NATIONAL FUEL GAS CO

Item 1. Financial Statements

Consolidated Statements of Income and Earnings

Reinvested in the Business

Consolidated Statements of Comprehensive Income

Consolidated Balance Sheets

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Notes to Condensed Consolidated Financial Statements

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.

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, 2024, 2023 and 2022 that are included in the Company's 2024 Form 10-K. The consolidated financial statements for the year ended September 30, 2025 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the nine months ended June 30, 2025 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2025. 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 8 – Business Segment Information.

Consolidated Statements of Cash Flows. The Statement of Cash Flows for the nine months ended June 30, 2025 and nine months ended June 30, 2024 reconciles the net increase in cash and cash equivalents, which consists solely of cash and temporary cash investments for the periods presented. The Company did not have any restricted cash at June 30, 2025, October 1, 2024, June 30, 2024 or October 1, 2023. The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be equivalents.

Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances have historically been written-off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. Starting in the quarter ended March 31, 2025, account balances are being written-off against the allowance approximately three months after the account is final billed or when it is anticipated that the receivable will not be recovered. This change in policy was initiated to better match the timing of write-offs with the recovery of uncollectible expense in rates and resulted in a one-time cumulative adjustment to the allowance during the quarter ended March 31, 2025.

Activity in the allowance for uncollectible accounts for the nine months ended June 30, 2025 and 2024 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 $12.7 million at June 30, 2025, is reduced tozero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment. In the Company’s Exploration and Production segment, property acquisition, exploration and development costs are capitalized 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 $2.32 billion and $2.28 billion at June 30, 2025 and September 30, 2024, 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 $132.6 million and $201.0 million at June 30, 2025 and September 30, 2024, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying commodity pricing (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At June 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $798.8 million. 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 impairment charge 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. The estimated future net cash flows were increased by $338.6 million for hedging under the ceiling test at June 30, 2025.

The Exploration and Production segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting. As discussed in Note 3 – Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded at December 31, 2024.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at June 30, 2025.

Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the nine months ended June 30, 2025 and 2024, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):

Reclassifications Out of Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the nine months ended June 30, 2025 and 2024 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 nine months ended June 30, 2025, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 1,126 securities and 1,097 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2025, respectively. There were 335 securities excluded as being antidilutive for the nine months ended June 30, 2024. As the Company recognized a net loss for the quarter ended June 30, 2024, in accordance with accounting guidance, all dilution associated with restricted stock units and performance shares in the amount of 567,681 shares, was excluded from the earnings per share calculation for the quarter ended June 30, 2024.

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. Refer to Note 6 – Capitalization for further discussion of the Company's share repurchase program.

Stock-Based Compensation. The Company granted 239,042 performance shares during the nine months ended June 30, 2025. The weighted average fair value of such performance shares was $55.43 per share for the nine months ended June 30, 2025. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.

The performance shares granted during the nine months ended June 30, 2025 include awards that must meet a performance goal related to either relative total return on capital over athree-year performance cycle ("ROC Performance Shares"), methane intensity and greenhouse gas emissions reductions over athree-year performance cycle ("Emissions Performance Shares") or relative total shareholder return over athree-year performance cycle ("TSR Performance Shares"). The performance goal related to the ROC Performance Shares over thethree-year performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC 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 of the ROC Performance Shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.

The performance goal related to the Emissions Performance Shares over thethree-year performance cycle consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards or exceeding the Company's 2030 goals. The number of these Emissions Performance Shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these Emissions Performance Shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.

The performance goal related to the TSR Performance Shares over thethree-year performance cycle is the Company’sthree-year total shareholder return relative to thethree-year total shareholder return of the other companies in the 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 132,352 restricted stock units during the nine months ended June 30, 2025. The weighted average fair value of such restricted stock units was $58.64 per share for the nine months ended June 30, 2025. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.

Note 2 –Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2025 and 2024, presented by type of service from each reportable segment.

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.

The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $59.0 million for the remainder of fiscal 2025; $221.9 million for fiscal 2026; $204.8 million for fiscal 2027; $154.5 million for fiscal 2028; $124.5 million for fiscal 2029; and $650.2 million thereafter.

Note 3 –Fair Value Measurements

The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2025 and September 30, 2024. 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.

The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of June 30, 2025 and 2024 (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 Exploration and Production segment.

Derivative Financial Instruments

The derivative financial instruments reported in Level 2 at June 30, 2025 and September 30, 2024 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates.

The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At June 30, 2025, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

Derivative financial instruments reported in Level 2 at June 30, 2025 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022. The terms of the purchase and sale agreement specified that the Company could receive up tothree annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated at $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The calendar 2023 and 2024 contingency periods expired with the ICE Brent Average falling below $95 per barrel each calendar year. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk-free rate, time of maturity and counterparty risk. The fair value of this contingent consideration is estimated to bezero as of June 30, 2025.

Note 4 –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.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

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

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 Exploration and Production 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 Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 6 years.

On June 30, 2022, the Company completed the sale of Seneca’s California assets. The terms of the purchase and sale agreement specified that the Company could receive up tothree annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The calendar 2023 and 2024 contingency periods expired with the ICE Brent Average falling below $95 per barrel each calendar year. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to bezero and $0.7 million at June 30, 2025 and September 30, 2024, respectively. A $0.7 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the nine months ended June 30, 2025.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2025 and September 30, 2024.

Cash Flow Hedges

For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings.

As of June 30, 2025, the Company had 427.0 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of June 30, 2025, the Company was hedging a total of $47.2 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of June 30, 2025, the Company had $44.5 million of net hedging losses after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $15.7 million of unrealized losses 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.

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 eighteen counterparties of which three are in a net gain position. On average, the Company had $0.8 million of credit exposure per counterparty in a gain position at June 30, 2025. The maximum credit exposure per counterparty in a gain position at June 30, 2025 was $2.0 million. As of June 30, 2025, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

Certain counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit that could be extended to the Company when it is in a derivative financial liability position would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At June 30, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $34.3 million according to the Company's internal model (discussed in Note 3 – Fair Value Measurements), andno hedging collateral deposits were required to be posted by the Company at June 30, 2025. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits.

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 5 –Income Taxes

The effective tax rates for the quarters ended June 30, 2025 and June 30, 2024 were 25.4% and 34.3%, respectively. The decrease in the quarterly effective income tax rate was primarily driven by the impact of the impairment of exploration and production properties under the ceiling test recorded during the quarter ended June 30, 2024, which resulted in a larger income tax benefit on a loss before income taxes during the quarter ended June 30, 2024.

The effective tax rates for the nine months ended June 30, 2025 and June 30, 2024 were 24.5% and 22.2%, respectively. The change in the year-to-date effective income tax rate was primarily driven by the impact of the impairments recorded in the quarters ended December 31, 2024 and June 30, 2024. The impairments were related to exploration and production properties under the ceiling test in both nine-month periods and an impairment of certain water disposal assets recorded in the quarter ended December 31, 2024. The impact of the impairments resulted in a smaller income tax expense on income before income taxes during each of the nine-month periods ended June 30, 2025 and June 30, 2024.

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation. Additionally, the OBBBA incorporates the immediate deduction of intangible drilling costs for taxpayers subject to the Corporate Alternative Minimum Tax. The Company is still evaluating the OBBBA and the results of such evaluations, which are not expected to have a material effect, are expected to be reflected on the Company’s Form 10-K for the year ended September 30, 2025.

Note 6 – 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.

Common Stock. Common stock share activity during the nine months ended June 30, 2025 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 March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $200 million 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 April 2025, repurchases under the program were temporarily paused. As a result, the Company expects completion of the program will extend into calendar 2026. The timing and amount of future repurchases under this program will depend on a number of factors, including but not limited to stock price, market conditions, applicable securities laws (including SEC Rule 10b-18), corporate and regulatory requirements, and capital and liquidity needs.

During the nine months ended June 30, 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $64.37 per share, for a total cost of $53.8 million (including broker fees and excise taxes). Share repurchases that settled during the nine months ended June 30, 2025 were funded with cash provided by operating activities and/or short-term borrowings. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings. The program has no fixed expiration date.

Short-Term Borrowings. The Company is a party to a syndicated Credit Agreement (as amended from time to time, the “Credit Agreement”) that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the banks in the syndicate consented to a secondone-year extension of the maturity date of the Credit Agreement, such that the Company has aggregate commitments available in the full amount of $1.0 billion through February 23, 2029. In May 2025, the total lenders under the Credit Agreement increased totwelve as a new lender joined the syndicate, assuming a portion of an existing lender's commitment.

Current Portion of Long-Term Debt. The Current Portion of Long-Term Debt at June 30, 2025 consisted of a $300.0 million long-term delayed draw term loan that matures in February 2026. The Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% notes that matured in June 2025 and $450.0 million of 5.20% notes with a maturity date in July 2025. As discussed below, the Company redeemed the $450.0 million of 5.20% notes on March 6, 2025.

Long-Term Debt. 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. In the Exploration and Production and Gathering segments, the call premiums of $0.6 million for the redemption of the 5.20% notes and $1.8 million for the redemption of the 5.50% notes, were recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2025, and in the Pipeline and Storage segment, the call premiums of $0.2 million for the 5.20% notes redeemed and $1.5 million for the 5.50% notes redeemed were recorded to Unamortized Debt Expense on the Consolidated Balance Sheet as of March 31, 2025. The remaining proceeds of the debt issuances were used to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of $50.0 million of 7.38% notes under the Company's 1974 indenture prior to the June 13, 2025 maturity date of these notes. Placing these funds in trust enabled the Company to cancel and discharge the 1974 indenture. This relieved the Company from its obligations to comply with the 1974 indenture's covenants. The funds were paid out of the trust on June 13, 2025 for the redemption of the $50.0 million of 7.38% notes, leaving no notes outstanding under the 1974 indenture.

Delayed Draw Term Loan. On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) withsix lenders, all of which are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. The current weighted average locked-in interest rate is 5.82% until mid-August 2025.

Note 7 –Commitments and Contingencies

Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

At June 30, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.7 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at June 30, 2025. The Company has a regulatory liability of $2.1 million related to environmental clean-up costs at June 30, 2025 and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal 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 8 –Business Segment Information

The Company reports financial results forfour segments: Exploration and Production, Pipeline and Storage, Gathering and Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

The data presented in the tables below reflect financial information for the segments and reconcile to consolidated amounts. As stated in the 2024 Form 10-K, the Company evaluates segment performance based on income before discontinued operations (when applicable). When this is not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2024 Form 10-K. A listing of segment assets at June 30, 2025 and September 30, 2024 is shown in the tables below.

Note 9 –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 didnot make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the nine months ended June 30, 2025, and doesnot anticipate making any such contributions during the remainder of fiscal 2025. The Company also didnot make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2025, and doesnot anticipate making any such contributions during the remainder of fiscal 2025.

Note 10 –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 athree-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 authorizes 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 revenue requirement for each year of thethree-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 April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge (“DSIC”) to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. During the quarters ended March 31, 2025 and June 30, 2025, Distribution Corporation recovered $0.2 million and $0.3 million, respectively, from customers.

FERC Jurisdiction

Supply Corporation’s rate settlement, approved June 11, 2024, provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file.

On March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. As well, the revenue sharing mechanism under the 2019 rate case settlement was adjusted and Empire committed to undertake greenhouse gas and reliability reporting. 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.