NATIONAL FUEL GAS CO 10-Q

Item 1. Financial Statements National Fuel Gas Company Consolidated Statements of Income and Earnings Reinvested in the Business (Unaudited) Three Months Ended December 31, (Thousands of U.S. Dollars, Except Per Common Share Amounts) 2025 2024 INCOME Operating Revenues: Utility Revenues $ 259,047 $ 228,424 Integrated Upstream and Gathering Revenues 323,223 252,308 Pipeline and Storage Revenues 69,237 68,750 651,507 549,482 Operating Expenses: Purchased Gas 85,606 65,337 Operation and Maintenance: Utility 59,897 55,244 Integrated Upstream and Gathering and Other 56,306 42,905 Pipeline and Storage 26,786 26,577 Property, Franchise and Other Taxes 24,764 22,056 Depreciation, Depletion and Amortization 122,025 109,370 Impairment of Assets — 141,802 375,384 463,291 Operating Income 276,123 86,191 Other Income (Expense): Other Income 8,233 7,720 Interest Expense on Long-Term Debt ( 33,513 ) ( 33,362 ) Other Interest Expense ( 9,861 ) ( 4,381 ) Income Before Income Taxes 240,982 56,168 Income Tax Expense 59,337 11,182 Net Income Available for Common Stock 181,645 44,986 EARNINGS REINVESTED IN THE BUSINESS Balance at Beginning of Period 2,012,529 1,727,326 2,194,174 1,772,312 Share Repurchases under Repurchase Plan — ( 26,993 ) Dividends on Common Stock ( 50,834 ) ( 46,671 ) Balance at December 31 $ 2,143,340 $ 1,698,648 Earnings Per Common Share: Basic: Net Income Available for Common Stock $ 1.99 $ 0.50 Diluted: Net Income Available for Common Stock $ 1.98 $ 0.49 Weighted Average Common Shares Outstanding: Used in Basic Calculation 91,171,715 90,777,446 Used in Diluted Calculation 91,962,479 91,434,741 Dividends Per Common Share: Dividends Declared $ 0.535 $ 0.515 See Notes to Condensed Consolidated Financial Statements 6 Table of Content National Fuel Gas Company Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended December 31, (Thousands of U.S. Dollars) 2025 2024 Net Income Available for Common Stock $ 181,645 $ 44,986 Other Comprehensive Income (Loss), Before Tax: Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 49,098 ( 53,516 ) Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income ( 13,274 ) ( 29,504 ) Other Comprehensive Income (Loss), Before Tax 35,824 ( 83,020 ) Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 13,146 ( 14,403 ) Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income ( 3,554 ) ( 7,940 ) Income Taxes (Benefits) – Net 9,592 ( 22,343 ) Other Comprehensive Income (Loss) 26,232 ( 60,677 ) Comprehensive Income (Loss) $ 207,877 $ ( 15,691 ) See Notes to Condensed Consolidated Financial Statements 7 Table of Content National Fuel Gas Company Consolidated Balance Sheets (Unaudited) December 31, 2025 September 30, 2025 (Thousands of U.S. Dollars) ASSETS Property, Plant and Equipment $ 15,616,382 $ 15,406,329 Less - Accumulated Depreciation, Depletion and Amortization 7,800,307 7,693,687 7,816,075 7,712,642 Current Assets Cash and Temporary Cash Investments 271,398 43,166 Receivables – Net of Allowance for Uncollectible Accounts of $ 17,504 and $ 17,099 , Respectively 265,897 180,801 Unbilled Revenue 69,645 16,219 Gas Stored Underground 18,978 33,468 Materials and Supplies - at average cost 49,862 50,545 Unrecovered Purchased Gas Costs 20,723 5,769 Other Current Assets 62,097 80,759 758,600 410,727 Other Assets Recoverable Future Taxes 92,405 89,247 Unamortized Debt Expense 5,772 6,236 Other Regulatory Assets 133,604 135,486 Deferred Charges 75,570 73,941 Other Investments 68,962 68,346 Goodwill 5,476 5,476 Prepaid Pension and Post-Retirement Benefit Costs 171,569 169,228 Fair Value of Derivative Financial Instruments 69,364 39,388 Other 8,475 8,387 631,197 595,735 Total Assets $ 9,205,872 $ 8,719,104 See Notes to Condensed Consolidated Financial Statements 8 Table of Content National Fuel Gas Company Consolidated Balance Sheets (Unaudited) December 31, 2025 September 30, 2025 (Thousands of U.S. Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Comprehensive Shareholders’ Equity Common Stock, $ 1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding – 95,017,438 Shares and 90,379,095 Shares, Respectively $ 95,017 $ 90,379 Paid in Capital 1,382,593 1,050,918 Earnings Reinvested in the Business 2,143,340 2,012,529 Accumulated Other Comprehensive Loss ( 32,990 ) ( 59,222 ) Total Comprehensive Shareholders’ Equity 3,587,960 3,094,604 Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs 2,083,892 2,382,861 Total Capitalization 5,671,852 5,477,465 Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 90,000 150,200 Current Portion of Long-Term Debt 600,000 300,000 Accounts Payable 141,674 184,046 Amounts Payable to Customers 476 968 Dividends Payable 50,834 48,353 Interest Payable on Long-Term Debt 34,644 14,393 Customer Advances 17,108 17,188 Customer Security Deposits 29,875 29,853 Other Accruals and Current Liabilities 209,202 174,689 Fair Value of Derivative Financial Instruments 155 6,074 1,173,968 925,764 Other Liabilities Deferred Income Taxes 1,274,254 1,225,262 Taxes Refundable to Customers 304,370 306,335 Cost of Removal Regulatory Liability 311,971 307,659 Other Regulatory Liabilities 120,230 121,944 Other Post-Retirement Liabilities 3,731 5,252 Asset Retirement Obligations 234,405 236,787 Other Liabilities 111,091 112,636 2,360,052 2,315,875 Commitments and Contingencies (Note 8) — — Total Capitalization and Liabilities $ 9,205,872 $ 8,719,104 See Notes to Condensed Consolidated Financial Statements 9 Table of Content National Fuel Gas Company Consolidated Statements of Cash Flows (Unaudited) Three Months Ended December 31, (Thousands of U.S. Dollars) 2025 2024 OPERATING ACTIVITIES Net Income Available for Common Stock $ 181,645 $ 44,986 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Impairment of Assets — 141,802 Depreciation, Depletion and Amortization 122,025 109,370 Deferred Income Taxes 34,277 ( 5,385 ) Stock-Based Compensation 4,094 4,705 Other 7,701 7,146 Change in: Receivables and Unbilled Revenue ( 138,565 ) ( 115,165 ) Gas Stored Underground and Materials and Supplies 15,173 10,180 Unrecovered Purchased Gas Costs ( 14,954 ) — Other Current Assets 18,581 8,814 Accounts Payable 21,412 9,703 Amounts Payable to Customers ( 492 ) ( 133 ) Customer Advances ( 80 ) ( 4,078 ) Customer Security Deposits 22 ( 174 ) Other Accruals and Current Liabilities 37,561 21,266 Other Assets ( 5,085 ) ( 3,892 ) Other Liabilities ( 8,394 ) ( 9,057 ) Net Cash Provided by Operating Activities 274,921 220,088 INVESTING ACTIVITIES Capital Expenditures ( 277,631 ) ( 240,427 ) Other ( 1,255 ) 5,878 Net Cash Used in Investing Activities ( 278,886 ) ( 234,549 ) FINANCING ACTIVITIES Changes in Notes Payable to Banks and Commercial Paper ( 60,200 ) 109,300 Shares Repurchased Under Repurchase Plan — ( 33,524 ) Dividends Paid on Common Stock ( 48,353 ) ( 46,872 ) Net Proceeds from Common Stock Sale 347,106 — Net Repurchases of Common Stock Under Stock and Benefit Plans ( 6,356 ) ( 3,971 ) Net Cash Provided by Financing Activities 232,197 24,933 Net Increase in Cash and Cash Equivalents 228,232 10,472 Cash and Cash Equivalents at October 1 43,166 38,222 Cash and Cash Equivalents at December 31 $ 271,398 $ 48,694 Supplemental Disclosure of Cash Flow Information Non-Cash Investing Activities: Non-Cash Capital Expenditures $ 70,359 $ 71,616 Non-Cash Financing Activities: Non-Cash Accrued Placement Fees from Common Stock Sale $ 8,531 $ — See Notes to Condensed Consolidated Financial Statements 10 Table of Content National Fuel Gas Company Notes to Condensed Consolidated Financial Statements (Unaudited) Note 1 – Summary of Significant Accounting Policies Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to exploration and production properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at 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. Reclassifications. As reported in the Company's 2025 Form 10-K, during the quarter ended September 30, 2025, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering. As a result, revenue and operation and maintenance expense line items on the consolidated statements of income in prior periods have been reclassified to conform to the current year presentation. Additional discussion is provided at Note 9 — Business Segment Information. Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Quarterly Report on Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2025, 2024 and 2023 that are included in the Company's 2025 Form 10-K. The consolidated financial statements for the year ended September 30, 2026 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year. The earnings for the three months ended December 31, 2025 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2026. Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility segment, earnings during the winter months normally represent a substantial part of the earnings that this business is expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 9 – Business Segment Information. Consolidated Statements of Cash Flows. The Statement of Cash Flows for the three months ended December 31, 2025 and the three months ended December 31, 2024 reconciles the net increase in cash and cash equivalents, which consists solely of cash and temporary cash investments for the periods presented. The Company did not have any restricted cash at December 31, 2025, October 1, 2025, December 31, 2024 or October 1, 2024. The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be equivalents. Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances have historically been written-off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. Starting in the quarter ended March 31, 2025, account balances are being written-off against the allowance approximately three months after the account is final billed or when it is anticipated that the receivable will not be recovered. This change in policy was initiated to better match the timing of write-offs with the recovery of uncollectible expense in rates and resulted in a one-time cumulative adjustment to the allowance during the quarter ended March 31, 2025. 11 Table of Content Activity in the allowance for uncollectible accounts for the three months ended December 31, 2025 and 2024 are as follows (in thousands): Balance at Beginning of Period Additions Charged to Costs and Expenses Discounts on Purchased Receivables Net Accounts Receivable Written-Off Balance at End of Period Three Months Ended December 31, 2025 Allowance for Uncollectible Accounts $ 17,099 $ 5,214 $ 121 $ ( 4,930 ) $ 17,504 Three Months Ended December 31, 2024 Allowance for Uncollectible Accounts $ 26,194 $ 4,605 $ 107 $ ( 2,522 ) $ 28,384 Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year as storage quantities are withdrawn and increases in the third and fourth quarters as storage quantities are replenished. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $ 2.8 million at December 31, 2025, is reduced to zero by September 30 of each year as the inventory is replenished. Property, Plant and Equipment. In the Company’s Integrated Upstream and Gathering segment, upstream property acquisition, exploration and development costs are accounted for under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center. The Company's capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $ 2.51 billion and $ 2.46 billion at December 31, 2025 and September 30, 2025, respectively. Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $ 105.7 million and $ 112.4 million at December 31, 2025 and September 30, 2025, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10 %, which is computed by applying commodity pricing (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $ 1.3 billion. The book value of the exploration and production properties exceeded the ceiling at December 31, 2024. As such, the Company recognized a non-cash, pre-tax ceiling test impairment charge in the Integrated Upstream and Gathering segment of $ 108.3 million for the quarter ended December 31, 2024. A deferred income tax benefit of $ 29.2 million related to the non-cash impairment charge was also recognized for the quarter ended December 31, 2024. In adjusting estimated future net cash flows for hedging under the ceiling test at December 31, 2025, estimated future net cash flows were increased by $ 170.7 million. The Integrated Upstream and Gathering segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting, including water disposal assets used in its upstream operations as well as gathering lines and compressor stations associated with its gathering operations, all of which are recorded at 12 Table of Content historical cost. As discussed in Note 4 – Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded in the Integrated Upstream and Gathering segment at December 31, 2024. The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility and Pipeline and Storage segments at December 31, 2025. Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the three months ended December 31, 2025 and 2024, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Three Months Ended December 31, 2025 Balance at October 1, 2025 $ 19,950 $ ( 79,172 ) $ ( 59,222 ) Other Comprehensive Gains and Losses Before Reclassifications 35,952 — 35,952 Amounts Reclassified From Other Comprehensive Loss ( 9,720 ) — ( 9,720 ) Balance at December 31, 2025 $ 46,182 $ ( 79,172 ) $ ( 32,990 ) Three Months Ended December 31, 2024 Balance at October 1, 2024 $ 55,799 $ ( 71,275 ) $ ( 15,476 ) Other Comprehensive Gains and Losses Before Reclassifications ( 39,113 ) — ( 39,113 ) Amounts Reclassified From Other Comprehensive Loss ( 21,564 ) — ( 21,564 ) Balance at December 31, 2024 $ ( 4,878 ) $ ( 71,275 ) $ ( 76,153 ) Reclassifications Out of Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the three months ended December 31, 2025 and 2024 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Income (Loss) Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) Affected Line Item in the Statement Where Net Income is Presented Three Months Ended December 31, 2025 2024 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $ 13,395 $ 29,729 Operating Revenues Foreign Currency Contracts ( 121 ) ( 225 ) Operating Revenues 13,274 29,504 Total Before Income Tax ( 3,554 ) ( 7,940 ) Income Tax Expense $ 9,720 $ 21,564 Net of Tax 13 Table of Content Other Current Assets . The components of the Company’s Other Current Assets are as follows (in thousands): At December 31, 2025 At September 30, 2025 Prepayments $ 13,854 $ 16,477 Prepaid Property and Other Taxes 13,855 13,920 Federal Income Taxes Receivable — 14,511 State Income Taxes Receivable — 489 Regulatory Assets 34,388 35,362 $ 62,097 $ 80,759 Other Accruals and Current Liabilities . The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands): At December 31, 2025 At September 30, 2025 Accrued Capital Expenditures $ 47,178 $ 45,932 Regulatory Liabilities 26,367 20,624 Reserve for Gas Replacement 2,799 — Liability for Royalty and Working Interests 36,608 28,076 Federal Income Taxes Payable 5,384 — State Income Taxes Payable 4,676 — Pennsylvania Impact Fee 19,955 14,923 Non-Qualified Benefit Plan Liability 11,567 11,567 Other 54,668 53,567 $ 209,202 $ 174,689 Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were restricted stock units and performance shares. For the quarter ended December 31, 2025, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 30 securities and four securities excluded as being antidilutive for the quarters ended December 31, 2025 and December 31, 2024, respectively. Share Repurchases. The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Stock-Based Compensation. The Company granted 137,995 performance shares during the quarter ended December 31, 2025. The weighted average fair value of such performance shares was $ 62.07 per share for the quarter ended December 31, 2025. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. The performance shares granted during the quarter ended December 31, 2025 include awards that must meet a performance goal related to relative total shareholder return over a three-year performance cycle ("TSR Performance Shares"). The performance goal related to the TSR Performance Shares over the three-year performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of other companies in a group selected by the 14 Table of Content Compensation Committee ("Report Group"). Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR Performance Shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR Performance Shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR Performance Shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. The Company granted 128,755 restricted stock units during the quarter ended December 31, 2025. The weighted average fair value of such restricted stock units was $ 77.75 per share for the quarter ended December 31, 2025. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period. Note 2 – Pending Acquisition On October 20, 2025, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with CenterPoint Energy Resources Corp. (the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of Vectren Energy Delivery of Ohio, LLC (“CenterPoint Ohio”) for an aggregate purchase price of $ 2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas. Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions. The purchase price will include a combination of $ 1.42 billion in cash and a $ 1.2 billion promissory note to be issued by the Company to the Seller at closing. The promissory note, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5 %. Permanent financing, inclusive of the amount to repay the promissory note, will consist of long-term debt and common equity, along with expected future free cash flow. In that regard, on December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $ 1.00 per share, at a price of $ 79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $ 338.6 million. In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by The Toronto-Dominion Bank (“TD Bank”), New York Branch and Wells Fargo Bank, National Association (together with TD Bank, the “Commitment Parties”), as well as a 364 -day term loan facility commitment letter supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility. The combination of both facilities fully supports any portion of the purchase price that has not been permanently financed. 15 Table of Content Note 3 – Revenue from Contracts with Customers The following tables provide a disaggregation of the Company's revenues for the three months ended December 31, 2025 and 2024, presented by type of service from each reportable segment. As reported in the Company's 2025 Form 10-K, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering. Prior year disaggregation of revenue information shown below has been restated to reflect this change in presentation. Quarter Ended December 31, 2025 (Thousands) Revenues By Type of Service Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Production of Natural Gas $ 302,460 $ — $ — $ 302,460 $ — $ — $ 302,460 Production of Crude Oil 292 — — 292 — — 292 Natural Gas Processing 164 — — 164 — — 164 Natural Gas Gathering Service 2,767 — — 2,767 — — 2,767 Natural Gas Transportation Service — 81,008 32,618 113,626 — ( 26,757 ) 86,869 Natural Gas Storage Service — 25,137 — 25,137 — ( 10,715 ) 14,422 Natural Gas Residential Sales — — 198,008 198,008 — — 198,008 Natural Gas Commercial Sales — — 27,877 27,877 — — 27,877 Natural Gas Industrial Sales — — 1,409 1,409 — ( 1 ) 1,408 Other 4,145 756 ( 1,024 ) 3,877 — ( 281 ) 3,596 Total Revenues from Contracts with Customers 309,828 106,901 258,888 675,617 — ( 37,754 ) 637,863 Alternative Revenue Programs — — 249 249 — — 249 Derivative Financial Instruments 13,395 — — 13,395 — — 13,395 Total Revenues $ 323,223 $ 106,901 $ 259,137 $ 689,261 $ — $ ( 37,754 ) $ 651,507 Quarter Ended December 31, 2024 (Thousands) Revenues By Type of Service Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Production of Natural Gas $ 217,458 $ — $ — $ 217,458 $ — $ — $ 217,458 Production of Crude Oil 515 — — 515 — — 515 Natural Gas Processing 275 — — 275 — — 275 Natural Gas Gathering Service 3,448 — — 3,448 — — 3,448 Natural Gas Transportation Service — 81,204 26,921 108,125 — ( 27,181 ) 80,944 Natural Gas Storage Service — 24,993 — 24,993 — ( 10,504 ) 14,489 Natural Gas Residential Sales — — 156,350 156,350 — — 156,350 Natural Gas Commercial Sales — — 22,243 22,243 — — 22,243 Natural Gas Industrial Sales — — 1,338 1,338 — ( 1 ) 1,337 Other 883 415 15,740 17,038 — ( 261 ) 16,777 Total Revenues from Contracts with Customers 222,579 106,612 222,592 551,783 — ( 37,947 ) 513,836 Alternative Revenue Programs — — 5,917 5,917 — — 5,917 Derivative Financial Instruments 29,729 — — 29,729 — — 29,729 Total Revenues $ 252,308 $ 106,612 $ 228,509 $ 587,429 $ — $ ( 37,947 ) $ 549,482 16 Table of Content The Company records revenue related to its derivative financial instruments in the Integrated Upstream and Gathering segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance. The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $ 174.8 million for the remainder of fiscal 2026; $ 218.7 million for fiscal 2027; $ 164.2 million for fiscal 2028; $ 130.8 million for fiscal 2029; $ 123.8 million for fiscal 2030; and $ 540.0 million thereafter. Note 4 – Fair Value Measurements The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of December 31, 2025 and September 30, 2025. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Recurring Fair Value Measures At fair value as of December 31, 2025 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 260,901 $ — $ — $ — $ 260,901 Derivative Financial Instruments: Over the Counter Swaps – Gas — 84,228 — ( 32,868 ) 51,360 Over the Counter No Cost Collars – Gas — 26,413 — ( 8,154 ) 18,259 Foreign Currency Contracts — 184 — ( 439 ) ( 255 ) Other Investments: Balanced Equity Mutual Fund 14,183 — — — 14,183 Fixed Income Mutual Fund 10,203 — — — 10,203 Total $ 285,287 $ 110,825 $ — $ ( 41,461 ) $ 354,651 Liabilities: Derivative Financial Instruments: Over the Counter Swaps – Gas $ — $ 32,868 $ — $ ( 32,868 ) $ — Over the Counter No Cost Collars – Gas — 8,154 — ( 8,154 ) — Foreign Currency Contracts — 594 — ( 439 ) 155 Total $ — $ 41,616 $ — $ ( 41,461 ) $ 155 Total Net Assets/(Liabilities) $ 285,287 $ 69,209 $ — $ — $ 354,496 17 Table of Content Recurring Fair Value Measures At fair value as of September 30, 2025 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 30,551 $ — $ — $ — $ 30,551 Derivative Financial Instruments: Over the Counter Swaps – Gas — 62,190 — ( 33,615 ) 28,575 Over the Counter No Cost Collars – Gas — 24,149 — ( 12,805 ) 11,344 Foreign Currency Contracts — 144 — ( 675 ) ( 531 ) Other Investments: Balanced Equity Mutual Fund 13,786 — — — 13,786 Fixed Income Mutual Fund 10,082 — — — 10,082 Total $ 54,419 $ 86,483 $ — $ ( 47,095 ) $ 93,807 Liabilities: Derivative Financial Instruments: Over the Counter Swaps – Gas $ — $ 34,169 $ — $ ( 33,615 ) $ 554 Over the Counter No Cost Collars – Gas — 18,036 — ( 12,805 ) 5,231 Foreign Currency Contracts — 893 — ( 675 ) 218 Total $ — $ 53,098 $ — $ ( 47,095 ) $ 6,003 Total Net Assets/(Liabilities) $ 54,419 $ 33,385 $ — $ — $ 87,804 (1) Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet. The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of December 31, 2025 and 2024 (in thousands): Impairments Nonrecurring Fair Value Measures Quarter Ended December 31, Segment Date of Measurement Fair Value 2025 2024 Impairment of Assets: Water Disposal Assets Integrated Upstream and Gathering December 31, 2024 $ 12,880 $ — $ 33,453 In exploring the potential sale of certain water disposal assets during the quarter ended December 31, 2024, the Company determined that the fair market value of such assets was less than the recorded net book value resulting in an impairment charge that reduced the net book value to fair market value. These assets are used to dispose of water from operations in the Integrated Upstream and Gathering segment. Derivative Financial Instruments The derivative financial instruments reported in Level 2 at December 31, 2025 and September 30, 2025 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Integrated Upstream and Gathering segment. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At December 31, 2025, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates. 18 Table of Content Note 5 – Financial Instruments Long-Term Debt. The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands): December 31, 2025 September 30, 2025 Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt $ 2,683,892 $ 2,695,409 $ 2,682,861 $ 2,696,145 The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries or SOFR for the risk-free component and company specific credit spread information – generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2. Other Financial Instruments. Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value. Other Investments. The components of the Company's Other Investments are as follows (in thousands): At December 31, 2025 At September 30, 2025 Life Insurance Contracts $ 44,576 $ 44,478 Equity Mutual Fund 14,183 13,786 Fixed Income Mutual Fund 10,203 10,082 $ 68,962 $ 68,346 Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction and for various benefit obligations the Company has to certain employees. Derivative Financial Instruments. The Company uses derivative financial instruments to manage commodity price risk in the Integrated Upstream and Gathering segment. The Company enters into over-the-counter no cost collar and swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Integrated Upstream and Gathering segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges and foreign currency forward contracts do not typically exceed 5 years. The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at December 31, 2025 and September 30, 2025. Cash Flow Hedges For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. 19 Table of Content As of December 31, 2025, the Company had 403.1 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding. As of December 31, 2025, the Company was hedging a total of $ 41.0 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts. As of December 31, 2025, the Company had $ 46.2 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $ 45.9 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended December 31, 2025 and 2024 (Thousands of Dollars) Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended December 31, Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended December 31, 2025 2024 2025 2024 Commodity Contracts $ 48,880 $ ( 51,909 ) Operating Revenue $ 13,395 $ 29,729 Foreign Currency Contracts 218 ( 1,607 ) Operating Revenue ( 121 ) ( 225 ) Total $ 49,098 $ ( 53,516 ) $ 13,274 $ 29,504 Credit Risk The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with seventeen counterparties of which sixteen are in a net gain position. On average, the Company had $ 4.3 million of credit exposure per counterparty in a gain position at December 31, 2025. The maximum credit exposure per counterparty in a gain position at December 31, 2025 was $ 10.8 million. As of December 31, 2025, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral. Certain counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit that could be extended to the Company when it is in a derivative financial liability position would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At December 31, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $ 0.2 million according to the Company's internal model (discussed in Note 4 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at December 31, 2025. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits. 20 Table of Content The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Note 6 – Income Taxes The effective tax rates for the quarters ended December 31, 2025 and December 31, 2024 were 24.6 % and 19.9 %, respectively. The increase in the quarterly effective income tax rate was primarily driven by the impact of the impairments of exploration and production properties under the ceiling test and other operational assets recorded during the quarter ended December 31, 2024, which resulted in a smaller income tax expense on income before income taxes during the quarter ended December 31, 2024. Note 7 – Capitalization Summary of Changes in Common Stock Equity Common Stock Paid In Capital Earnings Reinvested in the Business Accumulated Other Comprehensive Income (Loss) Shares Amount (Thousands) Balance at October 1, 2025 90,379 $ 90,379 $ 1,050,918 $ 2,012,529 $ ( 59,222 ) Net Income Available for Common Stock 181,645 Dividends Declared on Common Stock ($ 0.535 Per Share) ( 50,834 ) Other Comprehensive Income, Net of Tax 26,232 Share-Based Payment Expense (1) 3,427 Common Stock Issued from Sale of Common Stock 4,403 4,403 334,173 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 235 235 ( 5,925 ) Balance at December 31, 2025 95,017 $ 95,017 $ 1,382,593 $ 2,143,340 $ ( 32,990 ) Balance at October 1, 2024 91,006 $ 91,006 $ 1,045,487 $ 1,727,326 $ ( 15,476 ) Net Income Available for Common Stock 44,986 Dividends Declared on Common Stock ($ 0.515 Per Share) ( 46,671 ) Other Comprehensive Loss, Net of Tax ( 60,677 ) Share-Based Payment Expense (1) 4,090 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 156 156 ( 3,511 ) Share Repurchases Under Repurchase Plan ( 549 ) $ ( 549 ) $ ( 6,361 ) $ ( 26,993 ) Balance at December 31, 2024 90,613 $ 90,613 $ 1,039,705 $ 1,698,648 $ ( 76,153 ) (1) Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits. 21 Table of Content Common Stock. Common stock share activity during the three months ended December 31, 2025 consisted of the following items: Three Months Ended December 31, 2025 Vesting of Restricted Stock Units 138,643 Vesting of Performance Shares 167,241 Issuance of Common Stock Pursuant to the Company's Non-Employee Director Equity Compensation Plan and Deferred Compensation Plan for Directors and Officers 7,368 Shares Tendered to Pay Withholding Taxes on Stock-Based Compensation Awards (1) ( 77,422 ) Common Stock Issued Under Stock and Benefit Plans 235,830 Common Stock Issued from Sale of Common Stock 4,402,513 Total Common Stock Issued During the Three Months Ended December 31, 2025 4,638,343 (1) The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. On December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $ 1.00 per share, at a price of $ 79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $ 338.6 million. The proceeds of this issuance were used for general corporate purposes, including to fund a portion of the purchase price of the Company's previously announced acquisition of CenterPoint Energy Resources Corp.'s Ohio regulated gas utility business. Refer to Note 2 – Pending Acquisition for further discussion. Current Portion of Long-Term Debt. The Current Portion of Long-Term Debt at December 31, 2025 consisted of a $ 300.0 million long-term delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and $ 300.0 million of 5.50 % notes with a maturity date in October 2026. The Current Portion of Long-Term Debt at September 30, 2025 consisted of the aforementioned $ 300.0 million long-term delayed draw term loan with a maturity date in February 2026. Delayed Draw Term Loan. On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. As of January 22, 2026, the Company repaid the $ 300.0 million drawn under the Term Loan Agreement and the agreement was therefore terminated. The Term Loan Agreement provided a $ 300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company had the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $ 300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $ 299.4 million. Borrowings under the Term Loan Agreement bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10 %, plus a spread of 1.375 %. Note 8 – Commitments and Contingencies Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At December 31, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $ 2.9 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at December 31, 2025. The Company has a regulatory liability of $ 1.5 million related to environmental clean-up costs at December 31, 2025 and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company. Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal 22 Table of Content course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time. Note 9 – Business Segment Information The Company reports financial results for three segments: Integrated Upstream and Gathering, Pipeline and Storage, and Utility. The division of the Company’s operations into reportable segments is based on a combination of factors including differences in products and services as well as regulatory environments. As reported in the Company's 2025 Form 10-K, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering. Prior year segment information shown below has been recast to reflect this change in presentation. The Company's Chief Executive Officer, its Chief Operating Decision Maker (CODM), evaluates segment performance primarily using earnings attributable to the Company. External reporting is consistent with the internal financial reports used by the CODM to regularly assess performance of the business, make operating decisions and allocate resources. The Integrated Upstream and Gathering segment is composed of the operations of Seneca and Midstream Company. Seneca is engaged in the exploration for and development of natural gas reserves in the Appalachian region of the United States. Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region, primarily providing gathering services to Seneca. The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers, exploration and production companies (including Seneca) and pipeline companies serving northeastern United States markets. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for utilities (including Distribution Corporation), natural gas marketers and exploration and production companies (including Seneca) from producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points with access to additional markets in the northeastern United States and Canada. The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania. The data presented in the tables below reflects financial information for the segments and reconciles to consolidated amounts. As stated in the 2025 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, when applicable. If discontinued operations are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation or in the basis of measuring segment profit or loss from those used in the Company’s 2025 Form 10-K. A listing of segment assets at December 31, 2025 and December 31, 2024 is shown in the tables below. 23 Table of Content Three Months Ended December 31, 2025 Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other (4) Corporate and Intersegment Eliminations (4) Total Consolidated (Thousands) Revenue from External Customers (1) $ 323,223 $ 69,237 $ 259,047 $ 651,507 $ — $ — $ 651,507 Intersegment Revenues — 37,664 90 37,754 — ( 37,754 ) — Total Revenues 323,223 106,901 259,137 689,261 — ( 37,754 ) 651,507 Operation and Maintenance Expense (2) : Upstream General and Administrative Expense 19,406 — — 19,406 — ( 63 ) 19,343 Lease Operating Expense 16,826 — — 16,826 — ( 789 ) 16,037 Gathering Operation and Maintenance Expense 10,388 — — 10,388 — ( 69 ) 10,319 All Other Operation and Maintenance Expense 3,378 27,263 60,997 91,638 — 5,652 97,290 Purchased Gas Expense (2) — — 122,285 122,285 — ( 36,679 ) 85,606 Depreciation, Depletion and Amortization Expense (2) 84,263 19,102 18,479 121,844 — 181 122,025 Impairment of Assets (Significant Non-Cash Item) (2) — — — — — — — Interest Expense (2) 16,133 11,801 11,606 39,540 136 3,698 43,374 Interest Income ( 193 ) ( 964 ) ( 1,039 ) ( 2,196 ) ( 10 ) ( 571 ) ( 2,777 ) Income Tax Expense (Benefit) (2) 44,111 10,366 7,335 61,812 ( 37 ) ( 2,438 ) 59,337 Other Expense (Income) Items (3) 4,864 8,114 5,384 18,362 33 913 19,308 Segment Profit: Net Income (Loss) $ 124,047 $ 31,219 $ 34,090 $ 189,356 $ ( 122 ) $ ( 7,589 ) $ 181,645 Expenditures for Additions to Long-Lived Assets $ 141,849 $ 37,602 $ 43,094 $ 222,545 $ — $ 176 $ 222,721 Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other (4) Corporate and Intersegment Eliminations (4) Total Consolidated (Thousands) Segment Assets: At December 31, 2025 $ 3,925,191 $ 2,504,541 $ 2,645,957 $ 9,075,689 $ 8,565 $ 121,618 $ 9,205,872 At September 30, 2025 $ 3,701,646 $ 2,412,747 $ 2,534,289 $ 8,648,682 $ 8,704 $ 61,718 $ 8,719,104 Three Months Ended December 31, 2024 Integrated Upstream and Gathering Pipeline and Storage Utility Total Reportable Segments All Other (4) Corporate and Intersegment Eliminations (4) Total Consolidated (Thousands) Revenue from External Customers (1) $ 252,308 $ 68,750 $ 228,424 $ 549,482 $ — $ — $ 549,482 Intersegment Revenues — 37,862 85 37,947 — ( 37,947 ) — Total Revenues 252,308 106,612 228,509 587,429 — ( 37,947 ) 549,482 Operation and Maintenance Expense (2) : Upstream General and Administrative Expense 19,326 — — 19,326 — ( 59 ) 19,267 Lease Operating Expense 10,651 — — 10,651 — ( 1,587 ) 9,064 Gathering Operation and Maintenance Expense 6,735 — — 6,735 — ( 65 ) 6,670 All Other Operation and Maintenance Expense 3,867 27,034 56,260 87,161 — 2,564 89,725 Purchased Gas Expense (2) — — 101,473 101,473 — ( 36,136 ) 65,337 Depreciation, Depletion and Amortization Expense (2) 73,819 18,585 16,827 109,231 — 139 109,370 Impairment of Assets (Significant Non-Cash Item) (2) 141,802 — — 141,802 — — 141,802 Interest Expense (2) 19,410 11,729 10,716 41,855 116 ( 4,228 ) 37,743 Interest Income ( 679 ) ( 2,006 ) ( 648 ) ( 3,333 ) — 1,650 ( 1,683 ) Income Tax Expense (Benefit) (2) ( 6,451 ) 11,177 7,022 11,748 ( 59 ) ( 507 ) 11,182 Other Expense (Income) Items (3) 3,460 7,639 4,360 15,459 136 424 16,019 Segment Profit: Net Income (Loss) $ ( 19,632 ) $ 32,454 $ 32,499 $ 45,321 $ ( 193 ) $ ( 142 ) $ 44,986 Expenditures for Additions to Long-Lived Assets $ 135,629 $ 19,792 $ 36,430 $ 191,851 $ — $ 204 $ 192,055 (1) All Revenue from External Customers originated in the United States. (2) The Company considers this line to be a significant expense. (3) Consists of Property, Franchise and Other Taxes, Non-Service Pension and Post-Retirement Benefits Costs (Credits), Other (Income) Deductions, and Purchased Gas Expense for the Pipeline and Storage Segment. (4) Corporate and All Other categories primarily represent other non-segment business activities and eliminating entries. 24 Table of Content Note 10 – Retirement Plan and Other Post-Retirement Benefits Components of Net Periodic Benefit Cost (in thousands): Retirement Plan Other Post-Retirement Benefits Three Months Ended December 31, 2025 2024 2025 2024 Service Cost $ 861 $ 1,023 $ 105 $ 130 Interest Cost 8,944 9,223 3,836 3,625 Expected Return on Plan Assets ( 14,710 ) ( 14,647 ) ( 7,374 ) ( 6,536 ) Amortization of Prior Service Cost (Credit) 63 76 ( 65 ) ( 107 ) Amortization of (Gains) Losses 2,421 1,620 152 9 Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) ( 98 ) ( 165 ) ( 148 ) ( 727 ) Net Periodic Benefit Cost (Income) $ ( 2,519 ) $ ( 2,870 ) $ ( 3,494 ) $ ( 3,606 ) (1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months. The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income. Employer Contributions. The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026. Note 11 – Regulatory Matters New York Jurisdiction Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on December 19, 2024 with rates effective January 1, 2025 (“2024 Rate Order”). The 2024 Rate Order authorizes a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. It also reflects a return on equity of 9.7 % and authorized a revenue requirement increase of $ 57.3 million in fiscal 2025, an additional revenue requirement increase of $ 15.8 million in fiscal 2026, and an additional revenue requirement increase of $ 12.7 million in fiscal 2027. These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan. The revenue requirement for each year of the three-year plan has been reduced by $ 14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits. Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals. It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA. Pennsylvania Jurisdiction Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC in an order issued on June 15, 2023 with rates effective August 1, 2023 (“2023 Rate Order”). The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $ 23 million and authorized a new weather normalization adjustment mechanism. On January 28, 2026, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $ 19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make 25 Table of Content permanent its weather normalization adjustment mechanism. The Company is also proposing reactivation of the OPEB surcredit (Rider I) to refund $ 7.2 million for customer bill relief. The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC. On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge (“DSIC”) to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. During the quarter ended December 31, 2025, Distribution Corporation recovered $ 1.1 million from customers. The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing. FERC Jurisdiction Supply Corporation’s rate settlement was approved June 11, 2024, with rates effective February 1, 2024, and provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file. On March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $ 0.5 million. Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031.