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 June 30, Nine Months Ended June 30, (Thousands of U.S. Dollars, Except Per Common Share Amounts) 2026 2025 2026 2025 INCOME Operating Revenues: Utility Revenues $ 165,422 $ 157,446 $ 850,258 $ 729,445 Integrated Upstream and Gathering Revenues 302,516 306,402 984,561 873,901 Pipeline and Storage Revenues 69,559 67,982 212,558 207,916 537,497 531,830 2,047,377 1,811,262 Operating Expenses: Purchased Gas 29,878 27,986 323,335 228,661 Operation and Maintenance: Utility 60,592 56,053 187,549 174,744 Integrated Upstream and Gathering and Other 63,534 47,137 180,904 137,312 Pipeline and Storage 31,013 29,814 88,459 86,544 Property, Franchise and Other Taxes 22,482 24,180 72,519 71,450 Depreciation, Depletion and Amortization 121,058 116,408 362,412 337,055 Impairment of Assets — — — 141,802 328,557 301,578 1,215,178 1,177,568 Operating Income 208,940 230,252 832,199 633,694 Other Income (Expense): Other Income (Deductions) 11,866 8,534 37,100 31,486 Interest Expense on Long-Term Debt ( 33,181 ) ( 34,333 ) ( 96,776 ) ( 107,356 ) Other Interest Expense ( 2,831 ) ( 3,556 ) ( 16,344 ) ( 13,033 ) Income Before Income Taxes 184,794 200,897 756,179 544,791 Income Tax Expense 46,173 51,079 188,245 133,629 Net Income Available for Common Stock 138,621 149,818 567,934 411,162 EARNINGS REINVESTED IN THE BUSINESS Balance at Beginning of Period 2,340,168 1,855,366 2,012,529 1,727,326 2,478,789 2,005,184 2,580,463 2,138,488 Share Repurchases under Repurchase Plan — ( 3,311 ) — ( 43,389 ) Dividends on Common Stock ( 52,745 ) ( 48,340 ) ( 154,419 ) ( 141,566 ) Balance at June 30 $ 2,426,044 $ 1,953,533 $ 2,426,044 $ 1,953,533 Earnings Per Common Share: Basic: Net Income Available for Common Stock $ 1.46 $ 1.66 $ 6.06 $ 4.54 Diluted: Net Income Available for Common Stock $ 1.45 $ 1.64 $ 6.01 $ 4.51 Weighted Average Common Shares Outstanding: Used in Basic Calculation 95,034,935 90,358,018 93,730,191 90,546,228 Used in Diluted Calculation 95,736,482 91,139,556 94,445,771 91,247,547 Dividends Per Common Share: Dividends Declared $ 0.555 $ 0.535 $ 1.625 $ 1.565 See Notes to Condensed Consolidated Financial Statements 6 Table of Content National Fuel Gas Company Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended June 30, Nine Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 2026 2025 Net Income Available for Common Stock $ 138,621 $ 149,818 $ 567,934 $ 411,162 Other Comprehensive Income (Loss), Before Tax: Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 69,729 148,888 116,637 ( 113,675 ) Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income ( 58,170 ) ( 2,258 ) ( 22,684 ) ( 23,601 ) Other Comprehensive Income (Loss), Before Tax 11,559 146,630 93,953 ( 137,276 ) Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 18,669 40,070 31,229 ( 30,593 ) Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments in Net Income ( 15,575 ) ( 608 ) ( 6,074 ) ( 6,352 ) Income Taxes (Benefits) – Net 3,094 39,462 25,155 ( 36,945 ) Other Comprehensive Income (Loss) 8,465 107,168 68,798 ( 100,331 ) Comprehensive Income $ 147,086 $ 256,986 $ 636,732 $ 310,831 See Notes to Condensed Consolidated Financial Statements 7 Table of Content National Fuel Gas Company Consolidated Balance Sheets (Unaudited) June 30, 2026 September 30, 2025 (Thousands of U.S. Dollars) ASSETS Property, Plant and Equipment $ 16,097,040 $ 15,406,329 Less - Accumulated Depreciation, Depletion and Amortization 8,002,972 7,693,687 8,094,068 7,712,642 Current Assets Cash and Temporary Cash Investments 1,235,178 43,166 Receivables – Net of Allowance for Uncollectible Accounts of $ 23,611 and $ 17,099 , Respectively 227,913 180,801 Unbilled Revenue 16,916 16,219 Gas Stored Underground 12,838 33,468 Materials and Supplies - at average cost 51,232 50,545 Unrecovered Purchased Gas Costs 2,136 5,769 Other Current Assets 67,660 80,759 1,613,873 410,727 Other Assets Recoverable Future Taxes 98,996 89,247 Unamortized Debt Expense 5,821 6,236 Other Regulatory Assets 123,464 135,486 Deferred Charges 117,345 73,941 Other Investments 66,946 68,346 Goodwill 5,476 5,476 Prepaid Pension and Post-Retirement Benefit Costs 187,737 169,228 Fair Value of Derivative Financial Instruments 127,630 39,388 Other 10,411 8,387 743,826 595,735 Total Assets $ 10,451,767 $ 8,719,104 See Notes to Condensed Consolidated Financial Statements 8 Table of Content National Fuel Gas Company Consolidated Balance Sheets (Unaudited) June 30, 2026 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 – 95,035,675 Shares and 90,379,095 Shares, Respectively $ 95,036 $ 90,379 Paid in Capital 1,393,023 1,050,918 Earnings Reinvested in the Business 2,426,044 2,012,529 Accumulated Other Comprehensive Income (Loss) 9,576 ( 59,222 ) Total Comprehensive Shareholders’ Equity 3,923,679 3,094,604 Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs 3,567,401 2,382,861 Total Capitalization 7,491,080 5,477,465 Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper — 150,200 Current Portion of Long-Term Debt — 300,000 Accounts Payable 146,096 184,046 Amounts Payable to Customers 752 968 Dividends Payable 52,745 48,353 Interest Payable on Long-Term Debt 34,475 14,393 Customer Advances — 17,188 Customer Security Deposits 27,723 29,853 Other Accruals and Current Liabilities 241,398 174,689 Fair Value of Derivative Financial Instruments 1,027 6,074 504,216 925,764 Other Liabilities Deferred Income Taxes 1,353,287 1,225,262 Taxes Refundable to Customers 302,149 306,335 Cost of Removal Regulatory Liability 319,921 307,659 Other Regulatory Liabilities 116,935 121,944 Other Post-Retirement Liabilities 3,768 5,252 Asset Retirement Obligations 223,021 236,787 Other Liabilities 137,390 112,636 2,456,471 2,315,875 Commitments and Contingencies (Note 8) — — Total Capitalization and Liabilities $ 10,451,767 $ 8,719,104 See Notes to Condensed Consolidated Financial Statements 9 Table of Content National Fuel Gas Company Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended June 30, (Thousands of U.S. Dollars) 2026 2025 OPERATING ACTIVITIES Net Income Available for Common Stock $ 567,934 $ 411,162 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Impairment of Assets — 141,802 Depreciation, Depletion and Amortization 362,412 337,055 Deferred Income Taxes 88,936 60,754 Premiums Paid on Early Redemption of Debt 413 2,385 Stock-Based Compensation 14,801 15,721 Other 17,695 19,296 Change in: Receivables and Unbilled Revenue ( 47,233 ) ( 95,254 ) Gas Stored Underground and Materials and Supplies 19,943 18,803 Unrecovered Purchased Gas Costs 3,633 ( 2,903 ) Other Current Assets 13,054 28,038 Accounts Payable 2 1,744 Amounts Payable to Customers ( 216 ) ( 18,445 ) Customer Advances ( 17,188 ) ( 19,373 ) Customer Security Deposits ( 2,130 ) ( 7,526 ) Other Accruals and Current Liabilities 57,892 44,283 Other Assets ( 15,919 ) ( 35,348 ) Other Liabilities ( 29,494 ) ( 39,918 ) Net Cash Provided by Operating Activities 1,034,535 862,276 INVESTING ACTIVITIES Capital Expenditures ( 764,515 ) ( 627,316 ) Other 10,302 9,352 Net Cash Used in Investing Activities ( 754,213 ) ( 617,964 ) FINANCING ACTIVITIES Changes in Notes Payable to Banks and Commercial Paper ( 150,200 ) ( 29,200 ) Net Proceeds from Issuance of Long-Term Debt 1,481,195 988,731 Shares Repurchased Under Repurchase Plan — ( 54,430 ) Reduction of Long-Term Debt ( 601,239 ) ( 1,004,086 ) Dividends Paid on Common Stock ( 150,027 ) ( 140,098 ) Net Proceeds from Common Stock Sale 338,396 — Net Repurchases of Common Stock Under Stock and Benefit Plans ( 6,435 ) ( 4,134 ) Net Cash Provided by (Used in) Financing Activities 911,690 ( 243,217 ) Net Increase in Cash and Cash Equivalents 1,192,012 1,095 Cash and Cash Equivalents at October 1 43,166 38,222 Cash and Cash Equivalents at June 30 $ 1,235,178 $ 39,317 Supplemental Disclosure of Cash Flow Information Non-Cash Investing Activities: Non-Cash Capital Expenditures $ 105,293 $ 88,627 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 nine months ended June 30, 2026 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 nine months ended June 30, 2026 and nine months ended June 30, 2025 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 June 30, 2026, October 1, 2025, June 30, 2025 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 cash equivalents. Cash and Temporary Cash Investments at June 30, 2026 includes cash proceeds from the June 2026 debt issuance reported as a financing activity in the Statement of Cash Flows. The debt issuance is discussed in more detail in Note 7 – Capitalization. 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 nine months ended June 30, 2026 and 2025 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 Nine Months Ended June 30, 2026 Allowance for Uncollectible Accounts $ 17,099 $ 14,903 $ 912 $ ( 9,303 ) $ 23,611 Nine Months Ended June 30, 2025 Allowance for Uncollectible Accounts $ 26,194 $ 17,758 $ 807 $ ( 21,027 ) $ 23,732 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 $ 19.8 million at June 30, 2026, 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 $ 2.64 billion and $ 2.46 billion at June 30, 2026 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 $ 112.5 million and $ 112.4 million at June 30, 2026 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 June 30, 2026, the ceiling exceeded the book value of the exploration and production properties by approximately $ 1.4 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 June 30, 2026, estimated future net cash flows were increased by $ 67.8 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 June 30, 2026. Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the nine months ended June 30, 2026 and 2025, 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 June 30, 2026 Balance at April 1, 2026 $ 80,283 $ ( 79,172 ) $ 1,111 Other Comprehensive Gains and Losses Before Reclassifications 51,060 — 51,060 Amounts Reclassified From Other Comprehensive Income ( 42,595 ) — ( 42,595 ) Balance at June 30, 2026 $ 88,748 $ ( 79,172 ) $ 9,576 Nine Months Ended June 30, 2026 Balance at October 1, 2025 $ 19,950 $ ( 79,172 ) $ ( 59,222 ) Other Comprehensive Gains and Losses Before Reclassifications 85,408 — 85,408 Amounts Reclassified From Other Comprehensive Income ( 16,610 ) — ( 16,610 ) Balance at June 30, 2026 $ 88,748 $ ( 79,172 ) $ 9,576 Three Months Ended June 30, 2025 Balance at April 1, 2025 $ ( 151,700 ) $ ( 71,275 ) $ ( 222,975 ) Other Comprehensive Gains and Losses Before Reclassifications 108,818 — 108,818 Amounts Reclassified From Other Comprehensive Loss ( 1,650 ) — ( 1,650 ) Balance at June 30, 2025 $ ( 44,532 ) $ ( 71,275 ) $ ( 115,807 ) Nine Months Ended June 30, 2025 Balance at October 1, 2024 $ 55,799 $ ( 71,275 ) $ ( 15,476 ) Other Comprehensive Gains and Losses Before Reclassifications ( 83,082 ) — ( 83,082 ) Amounts Reclassified From Other Comprehensive Loss ( 17,249 ) — ( 17,249 ) Balance at June 30, 2025 $ ( 44,532 ) $ ( 71,275 ) $ ( 115,807 ) 13 Table of Content Reclassifications Out of Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the nine months ended June 30, 2026 and 2025 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 June 30, Nine Months Ended June 30, 2026 2025 2026 2025 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $ 58,258 $ 2,515 $ 22,959 $ 24,409 Operating Revenues Foreign Currency Contracts ( 88 ) ( 257 ) ( 275 ) ( 808 ) Operating Revenues 58,170 2,258 22,684 23,601 Total Before Income Tax ( 15,575 ) ( 608 ) ( 6,074 ) ( 6,352 ) Income Tax Expense $ 42,595 $ 1,650 $ 16,610 $ 17,249 Net of Tax Other Current Assets . The components of the Company’s Other Current Assets are as follows (in thousands): At June 30, 2026 At September 30, 2025 Prepayments $ 23,159 $ 16,477 Prepaid Property and Other Taxes 10,586 13,920 Federal Income Taxes Receivable — 14,511 State Income Taxes Receivable — 489 Regulatory Assets 33,915 35,362 $ 67,660 $ 80,759 Other Accruals and Current Liabilities . The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands): At June 30, 2026 At September 30, 2025 Accrued Capital Expenditures $ 63,908 $ 45,932 Regulatory Liabilities 17,737 20,624 Reserve for Gas Replacement 19,793 — Liability for Royalty and Working Interests 27,038 28,076 Federal Income Taxes Payable 25,631 — State Income Taxes Payable 9,628 — Pennsylvania Impact Fee 7,479 14,923 Non-Qualified Benefit Plan Liability 11,567 11,567 Other 58,617 53,567 $ 241,398 $ 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 and nine months ended June 30, 2026, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these 14 Table of Content 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 zero securities and 3,055 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2026, respectively. There were 1,126 securities and 1,097 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2025. 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 nine months ended June 30, 2026. The weighted average fair value of such performance shares was $ 62.07 per share for the nine months ended June 30, 2026. 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 nine months ended June 30, 2026 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 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 134,755 restricted stock units during the nine months ended June 30, 2026. The weighted average fair value of such restricted stock units was $ 77.50 per share for the nine months ended June 30, 2026. 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 on October 1, 2026. 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, is expected to 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 $ 338.4 million. Furthermore, as discussed in Note 7 – Capitalization, the Company issued $ 1.5 billion of long- 15 Table of Content term debt on June 10, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $ 1,481.2 million. After redeeming certain notes scheduled to mature on October 1, 2026 with a portion of the net proceeds, the Company invested the remaining net proceeds from the debt issuance in temporary cash investments and expects to use that cash to fund a substantial portion of the purchase price at closing. 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 was designed to fully support any portion of the purchase price that had not been permanently financed. Given the permanent financing in place, as mentioned in the previous paragraph, the Company terminated the 364 -day term loan facility commitment letter effective June 10, 2026. The remaining commitment under the senior unsecured bridge loan facility commitment letter is currently $ 1.10 billion. Note 3 – Revenue from Contracts with Customers The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2026 and 2025, 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 June 30, 2026 (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 $ 235,036 $ — $ — $ 235,036 $ — $ — $ 235,036 Production of Crude Oil ( 146 ) — — ( 146 ) — — ( 146 ) Natural Gas Processing 245 — — 245 — — 245 Natural Gas Gathering Service 3,723 — — 3,723 — — 3,723 Natural Gas Transportation Service — 80,867 20,561 101,428 — ( 26,095 ) 75,333 Natural Gas Storage Service — 25,699 — 25,699 — ( 10,735 ) 14,964 Natural Gas Residential Sales — — 121,502 121,502 — — 121,502 Natural Gas Commercial Sales — — 14,129 14,129 — — 14,129 Natural Gas Industrial Sales — — 885 885 — ( 1 ) 884 Other 5,400 ( 25 ) 3,158 8,533 — ( 229 ) 8,304 Total Revenues from Contracts with Customers 244,258 106,541 160,235 511,034 — ( 37,060 ) 473,974 Alternative Revenue Programs — — 5,265 5,265 — — 5,265 Derivative Financial Instruments 58,258 — — 58,258 — — 58,258 Total Revenues $ 302,516 $ 106,541 $ 165,500 $ 574,557 $ — $ ( 37,060 ) $ 537,497 16 Table of Content Nine Months Ended June 30, 2026 (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 $ 937,713 $ — $ — $ 937,713 $ — $ — $ 937,713 Production of Crude Oil 585 — — 585 — — 585 Natural Gas Processing 609 — — 609 — — 609 Natural Gas Gathering Service 9,113 — — 9,113 — — 9,113 Natural Gas Transportation Service — 244,923 101,757 346,680 — ( 79,501 ) 267,179 Natural Gas Storage Service — 76,513 — 76,513 — ( 32,341 ) 44,172 Natural Gas Residential Sales — — 642,481 642,481 — — 642,481 Natural Gas Commercial Sales — — 92,893 92,893 — — 92,893 Natural Gas Industrial Sales — — 4,852 4,852 — ( 5 ) 4,847 Other 13,582 3,469 5,022 22,073 — ( 794 ) 21,279 Total Revenues from Contracts with Customers 961,602 324,905 847,005 2,133,512 — ( 112,641 ) 2,020,871 Alternative Revenue Programs — — 3,547 3,547 — — 3,547 Derivative Financial Instruments 22,959 — — 22,959 — — 22,959 Total Revenues $ 984,561 $ 324,905 $ 850,552 $ 2,160,018 $ — $ ( 112,641 ) $ 2,047,377 Quarter Ended June 30, 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 $ 300,137 $ — $ — $ 300,137 $ — $ — $ 300,137 Production of Crude Oil 434 — — 434 — — 434 Natural Gas Processing 267 — — 267 — — 267 Natural Gas Gathering Service 2,519 — — 2,519 — — 2,519 Natural Gas Transportation Service — 80,235 21,639 101,874 — ( 26,845 ) 75,029 Natural Gas Storage Service — 25,028 — 25,028 — ( 10,604 ) 14,424 Natural Gas Residential Sales — — 118,551 118,551 — — 118,551 Natural Gas Commercial Sales — — 15,349 15,349 — — 15,349 Natural Gas Industrial Sales — — 732 732 — ( 1 ) 731 Other 530 316 ( 633 ) 213 — ( 224 ) ( 11 ) Total Revenues from Contracts with Customers 303,887 105,579 155,638 565,104 — ( 37,674 ) 527,430 Alternative Revenue Programs — — 1,885 1,885 — — 1,885 Derivative Financial Instruments 2,515 — — 2,515 — — 2,515 Total Revenues $ 306,402 $ 105,579 $ 157,523 $ 569,504 $ — $ ( 37,674 ) $ 531,830 17 Table of Content Nine Months Ended June 30, 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 $ 836,000 $ — $ — $ 836,000 $ — $ — $ 836,000 Production of Crude Oil 1,341 — — 1,341 — — 1,341 Natural Gas Processing 881 — — 881 — — 881 Natural Gas Gathering Service 9,200 — — 9,200 — — 9,200 Natural Gas Transportation Service — 243,921 93,815 337,736 — ( 81,564 ) 256,172 Natural Gas Storage Service — 75,309 — 75,309 — ( 31,799 ) 43,510 Natural Gas Residential Sales — — 532,001 532,001 — — 532,001 Natural Gas Commercial Sales — — 77,194 77,194 — — 77,194 Natural Gas Industrial Sales — — 4,007 4,007 — ( 4 ) 4,003 Other 2,070 2,535 12,507 17,112 — ( 761 ) 16,351 Total Revenues from Contracts with Customers 849,492 321,765 719,524 1,890,781 — ( 114,128 ) 1,776,653 Alternative Revenue Programs — — 10,200 10,200 — — 10,200 Derivative Financial Instruments 24,409 — — 24,409 — — 24,409 Total Revenues $ 873,901 $ 321,765 $ 729,724 $ 1,925,390 $ — $ ( 114,128 ) $ 1,811,262 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: $ 59.1 million for the remainder of fiscal 2026; $ 243.9 million for fiscal 2027; $ 198.5 million for fiscal 2028; $ 148.1 million for fiscal 2029; $ 139.4 million for fiscal 2030; and $ 783.4 million for years subsequent to fiscal 2030. 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. 18 Table of Content 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 June 30, 2026 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 June 30, 2026 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 1,231,017 $ — $ — $ — $ 1,231,017 Derivative Financial Instruments: Over the Counter Swaps – Gas — 115,548 — ( 14,890 ) 100,658 Over the Counter No Cost Collars – Gas — 27,756 — — 27,756 Foreign Currency Contracts — 30 — ( 814 ) ( 784 ) Other Investments: Balanced Equity Mutual Fund 15,093 — — — 15,093 Fixed Income Mutual Fund 10,292 — — — 10,292 Total $ 1,256,402 $ 143,334 $ — $ ( 15,704 ) $ 1,384,032 Liabilities: Derivative Financial Instruments: Over the Counter Swaps – Gas $ — $ 14,890 $ — $ ( 14,890 ) $ — Over the Counter No Cost Collars – Gas — — — — — Foreign Currency Contracts — 1,106 — ( 814 ) 292 Total $ — $ 15,996 $ — $ ( 15,704 ) $ 292 Total Net Assets/(Liabilities) $ 1,256,402 $ 127,338 $ — $ — $ 1,383,740 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. 19 Table of Content The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of June 30, 2026 and 2025 (in thousands): Impairments Nonrecurring Fair Value Measures Nine Months Ended June 30, Segment Date of Measurement Fair Value 2026 2025 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 June 30, 2026 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 June 30, 2026, 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. 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): June 30, 2026 September 30, 2025 Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt $ 3,567,401 $ 3,562,414 $ 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. 20 Table of Content Other Investments. The components of the Company's Other Investments are as follows (in thousands): At June 30, 2026 At September 30, 2025 Life Insurance Contracts $ 41,561 $ 44,478 Equity Mutual Fund 15,093 13,786 Fixed Income Mutual Fund 10,292 10,082 $ 66,946 $ 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 June 30, 2026 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. As of June 30, 2026, the Company had 313.8 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding. As of June 30, 2026, the Company was hedging a total of $ 36.1 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts. As of June 30, 2026, the Company had $ 88.7 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $ 72.9 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. 21 Table of Content The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2026 and 2025 (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 June 30, 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 June 30, 2026 2025 2026 2025 Commodity Contracts $ 70,098 $ 147,594 Operating Revenue $ 58,258 $ 2,515 Foreign Currency Contracts ( 369 ) 1,294 Operating Revenue ( 88 ) ( 257 ) Total $ 69,729 $ 148,888 $ 58,170 $ 2,258 The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Nine Months Ended June 30, 2026 and 2025 (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 Nine Months Ended June 30, 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 Nine Months Ended June 30, 2026 2025 2026 2025 Commodity Contracts $ 117,239 $ ( 113,145 ) Operating Revenue $ 22,959 $ 24,409 Foreign Currency Contracts ( 602 ) ( 530 ) Operating Revenue ( 275 ) ( 808 ) Total $ 116,637 $ ( 113,675 ) $ 22,684 $ 23,601 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 $ 8.0 million of credit exposure per counterparty in a gain position at June 30, 2026. The maximum credit exposure of a single counterparty in a gain position at June 30, 2026 was $ 14.5 million. As of June 30, 2026, 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 June 30, 2026, the fair market value of the derivative financial instrument 22 Table of Content liabilities with a credit-risk related contingency feature was $ 0.3 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 June 30, 2026. 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. 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 June 30, 2026 and June 30, 2025 were 25.0 % and 25.4 %, respectively. The effective income tax rate for the quarter ended June 30, 2026 was generally consistent with the prior year quarter ended June 30, 2025. The effective tax rates for the nine months ended June 30, 2026 and June 30, 2025 were 24.9 % and 24.5 %, respectively. The effective income tax rate for the nine months ended June 30, 2026 was generally consistent with the prior year nine months ended June 30, 2025. 23 Table of Content 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 April 1, 2026 95,027 $ 95,027 $ 1,388,193 $ 2,340,168 $ 1,111 Net Income Available for Common Stock 138,621 Dividends Declared on Common Stock ($ 0.555 Per Share) ( 52,745 ) Other Comprehensive Income, Net of Tax 8,465 Share-Based Payment Expense (1) 4,134 Common Stock Issued from Sale of Common Stock — — ( 7 ) Common Stock Issued Under Stock and Benefit Plans 9 9 703 Balance at June 30, 2026 95,036 $ 95,036 $ 1,393,023 $ 2,426,044 $ 9,576 Balance at October 1, 2025 90,379 $ 90,379 $ 1,050,918 $ 2,012,529 $ ( 59,222 ) Net Income Available for Common Stock 567,934 Dividends Declared on Common Stock ($ 1.625 Per Share) ( 154,419 ) Other Comprehensive Income, Net of Tax 68,798 Share-Based Payment Expense (1) 12,680 Common Stock Issued from Sale of Common Stock 4,403 4,403 333,993 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 254 254 ( 4,568 ) Balance at June 30, 2026 95,036 $ 95,036 $ 1,393,023 $ 2,426,044 $ 9,576 Balance at April 1, 2025 90,398 $ 90,398 $ 1,042,822 $ 1,855,366 $ ( 222,975 ) Net Income Available for Common Stock 149,818 Dividends Declared on Common Stock ($ 0.535 Per Share) ( 48,340 ) Other Comprehensive Income, Net of Tax 107,168 Share-Based Payment Expense (1) 4,685 Common Stock Issued Under Stock and Benefit Plans 12 12 529 Share Repurchases Under Repurchase Plan ( 54 ) ( 54 ) ( 630 ) ( 3,311 ) Balance at June 30, 2025 90,356 $ 90,356 $ 1,047,406 $ 1,953,533 $ ( 115,807 ) Balance at October 1, 2024 91,006 $ 91,006 $ 1,045,487 $ 1,727,326 $ ( 15,476 ) Net Income Available for Common Stock 411,162 Dividends Declared on Common Stock ($ 1.565 Per Share) ( 141,566 ) Other Comprehensive Loss, Net of Tax ( 100,331 ) Share-Based Payment Expense (1) 13,911 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 179 179 ( 2,377 ) Share Repurchases Under Repurchase Plan ( 829 ) ( 829 ) ( 9,615 ) ( 43,389 ) Balance at June 30, 2025 90,356 $ 90,356 $ 1,047,406 $ 1,953,533 $ ( 115,807 ) (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. 24 Table of Content Common Stock. Common stock share activity during the nine months ended June 30, 2026 consisted of the following items: Nine Months Ended June 30, 2026 Vesting of Restricted Stock Units 140,895 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 24,268 Shares Tendered to Pay Withholding Taxes on Stock-Based Compensation Awards (1) ( 78,337 ) Common Stock Issued Under Stock and Benefit Plans 254,067 Common Stock Issued from Sale of Common Stock 4,402,513 Total Common Stock Issued During the Nine Months Ended June 30, 2026 4,656,580 (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 $ 338.4 million. Refer to Note 2 – Pending Acquisition for further discussion. Short-Term Borrowings. On March 27, 2026, the Company entered into an Amended and Restated Credit Agreement (the “Credit Agreement”) with PNC Bank, National Association, as administrative agent and lender, and 12 additional lenders. The Credit Agreement provides a $ 1.3 billion unsecured committed revolving credit facility with an initial maturity date of March 27, 2031. The Credit Agreement amended and restated that certain credit agreement, dated as of February 28, 2022, among the Company, JPMorgan Chase Bank, N. A., as administrative agent, and the lenders party thereto. 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 were then lenders under the Company's prior primary revolving credit agreement. 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. Borrowings under the Term Loan Agreement bore interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10 %, plus a spread of 1.375 %. On January 22, 2026, the Company repaid all outstanding obligations under the Term Loan Agreement, and the agreement was terminated. Current Portion of Long-Term Debt. None of the Company's long-term debt as of June 30, 2026 had a maturity date within the following twelve month period. The Current Portion of Long-Term Debt at September 30, 2025 consisted of a $ 300.0 million long-term delayed draw term loan with a maturity date in February 2026 that was repaid in January 2026. Long-Term Debt. On June 10, 2026, the Company had the following long-term debt issuances: Amount of Issuance (in millions) Maturity Date Coupon Rate Net Proceeds Received (in millions) 3 -Year Note $ 500.0 5/15/2029 4.75 % $ 495.6 5 -Year Note $ 500.0 10/15/2031 5.05 % $ 494.2 10 -Year Note $ 500.0 5/15/2036 5.50 % $ 491.4 The holders of these notes may require the Company to repurchase their notes at a price equal to 101 % of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00 %, such that the coupon will not exceed 6.75 % on the 4.75 % notes, 7.05 % on the 5.05 % notes and 7.50 % on the 5.50 % notes, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. If the CenterPoint Ohio acquisition is not consummated for any reason, the Company will be required to redeem the notes in a special mandatory redemption at a price equal to 101 % of the principal amount of the notes. The proceeds of these debt issuances will be used principally to fund a portion of the CenterPoint Ohio acquisition, including the payment of related fees and expenses. In addition, a portion of the 25 Table of Content proceeds was used for general corporate purposes, including the June 11, 2026 redemption of $ 300.0 million of the Company's 5.50 % notes that were scheduled to mature in October 2026. The Company redeemed those notes for $ 301.2 million, plus accrued interest. In the Integrated Upstream and Gathering segment, the call premium of $ 0.4 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended June 30, 2026, and in the Pipeline and Storage and Utility segments, call premiums of $ 0.2 million and $ 0.6 million, respectively, were recorded to Unamortized Debt Expense on the Consolidated Balance Sheet as of June 30, 2026. 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 June 30, 2026, 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 June 30, 2026. The Company has a regulatory liability of less than $ 0.1 million related to environmental clean-up costs at June 30, 2026 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 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 and Empire provide interstate natural gas transportation services for affiliated and nonaffiliated companies through integrated natural gas pipeline systems in Pennsylvania and New York. Supply Corporation also provides storage services through its underground natural gas storage fields, and Empire provides storage service (via lease with Supply Corporation) to a nonaffiliated company. 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 26 Table of Content 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 June 30, 2026 and September 30, 2025 is shown in the tables below. Quarter Ended June 30, 2026 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) $ 302,516 $ 69,559 $ 165,422 $ 537,497 $ — $ — $ 537,497 Intersegment Revenues — 36,982 78 37,060 — ( 37,060 ) — Total Revenues 302,516 106,541 165,500 574,557 — ( 37,060 ) 537,497 Operation and Maintenance Expense (2) : Upstream General and Administrative Expense 17,487 — — 17,487 — ( 63 ) 17,424 Lease Operating Expense 15,847 — — 15,847 — ( 532 ) 15,315 Gathering Operation and Maintenance Expense 13,595 — — 13,595 — ( 69 ) 13,526 All Other Operation and Maintenance Expense 3,366 31,479 61,652 96,497 — 12,377 108,874 Purchased Gas Expense (2) — — 66,239 66,239 — ( 36,361 ) 29,878 Depreciation, Depletion and Amortization Expense (2) 83,078 19,656 18,090 120,824 — 234 121,058 Interest Expense (2) 13,509 11,735 10,764 36,008 122 ( 118 ) 36,012 Interest Income ( 414 ) ( 1,129 ) ( 912 ) ( 2,455 ) — ( 1,484 ) ( 3,939 ) Income Tax Expense (Benefit) (2) 40,400 9,417 ( 1,118 ) 48,699 ( 72 ) ( 2,454 ) 46,173 Other Expense (Income) Items (3) 3,774 6,644 5,099 15,517 172 ( 1,134 ) 14,555 Segment Profit: Net Income (Loss) $ 111,874 $ 28,739 $ 5,686 $ 146,299 $ ( 222 ) $ ( 7,456 ) $ 138,621 Expenditures for Additions to Long-Lived Assets $ 146,327 $ 91,571 $ 46,956 $ 284,854 $ — $ 4,009 $ 288,863 Nine Months Ended June 30, 2026 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) $ 984,561 $ 212,558 $ 850,258 $ 2,047,377 $ — $ — $ 2,047,377 Intersegment Revenues — 112,347 294 112,641 — ( 112,641 ) — Total Revenues 984,561 324,905 850,552 2,160,018 — ( 112,641 ) 2,047,377 Operation and Maintenance Expense (2) : Upstream General and Administrative Expense 55,365 — — 55,365 — ( 188 ) 55,177 Lease Operating Expense 50,034 — — 50,034 — ( 1,855 ) 48,179 Gathering Operation and Maintenance Expense 37,788 — — 37,788 — ( 207 ) 37,581 All Other Operation and Maintenance Expense 9,847 89,913 190,778 290,538 — 25,437 315,975 Purchased Gas Expense (2) — — 433,384 433,384 — ( 110,049 ) 323,335 Depreciation, Depletion and Amortization Expense (2) 247,888 58,719 55,171 361,778 — 634 362,412 Interest Expense (2) 44,753 35,314 33,508 113,575 376 ( 831 ) 113,120 Interest Income ( 986 ) ( 2,964 ) ( 3,116 ) ( 7,066 ) ( 10 ) ( 1,544 ) ( 8,620 ) Income Tax Expense (Benefit) (2) 139,559 30,341 24,217 194,117 154 ( 6,026 ) 188,245 Other Expense (Income) Items (3) 12,362 22,017 11,485 45,864 ( 1,043 ) ( 782 ) 44,039 Segment Profit: Net Income (Loss) $ 387,951 $ 91,565 $ 105,125 $ 584,641 $ 523 $ ( 17,230 ) $ 567,934 Expenditures for Additions to Long-Lived Assets $ 453,903 $ 166,199 $ 120,550 $ 740,652 $ — $ 3,888 $ 744,540 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 June 30, 2026 $ 4,120,435 $ 2,690,056 $ 2,621,401 $ 9,431,892 $ 10,496 $ 1,009,379 $ 10,451,767 At September 30, 2025 $ 3,701,646 $ 2,412,747 $ 2,534,289 $ 8,648,682 $ 8,704 $ 61,718 $ 8,719,104 27 Table of Content Quarter Ended June 30, 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) $ 306,402 $ 67,982 $ 157,446 $ 531,830 $ — $ — $ 531,830 Intersegment Revenues — 37,597 77 37,674 — ( 37,674 ) — Total Revenues 306,402 105,579 157,523 569,504 — ( 37,674 ) 531,830 Operation and Maintenance Expense (2) : Upstream General and Administrative Expense 18,602 — — 18,602 — ( 59 ) 18,543 Lease Operating Expense 12,566 — — 12,566 — ( 1,303 ) 11,263 Gathering Operation and Maintenance Expense 7,865 — — 7,865 — ( 65 ) 7,800 All Other Operation and Maintenance Expense 3,816 30,264 57,039 91,119 — 4,279 95,398 Purchased Gas Expense (2) — — 64,292 64,292 — ( 36,306 ) 27,986 Depreciation, Depletion and Amortization Expense (2) 79,696 18,601 17,945 116,242 — 166 116,408 Interest Expense (2) 17,795 11,209 10,958 39,962 141 ( 2,214 ) 37,889 Interest Income ( 89 ) ( 1,116 ) ( 537 ) ( 1,742 ) ( 11 ) 664 ( 1,089 ) Income Tax Expense (Benefit) (2) 44,333 10,415 ( 2,201 ) 52,547 ( 63 ) ( 1,405 ) 51,079 Other Expense (Income) Items (3) 5,151 7,349 5,030 17,530 142 ( 937 ) 16,735 Segment Profit: Net Income (Loss) $ 116,667 $ 28,857 $ 4,997 $ 150,521 $ ( 209 ) $ ( 494 ) $ 149,818 Expenditures for Additions to Long-Lived Assets $ 150,007 $ 22,700 $ 50,025 $ 222,732 $ — $ 138 $ 222,870 Nine Months Ended June 30, 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) $ 873,901 $ 207,916 $ 729,445 $ 1,811,262 $ — $ — $ 1,811,262 Intersegment Revenues — 113,849 279 114,128 — ( 114,128 ) — Total Revenues 873,901 321,765 729,724 1,925,390 — ( 114,128 ) 1,811,262 Operation and Maintenance Expense (2) : Upstream General and Administrative Expense 56,776 — — 56,776 — ( 177 ) 56,599 Lease Operating Expense 35,710 — — 35,710 — ( 4,513 ) 31,197 Gathering Operation and Maintenance Expense 23,760 — — 23,760 — ( 194 ) 23,566 All Other Operation and Maintenance Expense 10,994 87,940 177,742 276,676 — 10,562 287,238 Purchased Gas Expense (2) — — 337,541 337,541 — ( 108,880 ) 228,661 Depreciation, Depletion and Amortization Expense (2) 228,970 55,733 51,908 336,611 — 444 337,055 Impairment of Assets (Significant Non-Cash Item) (2) 141,802 — — 141,802 — — 141,802 Interest Expense (2) 60,029 34,637 32,601 127,267 389 ( 7,267 ) 120,389 Interest Income ( 1,297 ) ( 4,919 ) ( 1,631 ) ( 7,847 ) ( 11 ) 2,833 ( 5,025 ) Income Tax Expense (Benefit) (2) 82,761 32,553 21,498 136,812 ( 204 ) ( 2,979 ) 133,629 Other Expense (Income) Items (3) 13,191 22,802 9,025 45,018 500 ( 529 ) 44,989 Segment Profit: Net Income (Loss) $ 221,205 $ 93,019 $ 101,040 $ 415,264 $ ( 674 ) $ ( 3,428 ) $ 411,162 Expenditures for Additions to Long-Lived Assets $ 412,519 $ 58,117 $ 128,322 $ 598,958 $ — $ ( 3,002 ) $ 595,956 (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. 28 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 June 30, 2026 2025 2026 2025 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) 152 85 131 ( 447 ) Net Periodic Benefit Cost (Income) $ ( 2,269 ) $ ( 2,620 ) $ ( 3,215 ) $ ( 3,326 ) Retirement Plan Other Post-Retirement Benefits Nine Months Ended June 30, 2026 2025 2026 2025 Service Cost $ 2,584 $ 3,069 $ 315 $ 389 Interest Cost 26,833 27,669 11,508 10,876 Expected Return on Plan Assets ( 44,131 ) ( 43,940 ) ( 22,122 ) ( 19,608 ) Amortization of Prior Service Cost (Credit) 190 227 ( 195 ) ( 322 ) Amortization of (Gains) Losses 7,261 4,860 456 28 Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) ( 2,825 ) ( 3,026 ) ( 3,578 ) ( 5,333 ) Net Periodic Benefit Cost (Income) $ ( 10,088 ) $ ( 11,141 ) $ ( 13,616 ) $ ( 13,970 ) (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 nine months ended June 30, 2026, 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 nine months ended June 30, 2026, 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 29 Table of Content 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. On May 5, 2026, Distribution Corporation filed a petition with the NYPSC for, among other things, authorization to implement a system modernization tracker reconciliation mechanism through which qualified leak prone pipe removal costs incurred by the Company would be tracked and recovered. The petition remains pending with the Commission. 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 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 with a cap equivalent to 5 % of distribution revenues, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. Effective April 1, 2026, the DSIC cap was met and the DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing. 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 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. As reflected in a February 19, 2026 PaPUC Order, the filing was suspended until October 29, 2026 by operation of law unless directed otherwise by the PaPUC. Final briefs were submitted in the case on July 1, 2026. A decision is generally anticipated from the administrative law judge in August 2026. FERC Jurisdiction Supply Corporation filed an NGA Section 4 rate case at FERC on April 30, 2026 proposing rate increases to be effective November 1, 2026. Supply Corporation's filing requests an annual cost of service of approximately $ 404 million, an increase of approximately $ 95 million from Supply Corporation's settlement of its 2023 rate proceeding. The proposal also includes, among other things, a modernization cost recovery mechanism. By regulation, the proposed rates will become effective November 1, 2026 subject to refund, unless the parties in the case reach a settlement. 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.