National Fuel Gas NFG Form 10-Q filing Q2 FY2026

Item 1. Financial Statements (Unaudited)

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

See Notes to Condensed Consolidated Financial Statements

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See Notes to Condensed Consolidated Financial Statements

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See Notes to Condensed Consolidated Financial Statements

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See Notes to Condensed Consolidated Financial Statements

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See Notes to Condensed Consolidated Financial Statements

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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 six months ended March 31, 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 components, as reported on the Company's Consolidated Balance Sheets, of the total cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands):

The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents. Cash Held in Trust for Bondholders is the only restricted cash recorded on the Consolidated Balance Sheet. It relates to the cancellation and discharge of the Company's obligations under its 1974 indenture covenants.

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

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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.

Activity in the allowance for uncollectible accounts for the six months ended March 31, 2026 and 2025 are as follows (in thousands):

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 $47.4 million at March 31, 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 $2.59 billion and $2.46 billion at March 31, 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 $109.3 million and $112.4 million at March 31, 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 March 31, 2026, the ceiling exceeded the book value of the exploration and production properties by approximately $1.6 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 March 31, 2026, estimated future net cash flows were increased by $59.5 million.

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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 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 March 31, 2026.

Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the six months ended March 31, 2026 and 2025, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):

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Reclassifications Out of Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the six months ended March 31, 2026 and 2025 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Other Current Assets. The components of the Company’s Other Current Assets are as follows (in thousands):

Other Accruals and Current Liabilities. The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

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 six months ended March 31, 2026, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these

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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 99 securities and 2,072 securities excluded as being antidilutive for the quarter and six months ended March 31, 2026, respectively. There were 30 securities excluded as being antidilutive for the quarter ended March 31, 2025. There were no securities excluded as being antidilutive for the six months ended March 31, 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 six months ended March 31, 2026. The weighted average fair value of such performance shares was $62.07 per share for the six months ended March 31, 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 six months ended March 31, 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 128,755 restricted stock units during the six months ended March 31, 2026. The weighted average fair value of such restricted stock units was $77.75 per share for the six months ended March 31, 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 in the fourth quarter of calendar 2026, pending completion of a review with the PUCO 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, 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

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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.

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. The total commitment under both facilities, as adjusted for the equity issuance mentioned in the previous paragraph, is currently $2.28 billion.

Note 3 – Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the quarter and six months ended March 31, 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.

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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: $118.0 million for the remainder of fiscal 2026; $228.4 million for fiscal 2027; $172.6 million for fiscal 2028; $131.3 million for fiscal 2029; $124.3 million for fiscal 2030; and $540.7 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.

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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 March 31, 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.

(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.

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The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of March 31, 2026 and 2025 (in thousands):

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 March 31, 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 March 31, 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):

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.

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Other Investments. The components of the Company's Other Investments are as follows (in thousands):

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 March 31, 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 March 31, 2026, the Company had 374.1 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of March 31, 2026, the Company was hedging a total of $38.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of March 31, 2026, the Company had $80.3 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $67.1 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.

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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 $7.3 million of credit exposure per counterparty in a gain position at March 31, 2026. The maximum credit exposure of a single counterparty in a gain position at March 31, 2026 was $14.3 million. As of March 31, 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 March 31, 2026, the fair market value of the derivative financial instrument

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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 March 31, 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 March 31, 2026 and March 31, 2025 were 25.0% and 24.8%, respectively. The effective income tax rate for the quarter ended March 31, 2026 was generally consistent with the prior year quarter ended March 31, 2025.

The effective tax rates for the six months ended March 31, 2026 and March 31, 2025 were 24.9% and 24.0%, respectively. The change in the effective income tax rate was primarily driven by the impact of the impairment of the exploration and production properties under the ceiling test, as well as an impairment of certain water disposal assets, both of which were recorded in the quarter ended December 31, 2024, which resulted in a smaller income tax expense on income before income taxes to be recorded during the six months ended March 31, 2025.

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Note 7 – Capitalization

Summary of Changes in Common Stock Equity

(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.

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Common Stock. Common stock share activity during the six months ended March 31, 2026 consisted of the following items:

(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. The Current Portion of Long-Term Debt at March 31, 2026 consisted of $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 a $300.0 million long-term delayed draw term loan with a maturity date in February 2026 that was repaid in January 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 March 31, 2026, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.1 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at March 31, 2026. The Company has a regulatory liability of $0.5 million related to environmental clean-up costs at March 31, 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

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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 March 31, 2026 and September 30, 2025 is shown in the tables below.

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(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.

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Note 10 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):

(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 six months ended March 31, 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 six months ended March 31, 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

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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 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.

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. During the quarter ended March 31, 2026, Distribution Corporation recovered $2.8 million from customers. The DSIC cap has been met and the Company is unable to earn a return on incremental plant investments. 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 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.

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.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin. In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets. The Company reports

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financial results for three business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project in northwest Tioga County, Pennsylvania. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project commenced in February 2026. This project has a target in-service date in late calendar 2026.

Supply Corporation has also announced that it expects to serve as the transporter of natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania, which will support a co-located data center that is currently under development. The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025 and construction commenced in March 2026.

Supply Corporation has also developed its Line N System Upgrade Project, which will consist of modernization of primarily 1960’s era pipeline in Beaver County, Pennsylvania, as well as minor compressor station and facility upgrades. In April 2026, Supply Corporation executed a long-term precedent agreement with a shipper for 100% of the incremental capacity created by the project. The project has a projected in-service date of late calendar 2028. The Tioga Pathway Project, Shippingport Lateral Project and Line N System Upgrade Project are all discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its New York jurisdiction, reached a settlement with the parties to its rate case proceeding. On December 19, 2024, the NYPSC issued an order approving the settlement. The settlement, effective January 1, 2025, established a three-year rate plan that 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. The settlement also included standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024.

In Distribution Corporation's Pennsylvania jurisdiction, Distribution Corporation made a filing with the PaPUC on January 28, 2026 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 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.

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. In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. For further discussion of these and other rate matters, refer to the Rate Matters section below.

On October 20, 2025, the Company entered into 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 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 review with the PUCO 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, 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

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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.

In connection with the Purchase Agreement, the Company is a party to commitment letters for a 364-day senior unsecured term loan facility related to the consideration to be paid at closing, and a senior unsecured bridge loan facility related to repayment of the promissory note. The commitment letters are supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility. Together, the commitment letters fully support any portion of the aggregate purchase price that has not been permanently financed.

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. The Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). At March 31, 2026, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in the quarter ended March 31, 2026. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

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. For further discussion of the Credit Agreement, refer to the Capital Resources and Liquidity section below.

The Company expects to use cash from operations, equity proceeds, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including any potential funding for the CenterPoint Ohio acquisition and the repayment of its $300.0 million of 5.50% notes with a maturity date in October 2026. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and the ongoing impacts of federal policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

Exploration and Development Costs. The Company, in its Integrated Upstream and Gathering segment, follows the full cost method of accounting for determining the book value of its exploration and production properties. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling. At March 31, 2026, the ceiling exceeded the book value of the exploration and production properties by approximately $1.6 billion (after-tax). The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2026, based on the quoted Henry Hub spot price for natural gas, was $3.72 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended March 31, 2026. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at March 31, 2026 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $1.2 billion (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

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It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were $247.7 million for the quarter ended March 31, 2026 compared to earnings of $216.4 million for the quarter ended March 31, 2025. The increase in earnings of $31.3 million is primarily the result of higher earnings in the Integrated Upstream and Gathering segment.

The Company's earnings were $429.3 million for the six months ended March 31, 2026 compared to earnings of $261.3 million for the six months ended March 31, 2025. The increase in earnings of $168.0 million is primarily the result of higher earnings in the Integrated Upstream and Gathering segment.

The Company's earnings for the six months ended March 31, 2025 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Integrated Upstream and Gathering segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above. The remaining charges are related to the impairment of certain water disposal assets. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment

Integrated Upstream and Gathering

Integrated Upstream and Gathering Operating Revenues

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Production Volumes

Average Prices

2026 Compared with 2025

Operating revenues for the Integrated Upstream and Gathering segment increased $43.6 million for the quarter ended March 31, 2026 as compared with the quarter ended March 31, 2025. Gas production revenue after hedging increased $41.0 million due to the impact of a $0.51 per Mcf increase in the weighted average price of natural gas after hedging, partially offset by a 3.5 Bcf decrease in natural gas production. The decrease in natural gas production was largely due to weather-driven completion delays and natural gas production declines on producing wells. In addition, other revenue increased $3.3 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses. Slightly offsetting these increases, gathering revenue decreased $0.6 million as a result of natural production declines by producers connected to the Tioga and Trout Run gathering systems.

Operating revenues for the Integrated Upstream and Gathering segment increased $114.5 million for the six months ended March 31, 2026 as compared with the six months ended March 31, 2025. Gas production revenue after hedging increased $109.6 million due to the impact of a $0.42 per Mcf increase in the weighted average price of natural gas after hedging, coupled with an 8.0 Bcf increase in natural gas production. The increase in natural gas production was largely due to the timing of new wells brought online partially offset by natural gas production declines on producing wells. In addition, other revenue increased $6.2 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses. Slightly offsetting these increases, gathering revenue decreased $1.3 million as a result of natural production declines by producers connected to the Tioga and Trout Run gathering systems.

The Integrated Upstream and Gathering segment's earnings for the quarter ended March 31, 2026 were $152.0 million, an increase of $27.8 million when compared with earnings of $124.2 million for the quarter ended March 31, 2025. The $27.8 million increase can be attributed to the following factors:

(1) The decrease in interest expense is mainly attributed to lower short-term and long-term intercompany borrowings.

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(2) Represents the segment's share of the premiums paid by the Company to redeem long-term debt during the quarter ended March 31, 2025.

(3) The increase in depletion is mainly attributed to a higher depletion rate.

(4) The increase in lease operating expenses was primarily the result of additional third-party gathering and transportation costs combined with higher road maintenance costs.

(5) The increase in other operating expenses is mainly attributed to a change in segment reporting combined with higher gathering operation and maintenance expense and higher abandonment accretion expense. These were partially offset by higher abandonment costs recognized during the quarter ended March 31, 2025.

(6) The increase in income tax expense was primarily driven by an increase in state tax expense due to higher pre-tax income.

The Integrated Upstream and Gathering segment's earnings for the six months ended March 31, 2026 were $276.1 million, an increase of $171.6 million when compared with earnings of $104.5 million for the six months ended March 31, 2025. The $171.6 million increase can be attributed to the following factors:

(1) Includes a ceiling test impairment of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024.

(2) The decrease in interest expense is mainly attributed to lower short-term and long-term intercompany borrowings.

(3) Represents the segment's share of the premiums paid by the Company to redeem long-term debt during the six months ended March 31, 2025.

(4) The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the six months ended March 31, 2025.

(5) The increase in depletion is mainly attributed to higher production combined with a higher depletion rate.

(6) The increase in lease operating expenses was primarily the result of additional third-party gathering and transportation costs combined with higher road maintenance costs.

(7) The increase in other operating expenses is mainly attributed to a change in segment reporting combined with higher gathering operation and maintenance and higher abandonment accretion expense. These were partially offset by higher abandonment costs recognized during the six months ended March 31, 2025.

(8) The increase in income tax expense was primarily driven by higher state tax expense due to an increase in pre-tax income.

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Pipeline and Storage

Pipeline and Storage Operating Revenues

Pipeline and Storage Throughput

2026 Compared with 2025

Operating revenues for the Pipeline and Storage segment increased $1.9 million for the quarter ended March 31, 2026 as compared with the quarter ended March 31, 2025. The increase in operating revenue was primarily driven by higher other revenues of $0.9 million, along with an increase in transportation revenues of $0.6 million and an increase in storage revenues of $0.4 million. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance. The increase in transportation revenues was primarily attributable to new long-term contracts and rate increases on existing contracts, partially offset by revisions to existing contracts. The increase in storage revenues was primarily attributable to rate increases and deliverability enhancements on existing contracts.

Operating revenues for the Pipeline and Storage segment increased $2.2 million for the six months ended March 31, 2026 as compared with the six months ended March 31, 2025. The increase in operating revenue was primarily driven by higher other revenues of $1.3 million, along with an increase in storage revenues of $0.5 million and an increase in transportation revenues of $0.4 million. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance expense. The increase in storage revenues was primarily attributable to rate increases and deliverability enhancements on existing contracts coupled with increased commodity revenue driven by colder weather. The increase in transportation revenues was primarily attributable to new long-term contracts and rate increases on existing contracts, partially offset by revisions to existing contracts.

Transportation volume for the quarter and six months ended March 31, 2026 increased by 12.3 Bcf and 23.5 Bcf, respectively, from the prior year's quarter and six month periods. The increase in transportation volume for both the quarter and six months ended March 31, 2026 is primarily due to increased utilization resulting from colder weather. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

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The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2026 were $31.6 million, a decrease of $0.1 million when compared with earnings of $31.7 million for the quarter ended March 31, 2025. The $0.1 million decrease can be attributed to the following factors:

(1) The increase in depreciation expense primarily reflects additional plant in-service.

(2) The decrease in other income was primarily due to a lower average amount outstanding on intercompany short-term notes receivables and a lower weighted average interest rate on those receivables.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2026 were $62.8 million, a decrease of $1.4 million when compared with earnings of $64.2 million for the six months ended March 31, 2025. The $1.4 million decrease can be attributed to the following factors:

(1) The decrease in other income was primarily due to a lower average amount outstanding on intercompany short-term notes receivables and a lower weighted average interest rate on those receivables.

(2) The increase in depreciation expense primarily reflects additional plant in-service.

Utility

Utility Operating Revenues

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Utility Throughput

Degree Days

(1) Percents compare actual 2026 degree days to normal degree days and actual 2026 degree days to actual 2025 degree days.

2026 Compared with 2025

Operating revenues for the Utility segment increased $82.2 million for the quarter ended March 31, 2026 as compared with the quarter ended March 31, 2025. This increase resulted from a $77.3 million increase in retail gas sales revenue, a $3.1 million increase in transportation revenue and a $1.9 million increase in other revenue. The increase in retail gas sales revenue and transportation revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting mainly from an increase in the cost of gas sold (per Mcf) as well as a 1.0 Bcf increase in throughput mainly due to colder weather. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. Retail gas sales revenue and transportation revenue were also impacted by an increase to revenue from a distribution system improvement charge (“DISC”) modernization tracker in Pennsylvania that became effective in January 2025. For further discussion of the DSIC tracker, refer to the Rate Matters section below. The increase in transportation revenue also reflects a 0.4 Bcf increase in throughput due primarily to colder weather. The increase in other revenue was primarily due to certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million), as well as increases in late payment charges billed to customers ($0.5 million) and capacity release revenues ($0.4 million).

Operating revenues for the Utility segment increased $112.9 million for the six months ended March 31, 2026 as compared with the six months ended March 31, 2025. This increase resulted from a $105.9 million increase in retail gas sales revenue, a $4.7 million increase in transportation revenue and a $2.2 million increase in other revenue. The increase in retail gas sales revenue and transportation revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction, as discussed above. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from an increase in the cost of gas sold (per Mcf) as well as a 5.0 Bcf increase in throughput mainly due to colder weather. Retail gas sales revenue and transportation revenue were also impacted by an increase to revenue from the DISC modernization tracker in Pennsylvania, as discussed above. The increase in transportation revenue also reflects a 3.1 Bcf

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increase in throughput due primarily to colder weather. The increase in other revenue was primarily due to certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million), as well as increases in late payment charges billed to customers ($0.8 million) and capacity release revenues ($0.6 million).

The Utility segment’s earnings for the quarter ended March 31, 2026 were $65.3 million, an increase of $1.8 million when compared with earnings of $63.5 million for the quarter ended March 31, 2025. The increase can be attributed to the following factors:

(1) Amount primarily reflects an increase in earnings from a DSIC modernization tracker in Pennsylvania that became effective in January 2025 combined with certain other quarterly regulatory true-up adjustments.

(2) The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses as a result of higher operating revenue.

(3) The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

The impact of weather variations on earnings in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on customer bills and earnings for the Utility segment. For the quarter ended March 31, 2026, the WNA reduced earnings by approximately $1.1 million in both the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was colder than normal on a cycle-bill basis in both jurisdictions. For the quarter ended March 31, 2025, the WNA preserved earnings of approximately $0.6 million in the Utility segment’s New York rate jurisdiction, as the weather was warmer than normal on a cycle-bill basis. The earnings preserved by the WNA in the Utility segment's Pennsylvania rate jurisdiction for the quarter ended March 31, 2025 were negligible.

The Utility segment’s earnings for the six months ended March 31, 2026 were $99.4 million, an increase of $3.4 million when compared with earnings of $96.0 million for the six months ended March 31, 2025. The increase can be attributed to the following factors:

(1) Amount primarily reflects an increase in earnings from a DSIC modernization tracker in Pennsylvania that became effective in January 2025 combined with certain other quarterly regulatory true-up adjustments.

(2) The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses as a result of higher operating revenue.

(3) The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

(4) The increase in interest expenses is mainly attributed to an increase in long-term intercompany debt balances.

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For the six months ended March 31, 2026, the WNA reduced earnings by approximately $1.9 million and $2.0 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was colder than normal on a cycle-bill basis in both jurisdictions. For the six months ended March 31, 2025, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $2.6 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.2 million, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

ALL OTHER AND CORPORATE OPERATIONS

2026 Compared with 2025

All Other and Corporate operations reported a net loss of $1.3 million for the quarter ended March 31, 2026, a reduction of $1.8 million when compared with a net loss of $3.1 million for the quarter ended March 31, 2025. The reduction was primarily attributable to a net interest benefit arising from the December 2025 equity issuance ($2.6 million). While the proceeds of the equity issuance are intended for the pending acquisition of CenterPoint Ohio, in the short term those proceeds have created some interest income and, to a larger extent, have reduced borrowings and interest expense. Additional factors contributing to the reduction in net loss were an increase in income from life insurance policies ($1.1 million) and higher income from unconsolidated subsidiaries ($1.2 million). Partially offsetting these decreases to net loss were a decrease in interest income earned on temporary cash investments ($0.7 million), external costs associated with the Company's planned acquisition of CenterPoint Ohio ($1.9 million) and higher internal labor costs ($0.6 million). Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition.

For the six months ended March 31, 2026, All Other and Corporate operations reported a net loss of $9.0 million, an increase of $5.6 million when compared with a net loss of $3.4 million for the six months ended March 31, 2025. The increase was primarily attributable to external costs associated with the Company's planned acquisition ($7.8 million), as mentioned above, and higher operating expenses ($2.0 million) primarily attributable to an increase in internal labor costs, employee benefits and legal and consulting fees. Partially offsetting these increases, there was a net interest benefit from the December 2025 equity issuance ($3.0 million), as mentioned above, and higher income from unconsolidated subsidiaries ($1.2 million).

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $17.0 million for the quarter ended March 31, 2026, compared to net other income of $15.2 million for the quarter ended March 31, 2025, for an increase of $1.8 million. This increase can be attributed primarily to higher income from unconsolidated subsidiaries of $1.4 million and a $1.1 million increase in income from life insurance policies. Partially offsetting these increases was a $0.8 million decrease in non-service pension and post-retirement benefit income.

Net other income on the Consolidated Statements of Income was $25.2 million for the six months ended March 31, 2026, compared to net other income of $23.0 million for the six months ended March 31, 2025, for an increase of $2.2 million. This increase can be attributed primarily to higher income from unconsolidated subsidiaries of $1.6 million, along with an increase in interest income on deferred gas costs of $1.2 million and the nonrecurrence of a $0.7 million revaluation adjustment for contingent consideration that reduced other income during the six months ended March 31, 2025. Partially offsetting these increases was a $1.4 million decrease in non-service pension and post-retirement benefit income.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income decreased $9.6 million for the quarter ended March 31, 2026 as compared to the quarter ended March 31, 2025. For the six months ended March 31, 2026, interest expense on long-term debt decreased $9.4 million as compared with the six months ended March 31, 2025. The decrease in interest expense for both the quarter and six months ended March 31, 2026 was due to lower debt outstanding. The Company repaid a $300 million delayed draw term loan in January 2026. On February 19, 2025, the Company issued $500 million of 5.50% notes and $500 million of 5.95% notes. On March 6, 2025, the Company redeemed $450 million of 5.20% notes and $500 million of 5.50% notes and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Integrated Upstream and Gathering segment.

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Other Interest Expense

Other interest expense on the Consolidated Statement of Income decreased $1.4 million for the quarter ended March 31, 2026 as compared to the quarter ended March 31, 2025. This decrease was primarily due to lower average short term debt balances. For the six months ended March 31, 2026, other interest expense increased $4.0 million as compared to the six months ended March 31, 2025. This increase was primarily due to financing costs incurred associated with the Company's acquisition of CenterPoint Ohio's natural gas utility.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the six-month period ended March 31, 2026 consisted of cash provided by operating activities and net proceeds from the issuance of common stock. The Company’s primary source of cash during the six-month period ended March 31, 2025 consisted of cash provided by operating activities and net proceeds from short-term and long-term borrowings.

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During the remainder of 2026, the Company expects to use cash provided by operating activities and short-term borrowings to fund the Company's capital expenditures. In January 2026, the Company repaid the $300.0 million delayed draw term loan that was scheduled to mature in February 2026. Looking forward to 2027, based on current forward commodity prices, cash provided by operating activities is expected to exceed capital expenditures. These cash flow projections do not include the impact of the CenterPoint Ohio acquisition, the repayment of the Company's $300.0 million of 5.50% notes with a maturity date in 2026 or the impact of other acquisitions or divestitures that may arise in the future.

Operating Cash Flow

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of assets, deferred income taxes and stock-based compensation.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs, weather and regulatory lag may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. The weather impact on cash flow in the Utility segment is mitigated by a WNA in both its New York and Pennsylvania rate jurisdictions.

Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.

The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, 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 is reduced as the inventory is replenished.

Cash provided by operating activities in the Integrated Upstream and Gathering segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. The pricing protection obtained from derivative financial instruments will fluctuate over time as instruments expire and are replaced with new instruments reflecting current commodity prices of natural gas.

Net cash provided by operating activities totaled $657.3 million for the six months ended March 31, 2026, an increase of $183.4 million compared with $473.9 million provided by operating activities for the six months ended March 31, 2025. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Integrated Upstream and Gathering segment. The increase in the Integrated Upstream and Gathering segment is primarily due to higher

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natural gas prices and production in the Appalachian region combined with the timing of cash receipts and hedge settlements associated with that production.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $455.7 million during the six months ended March 31, 2026 and $373.1 million during the six months ended March 31, 2025. The table below presents these expenditures:

(1) At March 31, 2026, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $71.6 million, $5.1 million and $6.0 million, respectively, of non-cash capital expenditures. At September 30, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $87.9 million, $19.4 million and $18.0 million, respectively, of non-cash capital expenditures.

(2) At March 31, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $51.6 million, $2.4 million and $4.8 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures.

Integrated Upstream and Gathering

The Integrated Upstream and Gathering segment capital expenditures for the six months ended March 31, 2026 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $194.6 million spent in the Utica Shale area and $68.4 million spent in the Marcellus Shale area. These amounts included approximately $188.9 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Trout Run and Tioga gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

The Integrated Upstream and Gathering segment capital expenditures for the six months ended March 31, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $137.8 million spent in the Utica Shale area and $84.3 million spent in the Marcellus Shale area. These amounts included approximately $105.4 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2026 and March 31, 2025 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In

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addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2026 included expenditures related to Supply Corporation's Tioga Pathway Project ($8.4 million) and Shippingpoint Lateral Project ($12.6 million), both of which are discussed below.

In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines, on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems, including projects to support regional demand for power generation to support the electric grid and data center development and storage enhancements. Expansion and modernization projects where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures, and where a precedent agreement has been executed, are discussed below.

Supply Corporation has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity and filed a Section 7(b)/7(c) application with the FERC on August 21, 2024. FERC issued the Section 7(b)/7(c) certificate on May 5, 2025 and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project commenced in February 2026. This project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of March 31, 2026, approximately $13.5 million has been capitalized as Construction Work in Progress for this project.

Additionally, Supply Corporation concluded an open season on February 26, 2025, and based on interest in that open season, designed a project that would allow for the transportation of 205,000 Dth per day of natural gas supplies from its existing Line N pipeline system to a new interconnection with the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania, which will support a co-located data center that is currently under development (the “Shippingport Lateral Project”). In order to provide this new natural gas transportation capacity, Supply Corporation will construct an approximately 7.5 mile pipeline lateral from its existing Line N pipeline system to a direct interconnection with the facility with the incremental capacity expected to come online in late calendar 2026 and an estimated capital cost of approximately $57 million. Supply Corporation has executed a Precedent Agreement with Shippingport Power Station, LLC, the facility developer, for 100% of the capacity for the Shippingport Lateral Project and filed an application with FERC under the Commission’s prior notice regulations on August 29, 2025. The project obtained FERC authorization on November 7, 2025 and construction commenced in March 2026. As of March 31, 2026, approximately $12.8 million has been capitalized as Construction Work in Progress for this project.

Supply Corporation has also developed its Line N System Upgrade Project, which will consist of modernization of primarily 1960’s era pipeline in Beaver County, Pennsylvania, as well as minor compressor station and facility upgrades, to create approximately 94,000 Dth per day of additional natural gas transportation capacity from a new interconnection on the southern portion of Supply’s Line N system in Greene County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Mercer. In April 2026, Supply Corporation executed a long-term precedent agreement with a shipper for 100% of the incremental capacity created by the project. The project has a projected in-service date of late calendar 2028 and an estimated capital cost of approximately $93 million. As of March 31, 2026, $0.3 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at March 31, 2026.

Utility

The majority of the Utility segment capital expenditures for the six months ended March 31, 2026 and March 31, 2025 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.

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Project Funding

During the six months ended March 31, 2026 and fiscal 2025, the Company has financed capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash from operations, equity proceeds, and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Integrated Upstream and Gathering segment. It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment as well as the timing of base rate recovery in the Pipeline and Storage segment.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas generation facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility and Pipeline and Storage segments are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

Financing Cash Flow

Consolidated short-term debt decreased $108.9 million when comparing the balance sheet at March 31, 2026 to the balance sheet at September 30, 2025. The maximum amount of short-term debt outstanding during the six months ended March 31, 2026 was $311.0 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As of March 31, 2026, the Company had outstanding commercial paper of $41.3 million and did not have any short-term notes payable to banks.

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 (the “Acquired Company” or “CenterPoint Ohio”), the Seller’s Ohio natural gas local distribution company, for an aggregate purchase price of $2.62 billion, subject to customary adjustments (the “Purchase Price”), as provided in the Purchase Agreement (the “Transaction”). The Purchase Price will be paid through a combination of cash and a promissory note to be issued by the Company to the Seller at closing pursuant to a Seller Note Agreement (the “Seller Note Agreement”) between the Company, as borrower, and the Seller, as lender. The Seller Note Agreement, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will provide a $1.2 billion unsecured term loan credit facility (the “Seller Note Facility”) that matures on the last business day that is not more than 364 days from the closing of the Transaction.

The borrowings under the Seller Note Facility will bear interest at a rate of 6.5% per annum. The Seller Note Agreement will contain customary representations and affirmative, negative and financial covenants, consistent with the Company’s February 2024 term loan agreement discussed below. The Seller Note Agreement will also include covenants restricting certain actions with respect to the Acquired Company. The Seller Note Agreement will contain certain specified events of default, and should an event of default occur, the lender is entitled to exercise certain remedies, including acceleration of the loan and related obligations.

The Seller Note Agreement will contain a covenant defeasance provision that permits the Company to relieve itself from its obligations to comply with covenants under the Seller Note Agreement upon deposit of an amount with a paying agent sufficient to pay the principal of and interest due on the loan on each applicable interest payment date and the maturity date.

In connection with its entry into the Purchase Agreement, the Company entered into a bridge facility commitment letter (the “Bridge Commitment Letter”), pursuant to which The Toronto-Dominion Bank, New York Branch (“TD Bank”) and Wells Fargo Bank, National Association (“Wells Fargo Bank” and, together with TD Bank, the “Commitment Parties”), agreed to provide to the Company loans under a senior unsecured bridge loan facility (the “Bridge Facility”) composed of a $1.42

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billion 364-day tranche (the “Acquisition Tranche”), the proceeds of which will be used, if needed, to finance the Transaction, and a $1.2 billion 364-day tranche (the “Seller Note Tranche”), the proceeds of which will be used, if needed, to refinance the Seller Note Facility at its scheduled maturity.

On November 6, 2025, the Company entered into a 364-day term loan facility commitment letter (the “Term Loan Commitment Letter”), pursuant to which the Commitment Parties and ten additional banks, all of which are lenders under our primary credit facility, agreed to provide to the Company loans under a 364-day senior unsecured term loan facility (the “Term Loan Facility”) in the amount of $1.42 billion, the proceeds of which will be used, if needed, to finance the Transaction. Entering into the Term Loan Commitment Letter enabled the Company to terminate the commitments under the Bridge Commitment Letter in respect of the Acquisition Tranche. Also on November 6, 2025, the same ten additional banks joined the Commitment Parties as parties to the Bridge Commitment Letter in respect of the Seller Note Tranche.

Subject to the conditions in the respective commitment letters, the commitments under the Term Loan Facility and the Bridge Facility (together, the “Commitments”) may be reduced by proceeds of certain additional indebtedness that may be incurred by the Company and certain equity offerings of the Company to finance the Transaction. 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. The net proceeds of the issuance reduced the commitments under the Term Loan Facility to $1.08 billion. The Company expects to further reduce the Commitments through additional financings, possibly to zero, prior to the closing date of the Transaction or the scheduled maturity of the Seller Note Facility, as applicable, but there can be no assurance such financings will occur and any such expectation is subject to market conditions.

The Company is subject to certain customary fees with respect to the Term Loan Facility and the Bridge Facility. Interest on borrowings under the Term Loan Facility or the Bridge Facility would accrue at one of two rates, at the option of the Company: Term SOFR plus an applicable margin of 1.125% to 1.750%, or a base rate (at least as great as one-month Term SOFR plus 1.0%) plus an applicable margin of 0.125% to 0.750%. In each case, the applicable margin would depend on the Company’s credit ratings (at current ratings, the applicable margin would be 1.500% for Term SOFR loans and 0.500% for base rate loans). With respect to the Term Loan Facility, the Company will pay a fee on the 270th day after the funding date in an amount equal to 0.025% of the principal amount of any loans outstanding under such facility at the close of business on that date. With respect to the Bridge Facility, the applicable margin would increase by an additional 0.25% on each of the 90th, 180th and 270th day after the funding date for any loans outstanding under the Bridge Facility. Any borrowings under the Term Loan Facility or the Bridge Facility would mature 364 days from the funding date, which, for the Term Loan Facility, would be on or around the closing date of the Transaction and, for the Bridge Facility, would be on or around the scheduled maturity of the Seller Note Facility.

The availability of borrowings under the Term Loan Facility and the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of these types. Any definitive financing documentation for the Term Loan Facility or the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of these types. The Company expects to execute permanent financing prior to the respective funding dates of the Term Loan Facility and the Bridge Facility, such that borrowings under the facilities would not be incurred. There can be no assurance, however, such permanent financing will occur and any such expectation is subject to market conditions.

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 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. The Credit Agreement provides a $1.3 billion unsecured committed revolving credit facility, an increase of $300 million from the prior agreement. The facility has an initial maturity date of March 27, 2031. The Company may use the proceeds of loans under the Credit Agreement (a) to repay its (i) obligations under its commercial paper program, (ii) other short term credit facilities and (iii) maturing long-term debt obligations, (b) for general corporate purposes of the Company and its subsidiaries in the ordinary course of business, including for working capital, capital expenditure and other lawful corporate purposes and (c) to fund certain permitted acquisitions, including the CenterPoint Ohio acquisition, and other investments.

The total amount available to be issued under the Company’s commercial paper program is $500 million. The commercial paper program is backed by the Credit Agreement. The Company also has two uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed

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on an annual basis. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

On February 14, 2024, the Company entered into a term loan agreement (the “Term Loan Agreement”) with six of the 12 banks that 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.

The Credit Agreement provides that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company’s total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at March 31, 2026, $398.5 million was added back to the Company’s total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company’s consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: all unrealized gains or losses on commodity-related derivative financial instruments, and up to $10 million in unrealized gains or losses on other derivative financial instruments. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. Finally, for purposes of calculating the debt to capitalization ratio, the Company’s $1.2 billion obligation under the Seller Note Facility, which is to be incurred at the closing of the Transaction, will be excluded from the definition of consolidated indebtedness upon such time and to the extent that the Company, in accordance with the Seller Note Agreement, deposits with a paying agent funds for defeasance of the Seller Note Facility.

At March 31, 2026, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement, was 0.37. The constraints specified in the Credit Agreement would have permitted an additional $5.26 billion in short-term and/or long-term debt to be outstanding at March 31, 2026 before the Company’s debt to capitalization ratio exceeded 0.65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $125.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $125.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

On February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.2 million and $493.5 million, respectively. The holders of the 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 7.50% on the 5.50% notes and 7.95% on the 5.95% 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. The proceeds of these debt issuances were used for general corporate purposes, including the March 6, 2025 redemptions of $450.0 million of the Company's 5.20% notes that were scheduled to mature in July 2025 and $500.0 million of the Company's 5.50% notes that were scheduled to mature in January 2026. The Company redeemed those notes for $450.8 million and $503.3 million, respectively, plus accrued interest. The remaining proceeds of the debt issuances were used

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to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of the 7.38% notes outstanding under the Company's 1974 indenture.

The Current Portion of Long-Term Debt at March 31, 2026 consisted of $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 a $300.0 million long-term delayed draw term loan with a maturity date in February 2026 that was repaid in January 2026. The Company's present liquidity position is believed to be adequate to satisfy known demands.

The Company’s embedded cost of long-term debt was 4.81% at March 31, 2026 and 4.97% at March 31, 2025.

OTHER MATTERS

In addition to the legal proceedings disclosed in Part II, Item 1 of this report, 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 or 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 normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the six months ended March 31, 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 six months ended March 31, 2026, and does not anticipate making any such contributions during the remainder of fiscal 2026.

Market Risk Sensitive Instruments

Rules adopted by the CFTC and other regulators could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions.

The authoritative guidance for fair value measurements and disclosures requires 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 March 31, 2026, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas 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.

For a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2025 Form 10-K.

Rate Matters

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

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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 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.

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. During the quarter ended March 31, 2026, Distribution Corporation recovered $2.8 million from customers. The DSIC cap has been met and the Company is unable to earn a return on incremental plant investments. The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing.

Pipeline and Storage

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.

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.

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. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources

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necessary to meet emissions targets may be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued.

For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 – Commitments and Contingencies under the heading “Environmental Matters.”

While the current federal administration has initiated efforts to roll-back and/or limit certain environmental initiatives, legislative and regulatory measures concerning climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, cap-and-invest and cap-and-trade programs, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources.

Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. In New York, the CLCPA, which was passed in 2019, mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. Statements from New York's Governor and the state's 2025 New York State Energy Plan acknowledge that the near term targets of the statute may not be achievable in the required timeframes. The NYPSC has initiated and/or modified various proceedings in an effort to help the State meet these emissions reduction targets. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions, and in December 2025 the Governor approved legislation that will require residential natural gas service applicants to pay the installation costs for the first 100 feet of facilities necessary to provide natural gas service commencing December 19, 2026. The May 2023 legislation is subject to ongoing litigation, with the parties agreeing, in November 2025, to suspend the requirements of the legislation pending resolution of appellate proceedings. In addition, the NYDEC, in conjunction with the New York State Energy Research and Development Authority, has engaged in certain efforts to develop a cap-and-invest program in the state, although issuance of certain key regulations necessary to implement the program has been delayed. In October 2025, a New York State Supreme Court judge issued an order requiring the NYDEC to promulgate regulations in accordance with the CLCPA by February 6, 2026. An appeal of that order, filed by NYDEC on November 25, 2025, stayed all proceedings to enforce the order pending resolution of the appeal. The above-enumerated initiatives could impact the Company's customer base and assets, and could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also reduce demand for natural gas and delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by federal and state administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may also provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.

Effects of Inflation

The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2026.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 8 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 11 – Regulatory Matters.

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s 2025 Form 10-K, as amended by Item 1A of Part II of the Company's Form 10-Q for the quarter ended December 31, 2025, have not materially changed.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On January 2, 2026, the Company issued a total of 5,410 unregistered shares of Company common stock to non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to the Company’s Deferred Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 541 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended March 31, 2026. The Company issued an additional 689 unregistered shares in the aggregate on January 15, 2026 pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who participate in the DCP. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933 (“Securities Act”), as transactions not involving a public offering.

Issuer Purchases of Equity Securities

(a)Represents (i) shares of common stock of the Company purchased with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, (ii) shares of common stock of the Company, if any, tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes, and (iii) shares of common stock of the Company, if any, purchased on the open market pursuant to the Company's share repurchase program. Of the 31,683 shares purchased other than through a publicly announced share repurchase program, 30,955 were purchased for the Company's 401(k) plans and 728 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.

(b)On March 8, 2024, the Company’s Board of Directors authorized the repurchase of up to $200 million of shares of the Company’s common stock. The calculation of the dollar value of shares remaining available for purchase excludes excise taxes and brokerage fees paid by the Company in connection with the repurchase program which in the aggregate totaled $1.07 million from the beginning of the program to March 31, 2026. Repurchases may be made from time to time in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. In light of the Company’s agreement to acquire CenterPoint Ohio’s natural gas utility, repurchases under the program have been suspended. The repurchase program has no expiration date.

Item 5. Other Information

Trading Arrangements

During the quarter ended March 31, 2026, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of the Company adopted or terminated any “Rule 10b5–1 trading arrangement” or any “non-Rule 10b5–1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

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Item 6. Exhibits

Exhibit Number / • Description of Exhibit / Amended and Restated Credit Agreement, dated as of March 27, 2026, among the Company, the Lenders party thereto, and PNC Bank National Association, as Administrative Agent (Exhibit 10.1, Form 8-K dated March 27, 2026)*

31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act. 31.2 Written statements of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act. 32•• Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (99) National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended March 31, 2026 and 2025. (101) Interactive data files submitted pursuant to Regulation S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three and six months ended March 31, 2026 and 2025, (ii) the Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2026 and 2025, (iii) the Consolidated Balance Sheets at March 31, 2026 and September 30, 2025, (iv) the Consolidated Statements of Cash Flows for the six months ended March 31, 2026 and 2025 and (v) the Notes to Condensed Consolidated Financial Statements. (104) Cover Page Interactive Data File (embedded within the Inline XBRL document) • Incorporated herein by reference as indicated. •• In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.

• Certain schedules and similar attachments to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish supplementally to the SEC, upon request, an unredacted copy of any schedule or attachment to this Exhibit.

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