) in tax expense resulting from: State income tax expense (benefit), net of federal income tax (1) (7) (4) % 7 4 % Tax credits — — % 1 1 % Nontaxable or non-deductible items: Equity AFUDC (5) (3) % (3) (2) % Other — — % (1) (1) % Tax attribute adjustment 11 6 % — — % Excess deferred income tax amortization (11) (6) % (11) (7) % Audit adjustments — — % (5) (3) % Other, net (1) — % (1) — % Total (12) (7) % (13) (8) % Total income tax expense and effective tax rate $24 14 % $22 13 % (1) For all periods presented, Indiana contributed to 100% of the tax effect. Significant components of the net deferred tax liability were as follows: December 31, 2025 2024 (in millions) Non-current deferred tax assets: Net operating loss and other carryforwards $173 $97 Regulatory liabilities 38 40 Benefits and compensation 3 4 Asset retirement obligations 10 3 Other, net 13 21 Total deferred tax assets 237 165 Non-current deferred tax liabilities: Property, plant and equipment 569 485 Regulatory assets 35 8 Deferred fuel costs 11 15 Total deferred tax liabilities 615 508 Net deferred tax liabilities $378 $343 Tax Attribute Carryforwards As of December 31, 2025, the Company had (i) federal net operating loss carryforwards $421 million, which have an indefinite carryforward period, (ii) federal corporation alternative minimum tax carryforwards of $32 million, which have an indefinite carryforward period; (iii) $628 million of gross state net operating loss carryforwards, which expire beginning in 2039; and (iv) $27 million of investment tax credit carryforwards that will expire in 2041. As of December 31, 2025 and 2024, deferred investment tax credits totaling $26 million and $26 million, respectively, are included in Other non-current liabilities on the Consolidated Balance Sheets. 19

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Uncertain Tax Positions The Company has no unrecognized tax benefits for the years ended December 31, 2025 and 2024. Tax Audits and Settlements CenterPoint Energy files a consolidated federal income tax return that includes results from the Company's parent, Vectren, LLC. Certain subsidiaries of CenterPoint Energy, Inc., including Vectren, LLC, file state income tax returns in various jurisdictions. Tax years through 2022 have been audited and settled with the IRS for CenterPoint Energy. For the tax years 2023, 2024 and 2025, CenterPoint Energy, Inc. and its subsidiaries are participants in the IRS's Compliance Assurance Process. Income Tax Payables and Refunds For income taxes paid or refunds received for the years ended December 31, 2025 and 2024, see Note 12. 20

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(8) 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, 2023 Series-A Securitization Bond Tranche A-1, 5.026% $185 $198 2041, 2023 Series-A Securitization Bond Tranche A-2, 5.172% 126 126 Total Securitization Bonds 311 324 Current maturities (14) (13) Unamortized debt issuance cost (3) (3) Total long-term debt - VIE Securitization Bonds, net $294 $308 First Mortgage Bonds Payable to Third Parties: 2025, 2014 Series B, 3.45%, tax-exempt $— $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% 100 100 2036, 2024 Series 2024A, 5.28% 60 60 2055, 2025 Series 2025A, 5.69% 165 — 2031, 2025 Series 2025B, 5.09% 100 — 2035, 2025 Series 2025B, 5.52% 105 — 2055, 2025 Series 2025C, 6.18% 100 — 2040, 2025 Series 2025C, 5.77% 45 — Total First Mortgage Bond payable to third parties 1,458 984 Current maturities — (41) Unamortized debt issuance cost (6) (4) Total long-term debt - third parties, net $1,452 $939 Fixed Rate Senior Unsecured Notes Payable to Affiliated Companies 2025, 1.21% $— $106 2030, 1.72% 75 75 2032, 3.26% 75 75 Total long-term debt - affiliated companies 150 256 Current maturities — (106) Total long-term debt - affiliated companies, net $150 $150 December 31, 2025 2024 (in millions) 21

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Debt Transactions Debt Issuances. During 2025, 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) January 2025 (1) First Mortgage Bonds 165 5.69% 2055 July 2025 (2) First Mortgage Bonds 100 5.09% 2031 July 2025 (2) First Mortgage Bonds 105 5.52% 2035 October 2025 (3) First Mortgage Bonds 45 5.77% 2040 October 2025 (3) First Mortgage Bonds 100 6.18% 2055 $515 (1) Net proceeds from the Company's January 2025 issuance of first mortgage bonds, after deducting transaction expenses and fees, were approximately $164 million, which were used for the acquisition of Posey Solar. (2) Net proceeds from the Company's July 2025 issuance of the 2025B Bonds, after deducting transaction expenses and fees, were approximately $204 million, which were used for general corporate purposes, including repaying short-term debt, refunding long-term debt at maturity or otherwise, and funding capital expenditures. (3) Net proceeds from the Company's October 2025 issuance of the 2025C Bonds, after deducting transaction expenses and fees, were approximately $145 million, which were used for general corporate purposes, including repaying short-term debt, refunding long-term debt at maturity or otherwise, and funding capital expenditures. Debt Repayments and Redemptions. During 2025, 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) July 2025 (1) First Mortgage Bonds 41 3.45% 2025 $41 (1) In July 2025, the Company repaid at maturity $41 million aggregate principal amount of the Company's outstanding 3.45% first mortgage bonds due 2025 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. Securitization Bonds. As of December 31, 2025, the Company had a VIE, Securitization Subsidiary, which is consolidated. The consolidated VIE 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 Securitization Subsidiary is the sole owner of the right to impose, collect and receive the applicable 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. 22

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Credit Facility. The Company had the following revolving credit facility as of December 31, 2025: 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, 2025 (2) Termination Date (3) (in millions) December 6, 2022 $250 1.125% 65% 45% December 6, 2028 (1) Based on credit ratings as of December 31, 2025. (2) As defined in the revolving credit facility agreement, excluding Securitization Bonds. (3) 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. There were no borrowings outstanding under the revolving credit facility as of December 31, 2025 and 2024. Future Long-Term Debt Sinking Fund Requirements and Maturities. As of December 31, 2025, the Company had approximately $1.5 billion 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, 2025, the Company was permitted to issue additional bonds under its mortgage indenture up to 70% of then unfunded property additions and approximately $892 million of additional first mortgage bonds could be issued on this basis. Maturities. As of December 31, 2025, 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) 2026 $— $— $14 $14 2027 — — 14 14 2028 — 100 15 115 2029 — 180 16 196 2030 75 105 17 197 2031 and thereafter 75 1,073 236 1,384 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, 2025, the Company was in compliance with all financial debt covenants. (9) Commitments and Contingencies (a) Purchase Obligations Commitments include minimum purchase obligations related to both electric supply and natural gas supply contracts. 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, 2025 and 2024 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

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As of December 31, 2025, the Company had the following undiscounted minimum purchase obligations: Electric Supply (1) Natural Gas Supply (in millions) 2026 $132 $4 2027 159 4 2028 100 4 2029 98 4 2030 82 4 Thereafter 1,593 22 Total $2,164 $42 (1) Related to PPAs with commitments ranging from 20 years to 27 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 10. (b) 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, 2025 (in millions, except years) Amount accrued for remediation $2 Minimum estimated remediation costs 2 Maximum estimated remediation costs 7 Minimum years of remediation 5 Maximum years of remediation 20 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 24

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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. Following approval of its most recent rate case, this project is now being recovered through base rates. As of December 31, 2025, the Company has recorded an approximate $175 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 2015, the EPA finalized revisions to the existing steam electric wastewater discharge standards that 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. On December 31, 2025, the EPA published a final rule extending various deadlines and other provisions of the 2024 Supplemental ELG. The Company currently anticipates that it will be in compliance with the Supplemental ELG at the Culley facility due to previous wastewater treatment upgrades. 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. (c) 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 25

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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. (10) Regulatory Matters Securitization of Generation Retirements For further information about the issuance of Securitization Bonds, see Note 6. BTAs The Company has pursued PTCs for solar projects following the passage of the IRA. On February 7, 2023, the Company filed a CPCN with the IURC to approve an amended BTA to purchase the 191 MW Posey Solar project. 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. On March 7, 2025, the Company completed the acquisition of Posey Solar from Arevon for a purchase price of approximately $357 million. The Posey Solar project was placed in service in the second quarter of 2025 and is currently being recovered through base rates. In the applicable rate case, the IURC approved the Company's request to convey PTCs to customers through the new tax adjustment rider. For further information, see Note 3. On January 10, 2023, the Company filed a CPCN with the IURC to acquire a wind energy generating facility located in the central region of MISO through a BTA, and on June 6, 2023, the IURC issued an order approving the CPCN, thereby authorizing the Company to purchase the wind generating facility. In August 2025, due to changing project considerations and concerns about customer affordability, the Company exited negotiations relating to this wind energy generating facility. On December 4, 2025, the Company filed a Notice of Termination in this proceeding. PPAs The Company sought approval in February 2021 for a 100 MW solar PPA with Clenera LLC in Warrick County, Indiana. The request accounted for increased cost of debt related to this PPA, which would provide equivalent equity return to offset imputed debt during the 25-year life of the PPA. In October 2021, the IURC approved the Warrick County solar PPA but denied the request to preemptively offset imputed debt in the PPA cost. Due to rising project costs caused by inflation and supply chain issues affecting the energy industry, Clenera LLC and the Company renegotiated the terms of the agreement to increase the PPA price and the Company subsequently filed a request with the IURC to amend the previously approved PPA with certain modifications. On May 30, 2023, the IURC approved the Warrick County solar amended PPA; however, due to MISO interconnection study delays and estimated interconnection cost increases, on April 24, 2025, the Company provided notice that it was exercising its right to terminate the PPA, which terminated all further obligations of the Company with respect to the project. 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 largely due to 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 2021 PPA with certain modifications. On February 22, 2023, the IURC approved the Knox County solar amended PPA; however, due to MISO interconnection delays, the project in- service date was delayed from 2024 to 2026. The facility became operational on February 27, 2026. The power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA. On January 17, 2023, the Company filed a request with the IURC to amend the previously approved PPA with Oriden with certain modifications. On May 30, 2023, the IURC approved the Vermillion County solar amended PPA; however, due to MISO interconnection study delays, the developer disclosed the project in-service date would be delayed to 2028. On May 9, 2025, the Company and Oriden terminated the PPA. 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 late 2026. 26

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On April 14, 2025, the Company filed with the IURC seeking approval to purchase 170 MW of wind power under a 25-year PPA with an affiliate of NextEra Energy, Inc., which is developing a wind project in Tama County, Iowa. On June 3, 2025, an amendment to the PPA was filed with the IURC requesting an extension of the PPA's term from 25 to 27 years. The Company received a final order from the IURC on November 5, 2025. The facility became operational on December 9, 2025. The power purchase costs will be recovered through the fuel adjustment clause proceedings over the term of the PPA. 2025 IRP On December 5, 2025, the Company submitted its 2025 IRP with the IURC pursuant to applicable Indiana law requiring electric utilities to develop and submit to the IURC every three years (unless extended) an IRP that uses economic modeling to consider the costs and risks associated with available generation resource options to provide reliable, cost effective electric service for the next 20-year period. The Company's 2025 IRP was developed following a series of public meetings and stakeholder discussions occurring in 2025 and identified both a preferred portfolio, which assumes the status quo for the Company's service territory, and an alternative preferred portfolio, which includes a potential large load addition. Due to the phasing out of IRA renewable energy tax incentives pursuant to the OBBBA, declining accreditation from MISO for renewable energy and increased price pressure on resources due to, among other things, tariffs and ongoing supply chain issues, the 2025 IRP extends the timing for the Company's generation transition plan. Accordingly, both the preferred portfolio and the alternative portfolio call for using the interconnection at F.B. Culley unit 2 for a 90 MW battery storage unit by 2028 and the conversion of the A.B. Brown units 5 and 6 gas turbines to a combined cycle gas turbine unit in the near- to mid-term, depending on load conditions. Decisions around F.B. Culley 3 will be reevaluated in the next IRP. The 2025 IRP includes the cancellation of nearly $1 billion in non-economical renewable projects. F.B. Culley Unit 2 While the Company's 2025 IRP (similar to previous IRPs) included the retirement of F.B. Culley Unit 2, a coal-fired generation unit, by the end of 2025, the U.S. Department of Energy issued an emergency 202(c) order in December 2025 directing the Company to continue operating the unit through March 23, 2026. The Company has filed a complaint with the FERC to request creation of a cost recovery/cost allocation mechanism. If created, a separate filing will be made at a later date with the FERC to seek recovery of all costs incurred to comply with the U.S. Department of Energy's emergency 202(c) order. Indiana Electric has also filed an application with the IURC in Cause No. 46350 to recover any compliance costs associated with the emergency 202(c) order that are not recovered through the FERC proceedings. Natural Gas Combustion Turbines 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 $287 million turbine facility was constructed at the previous site of the A.B. Brown power plant in Posey County, Indiana. 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 was constructed and is operated by Texas Gas Transmission, LLC to supply natural gas to the turbine facility. FERC granted a certificate to construct the pipeline on October 20, 2022. On January 7, 2025, the United States Court of Appeals for the D.C. Circuit affirmed the FERC's order granting the certificate. The Company granted its contractor a full notice to proceed to construct the turbines on December 9, 2022. In the second quarter of 2025, 230 MW of the facility was placed in service, and, due to a transformer manufacturing issue, the remaining 230 MW of the facility was placed in service in the third quarter of 2025. The Company received approval from the IURC on February 3, 2025, to recover for each combustion turbine by adjusting base rates as they are placed in service. The first turbine and second turbine are currently being recovered in base rates that were updated on June 17, 2025 and October 1, 2025, respectively. Indiana Legislation The Company is evaluating the effects of certain legislation passed in 2026, including House Enrolled Act (HEA) 1002, a multi-faceted bill aimed at improving the affordability of electric rates, which became law during Indiana's 124th General Assembly. HEA 1002 does the following: • beginning in 2026, requires an electric utility to file a multi-year rate plan according to a prescribed schedule; • applies a customer affordability performance metric and a service restoration performance metric to each year of the multi-year rate plan and uses such metric to provide financial rewards or penalties based on the electricity supplier's measured performance of the metric; 27

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• requires an electric utility to offer a low income customer assistance program by July 1, 2026 to be funded by at least 0.2% of jurisdictional revenues for residential customers and allows the utility to seek recovery of eligible program costs; • prohibits an electric utility from terminating service to any customer on a day forecasted by the National Weather Service to have a heat index of at least 95 degrees Fahrenheit; • modifies the IURC's authority related to use of emergency powers; • beginning with the first monthly billing cycle after June 30, 2026, requires an electric utility to apply a levelized billing plan to residential customers who are eligible and have applied for the Low Income Housing Energy Assistance Program; and • requires an electric utility to report certain residential customer data to the Office of the Utility Consumer Counselor on a quarterly basis. 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 trackers 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. The first phase of rates, Phase 1, was implemented with an effective date of February 13, 2025, and the final phase of rates, Phase 2, was implemented with an effective date of March 5, 2026. The table below reflects significant applications pending or completed since the Company's 2024 financial statements were furnished to the SEC on Current Report 8-K dated March 18, 2025 through March 19, 2026. 28

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Gas (IURC) CSIA 2 April 2025 August 2025 July 2025 Requested an increase of $11.6 million to rate base, which reflects an approximately $1.5 million annual increase in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes a change in (over)/under recovery variance of $1.9 million. The OUCC filed testimony on June 3, 2025, recommending minor changes. Indiana South filed a rebuttal on June 17, 2025, adopting the changes. The evidentiary hearing was held on June 30, 2025. A final order was issued on July 30, 2025, with rates effective August 1, 2025. CSIA 1 October 2025 February 2026 January 2026 Requested an increase of $13.0 million to rate base, which reflects an approximately $1.2 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 $(2.1) million. The OUCC filed testimony on December 2, 2025, recommending minor changes, and Indiana South filed rebuttal on December 16, 2025. An evidentiary hearing was held January 6, 2026. A final order was issued on January 28, 2026 with rates effective on February 1, 2026. Electric (IURC) ECA $(1) May 2025 January 2026 December 2025 Requested a decrease of $10 million to rate base, which reflects a $1 million annual decrease in current revenues, of which 80% is included in the mechanism and 20% is deferred until the next rate case. The mechanism also includes an increase in the under recovery variance of $1.4 million. The final order was issued on December 30, 2025, approving rates effective January 1, 2026. CECA $— February 2025 July 2025 July 2025 Did not request a change in rate base, which reflects no change in current revenues. The mechanism includes a change in (over)/under-recovery variance of $0.1 million. The final order was issued July 2, 2025, approving rates effective July 2, 2025. Mechanism Annual Increase (Decrease) (in millions) Filing Date Effective Date Approval Date Additional Information (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 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 as of December 31, 2025 and 2024, 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, 2025 2024 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt, including current maturities: VIE Securitization Bonds $308 $312 $321 $322 Third parties 1,452 1,525 980 1,007 Affiliated companies 150 136 256 128 Total long-term debt, including current maturities $1,910 $1,973 $1,557 $1,457 29

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(12) Supplemental Cash Flow Information The table below provides supplemental disclosure of cash flow information: Year Ended December 31, 2025 2024 (in millions) Cash Payments: Income tax payments $— $5 Interest, net of capitalized interest 74 82 Non-cash transactions: Accounts payable related to capital expenditures $11 $15 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, 2025 2024 (in million) Cash and cash equivalents (1) $9 $9 Restricted cash included in Prepaid expenses and other current assets 3 2 Total cash, cash equivalents and restricted cash shown in Statements of Consolidated Cash Flows $12 $11 (1) Included $9 million and $7 million related to the Securitization Subsidiary as of December 31, 2025 and 2024, respectively. (13) Leases The components of lease cost, included in Operation and maintenance on the Company's Consolidated Statements of Income, were as follows: Year Ended December 31, 2025 2024 (in millions) Operating lease cost $2 $1 Short-term lease cost 1 — Total lease cost $3 $1 30

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Supplemental balance sheet information related to leases is as follows: December 31, 2025 2024 (In millions, except lease term and discount rate) Assets: Operating ROU assets (1) $40 $5 Total leased assets $40 $5 Liabilities: Current operating lease liability (2) $1 $— Non-current operating lease liability (3) 39 5 Total lease liabilities $40 $5 Weighted-average remaining lease term (in years) - operating leases 33.0 28.9 Weighted-average discount rate - operating leases 5.64 % 5.21 % (1) Reported within Other non-current assets in the Consolidated Balance Sheets. (2) Reported within Other current liabilities in the Consolidated Balance Sheets. (3) Reported within Other non-current liabilities in the Consolidated Balance Sheets. As of December 31, 2025, maturities of operating lease liabilities were as follows: (in millions) 2026 $2 2027 2 2028 2 2029 2 2030 2 2031 and beyond 87 Total lease payments $97 Less: Interest 57 Present value of lease liabilities $40 Other information related to leases is as follows: Year Ended December 31, 2025 2024 (in millions) Operating cash flows from operating leases included in the measurement of lease liabilities $2 $— ROU assets obtained in exchange for new operating lease liabilities 35 4 (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 19, 2026, the date the financial statements were issued. 31

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## Exhibit 99.2

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\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\*\* The following discussion and analysis provides additional information regarding Southern Indiana Gas and Electric Company's (the Company) results of operations that is supplemental to, and should be read in conjunction with, the information provided in the Company's 2025 consolidated financial statements and notes thereto. The following discussion and analysis should also be read in conjunction with CenterPoint Energy Inc.'s 2025 Annual Report on Form 10-K as it relates to the Company, which includes risk factors and forward looking statements. The Company generates revenue primarily from the delivery of natural gas and electric service to its customers, and the Company's primary source of cash flow results from the collection of customer bills and the payment for goods and services procured for the delivery of natural gas and electric services. Executive Summary of Results of Operations Operating Results In 2025, the Company reported net income of $150 million compared to $147 million in 2024, an increase of $3 million. The favorable variance is primarily due to an increase in margin as further described below. The Regulatory Environment Gas and electric operations, with regard to retail rates and charges, terms of service, accounting matters, financing, and certain other operational matters, are regulated by the Indiana Utility Regulatory Commission (IURC). In the Company's natural gas service territory, normal temperature adjustment (NTA) and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to residential and commercial customers due to weather and changing consumption patterns. In addition to these mechanisms, the IURC has authorized gas and electric infrastructure replacement programs, which allow for recovery of these investments outside of a base rate case proceeding. Further, rates charged to natural gas customers contain a gas cost adjustment (GCA) and electric rates contain a fuel adjustment clause (FAC). Both of these cost tracker mechanisms allow for the timely adjustment in charges to reflect changes in the cost of gas and cost for fuel. The Company utilizes similar mechanisms for other material operating costs, which allow for changes in revenue outside of a base rate case. Rate Design Strategies Sales of natural gas and electricity to residential and commercial customers are largely seasonal and are impacted by weather. Trends in the average consumption among natural gas residential and commercial customers have tended to decline as more efficient appliances and furnaces are installed and the Company's utilities have implemented conservation programs. In the Company's natural gas service territory, NTA and decoupling mechanisms largely mitigate the effect that would otherwise be caused by variations in volumes sold to these customers due to weather and changing consumption patterns. In the Company's natural gas service territory, the IURC has authorized bare steel and cast iron replacement programs. State laws were passed in 2012 and 2013 that expand the ability of utilities to recover, outside of a base rate proceeding, certain costs of federally mandated projects and other significant gas distribution and transmission infrastructure replacement investments. The Company has received approval to implement these mechanisms. In 2017, the Company's electric service territory started recovering certain costs of electric distribution and transmission infrastructure replacement investments. The electric service territory also currently recovers certain transmission investments outside of base rates. The electric service territory has neither an NTA nor a decoupling mechanism; however, rate designs provide for a lost margin recovery mechanism that works in tandem with conservation initiatives. Tracked Operating Expenses Gas costs and fuel costs incurred to serve customers are two of the Company's most significant operating expenses. Rates charged to natural gas customers contain a GCA. The GCA allows the Company to timely charge for changes in the cost of purchased gas, inclusive of unaccounted for gas expense based on actual experience and subject to caps that are based on historical experience. Electric rates contain a FAC that allows for timely adjustment in charges for electric energy to reflect changes in the cost of fuel. The net energy cost of purchased power, subject to an approved variable benchmark based on The New York Mercantile Exchange (NYMEX) natural gas prices, is also timely recovered through the FAC. Exhibit 99.2 1

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GCA and FAC procedures involve periodic filings and IURC hearings to establish price adjustments for a designated future period. The procedures also provide for inclusion in later periods of any variances between actual recoveries representing the estimated costs and actual costs incurred. The IURC has also applied the statute authorizing GCA and FAC procedures to reduce rates when necessary to limit net operating income to a level authorized in its last general rate order through the application of an earnings test. In the periods presented, the Company has not been impacted by the earnings test. Midcontinent Independent System Operator (MISO) charges and other reliability costs and revenues incurred to serve retail electric customers are recovered through the Reliability Cost and Revenue Adjustment (RCRA) and MISO Cost and Revenue Adjustment (MCRA). MISO charges include specific charges under the MISO's Federal Energy Regulatory Commission (FERC) approved tariff for items such as reactive power, scheduling, and transmission network charges that are socialized among various MISO members. Reliability costs and revenues include non-fuel costs of purchased power and costs and credits associated with certain interruptible customers. Gas pipeline integrity management operating costs, costs to fund energy efficiency programs, MISO costs, and the gas cost component of uncollectible accounts expense based on historical experience are recovered by mechanisms outside of typical base rate recovery. In addition, certain operating costs, including depreciation associated with federally mandated investments, gas and electric distribution and transmission infrastructure replacement investments, and regional electric transmission assets not in base rates are also recovered by mechanisms outside of typical base rate recovery. Revenues and margins are also impacted by the collection of state mandated taxes, which primarily fluctuate with gas and fuel costs. Base Rate Orders 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. The final phase of rates, Phase 2, was implemented with an effective date of March 5, 2026. See Note 10 to the consolidated financial statements for more specific information on the significant regulatory proceedings involving the Company. Operating Trends Margin Throughout this discussion, the terms Natural Gas margin and Electric margin are used. Natural Gas margin is calculated as Natural gas revenues less Utility natural gas. Electric margin is calculated as Electric revenues less Fuel and purchased power. The Company believes Natural Gas and Electric margins, together with net income, provide useful indicators for assessing performance. While revenues reflect overall activity levels, gas prices and fuel and purchased power costs can be volatile and are generally collected from customers on a dollar-for-dollar basis. In addition, the Company separately reflects regulatory expense recovery mechanisms within Natural Gas margin and Electric margin. These amounts represent dollar-for-dollar recovery of other operating expenses. The Company utilizes these approved regulatory mechanisms to recover variations in operating expenses from the amounts reflected in base rates and are generally expenses that are subject to volatility. Following is a discussion and analysis of margin. 2

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Electric Margin (Electric revenues less Fuel and purchased power) Electric margin and volumes sold by customer type follows: Year Ended December 31, (In millions) 2025 2024 Electric revenues (1) $782 $650 Fuel and purchased power 270 198 Total Electric margin $512 $452 Margin attributed to: Residential and commercial customers $240 $230 Industrial customers 142 121 Other 13 13 Regulatory expense recovery mechanisms 71 60 Subtotal: Retail 466 424 Wholesale margin 46 28 Total Electric margin $512 $452 Electric volumes sold in MWh attributed to: Residential and commercial customers 2,598,456 2,566,545 Industrial customers 2,380,611 2,233,775 Other customers 12,156 17,675 Total retail volumes 4,991,223 4,817,995 Wholesale 1,618 (289) Total volumes sold 4,992,841 4,817,706 (1) Includes revenues of $31 million and $33 million from the Securitization Subsidiary for the years ended December 31, 2025 and 2024, respectively. Retail Electric retail utility margin was $466 million for the year ended December 31, 2025, compared to $424 million in 2024, an increase of $42 million. The increase was primarily driven by new customer rates implemented following the final order in the rate case in February 2025, an increase in customer usage and growth, and an increase related to weather impacts. Heating degree days were 99 percent of normal in 2025 compared to 80 percent of normal in 2024, and cooling degree days were 107 percent of normal in 2025 compared to 112 percent of normal in 2024. Margin from Wholesale Electric Activities The Company earns a return on electric transmission projects constructed by the Company in its service territory that meet the criteria of the MISO's regional transmission expansion plans and also markets and sells its generating and transmission capacity to optimize the return on its owned assets. Substantially all off-system sales are generated in the MISO Day Ahead and Real Time markets when sales into the MISO in a given hour are greater than amounts purchased for native load. Further detail of MISO off- system margin and transmission system margin follows: Year Ended December 31, (In millions) 2025 2024 MISO transmission system margin $26 $24 MISO off-system margin 20 4 Total wholesale margin $46 $28 Transmission system margin associated with qualifying projects, including the reconciliation of recovery mechanisms and other transmission system operations, totaled $26 million during 2025 compared to $24 million in 2024, an increase of $2 million. For the year ended December 31, 2025, margin from off-system sales was $20 million compared to $4 million in 2024, an increase of $16 million. The base rate changes implemented in February 2025 require wholesale margin from off-system sales to be fully returned to customers under the approved rate case mechanism. 3

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Natural Gas Margin (Natural Gas revenues less Utility natural gas) Natural Gas margin and throughput by customer type follows: Year Ended December 31, (In millions) 2025 2024 Natural Gas revenues $139 $121 Utility natural gas 41 29 Total Natural Gas margin $98 $92 Margin attributed to: Residential & commercial customers $80 $76 Industrial customers 16 14 Other — 1 Regulatory expense recovery mechanisms 2 1 Total Natural Gas margin $98 $92 Sold and transported volumes in MDth attributed to: Residential and commercial customers 10,095 8,955 Industrial customers 39,924 34,105 Total sold and transported volumes 50,019 43,060 For the year ended December 31, 2025, Natural Gas margin was $98 million compared to $92 million in 2024, an increase of $6 million. The increase was primarily due to increased revenues driven by customer rates and the impact of the change in rate design. While weather has relatively no impact on customer margin due to the Company's rate design, heating degree days were 93 percent of normal in 2025 compared to 76 percent of normal in 2024. Operating Expenses Operation and Maintenance For the year ended December 31, 2025, Operation and maintenance expenses were $206 million compared to $179 million in 2024, an increase of $27 million. The increase was primarily driven by higher generating facility costs associated with the new natural gas combustion turbines at the previous site of the A.B. Brown power plant in Posey County, Indiana and Posey Solar, both of which began operations in 2025. Depreciation and Amortization For the year ended December 31, 2025, Depreciation and amortization expense was $163 million compared to $136 million in 2024, an increase of $27 million. The Company had a larger plant in service balance as both the new natural gas combustion turbines at the previous site of the A.B. Brown power plant in Posey County, Indiana and Posey Solar were placed in service during 2025, resulting in higher depreciation expense. 4

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SELECTED ELECTRIC OPERATING STATISTICS For the Year Ended December 31, 2025 2024 OPERATING REVENUES (in millions): Residential $293 $246 Commercial 194 173 Industrial 236 190 Other 13 13 Total retail 736 622 Net wholesale revenues 20 4 Transmission revenues 26 24 $782 $650 MARGIN (In millions): Residential $154 $139 Commercial 86 91 Industrial 142 121 Other 13 13 Regulatory expense recovery mechanisms 71 60 Total retail 466 424 Wholesale power and transmission system 46 28 $512 $452 ELECTRIC SALES (In MWh): Residential 1,446,133 1,421,485 Commercial 1,152,323 1,145,060 Industrial 2,380,611 2,233,775 Other sales - street lighting 12,156 17,675 Total retail 4,991,223 4,817,995 Wholesale 1,618 (289) 4,992,841 4,817,706 CUSTOMER COUNT: Residential 134,695 133,866 Commercial 19,596 19,411 Industrial 111 110 Other 20 20 154,422 153,407 WEATHER AS A % OF NORMAL: Cooling degree days 107 % 112 % Heating degree days 99 % 80 % 5

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SELECTED GAS OPERATING STATISTICS For the Year Ended December 31, 2025 2024 OPERATING REVENUES (in millions): Residential $91 $81 Commercial 34 27 Industrial 13 12 Other 1 1 $139 $121 MARGIN (In millions): Residential $62 $59 Commercial 18 17 Industrial 16 14 Other — 1 Regulatory expense recovery mechanisms 2 1 $98 $92 GAS SOLD and TRANSPORTED (In MDth): Residential 6,420 5,756 Commercial 3,675 3,199 Industrial 39,924 34,105 50,019 43,060 CUSTOMER COUNT Residential 105,497 105,344 Commercial 10,518 10,511 Industrial 148 136 116,163 115,991 6

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