NATIONAL FUEL GAS CO

Note A —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

During the quarter ended September 30, 2025, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment intoone reportable segment. 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 M— Business Segment Information.

Regulation

The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note F — Regulatory Matters for further discussion.

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 are as follows:

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Regulatory Mechanisms

The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.

Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note F — Regulatory Matters for further discussion.

Prior to January 1, 2025, the Utility segment’s tariff in its New York rate jurisdiction contained a system modernization/improvement tracker that was intended to provide recovery for leak prone pipe replacement. Amounts calculated under the tracker that were in excess of the annual amount that could be billed to the ratepayer were deferred as a regulatory asset per commission approval. After January 1, 2025, the mechanisms are no longer effective. The regulatory asset associated with the system modernization/improvement tracker is being amortized in accordance with the most recent rate settlement.

The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNA, which covers theeight-month period from October through May. The WNA is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills.

On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNA as afive-year pilot program. The program became effective October 2023 and covers theeight-month period from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNA, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues.

The impact of customer usage fluctuations in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism (“RDM”). The “revenue per class” RDM renders the Company financially indifferent to throughput changes for residential and small non-residential customers. Delivery revenues in excess of targets established in a base rate proceeding result in a refund being credited to customers’ bills. Delivery revenues below the target result in a surcharge being added to customers’ bills. The surcharge or credit is calculated over atwelve-month period ending September 30th, and applied to customer bills annually, beginning January 1st.

In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.

Asset Acquisition and Business Combination Accounting

In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business. If the initial screening test is not met, the Company evaluates whether the set of activities is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance.

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When the Company acquires assets and liabilities deemed to be an asset acquisition, the fair value of the purchase consideration, including the transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to the individual assets and liabilities assumed based on their relative fair values. Transaction costs associated with asset acquisitions are capitalized as part of the costs of the group of assets acquired.

When the Company acquires assets and liabilities deemed to be a business combination, the acquisition method is applied. Goodwill is measured as the fair value of the consideration transferred less the net recognized fair value of the identifiable assets acquired and the liabilities assumed, all measured at the acquisition date. Transaction costs that the Company incurs in connection with a business combination, such as finders’ fees, legal fees, due diligence fees and other professional and consulting fees are expensed as incurred.

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 $2.5 billion and $2.3 billion at September 30, 2025 and 2024, respectively. For further discussion of capitalized costs, refer to Note N — Supplementary Information for Exploration and Production Activities.

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 September 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.1 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 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 book value of the exploration and production properties exceeded the ceiling at September 30, 2024, as well as at June 30, 2024. As such, the Company recognized non-cash, pre-tax ceiling test impairment charges in the Integrated Upstream and Gathering segment of $463.7 million for the year ended September 30, 2024. Deferred income tax benefits of $127.3 million related to the non-cash impairment charges were also recognized for the year ended September 30, 2024. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2025, 2024 and 2023, estimated future net cash flows were increased by $261.0 million, $428.5 million and $38.8 million, respectively.

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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 I — 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 and September 30, 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 September 30, 2025. An impairment charge related to the Northern Access Project, which is discussed at Note I — Fair Value Measurements, was recorded in the Pipeline and Storage segment at September 30, 2024. The impairment charge reduced the value of certain assets recorded in Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.

Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.

Depreciation, Depletion and Amortization

For exploration and production properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved exploration and production properties is excluded from this computation. Depreciation, depletion and amortization expense for exploration and production properties was $261.7 million, $270.6 million and $235.7 million for the years ended September 30, 2025, 2024 and 2023, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated useful lives of property in service. The following is a summary of depreciable plant by segment:

Average depreciation, depletion and amortization rates are as follows:

(1)Amounts represents depletion of exploration and production properties.

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Goodwill

The Company has recognized goodwill of $5.5 million as of September 30, 2025 and 2024 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2025, 2024 and 2023, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.

Financial Instruments

The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include natural gas price swap agreements and no cost collars and foreign currency forward contracts. The Company accounts for these instruments as cash flow hedges for which the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note I — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.

For cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues on the Consolidated Statements of Income. Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges.

Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss and changes for the years ended September 30, 2025 and 2024, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands):

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The amounts included in accumulated other comprehensive loss related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $0.4 million at both September 30, 2025 and 2024. The total amount for accumulated losses was $78.8 million and $70.9 million at September 30, 2025 and 2024, respectively.

Reclassifications Out of Accumulated Other Comprehensive Loss

The details about the reclassification adjustments out of accumulated other comprehensive loss for the years ended September 30, 2025 and 2024 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

(1)These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.

Gas Stored Underground

In the Utility segment, gas stored underground in the amount of $33.5 million is carried at lower of cost or net realizable value, on a LIFO method. Based upon the average price of spot market gas purchased in September 2025, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $18.7 million at September 30, 2025.

Unamortized Debt Expense

Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2025, the remaining weighted average amortization period for such costs was approximately 3 years.

Income Taxes

The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed.

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The Company follows the asset and liability approach in accounting for income taxes, which requires the recognition of deferred income taxes for the expected future tax consequences of net operating losses, credits and temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.

The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income (Deductions).

Consolidated Statement 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. The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for derivative financial instruments in an unrealized loss position. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

Other Current Assets

The components of the Company’s Other Current Assets are as follows:

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Other Accruals and Current Liabilities

The components of the Company’s Other Accruals and Current Liabilities are as follows:

Customer Advances

The Company, primarily in its Utility segment, has balanced billing programs whereby customers pay their estimated annual usage in equal installments over atwelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2025 and 2024, customers in the balanced billing programs had advanced excess funds of $17.2 million and $19.4 million, respectively.

Customer Security Deposits

The Company, primarily in its Utility and Pipeline and Storage segments, oftentimes requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2025 and 2024, the Company had received customer security deposits amounting to $29.9 million and $36.3 million, respectively.

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 during fiscal 2025, 2024 and/or 2023 were restricted stock units and performance shares. For fiscal 2025, 2024 and 2023, 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 3,228 securities, 569 securities and 3,888 securities excluded as being antidilutive for the years ended September 30, 2025, 2024 and 2023, respectively.

Share Repurchases

The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note H — Capitalization and Short-Term Borrowings for further discussion of the Company’s share repurchase program.

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Stock-Based Compensation

The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. For all Company stock awards, forfeitures are recognized as they occur.

Restricted stock units are subject to restrictions on vesting and transferability. 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. The restricted stock units do not entitle the participants to dividend and voting rights. 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.

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. For performance shares based on a return on capital goal and greenhouse gas emissions reductions goal, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.

Refer to Note H — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.

New Authoritative Accounting and Financial Reporting Guidance

In November 2023, the FASB issued authoritative guidance which improves reportable segment disclosure requirements, primarily through enhanced disclosures for significant segment expenses. The guidance was effective retrospectively for the Company as of September 30, 2025. As a result, the Company has enhanced its segment disclosures to include the presentation of significant costs and expenses by segment. The adoption of this authoritative guidance only affects the Company’s disclosures, with no impact to its financial condition and results of operations. All applicable disclosures have been included in Note M — Business Segment Information.

Note B —Acquisitions

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 for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the Public Utilities Commission of Ohio, Hart-Scott-Rodino review, and other customary closing conditions. The purchase price will include a combination of $1.42 billion in cash and a $1.2 billion promissory note to be issued by the Company to the Seller. The promissory note, which was part of the Seller’s desired transaction structure and was incorporated

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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”) and additional banks, 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 the purchase price of $2.62 billion.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC (“SWN”) for total consideration of $124.8 million. The purchase price, which reflects an effective date of January 1, 2023, was reduced for production revenues less expenses that were retained by SWN from the effective date to the closing date. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment. The following is a summary of the asset acquisition in thousands:

Note C —Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company’s revenues for the years ended September 30, 2025, 2024 and 2023, presented by type of service from each reportable segment.

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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.

Integrated Upstream and Gathering Segment Revenue

The Company’s Integrated Upstream and Gathering segment records revenue from the sale of the natural gas and oil that it produces, which means that revenue is recorded based on the actual amount of natural gas or oil that is delivered to a pipeline, or upon pick-up in the case of oil, netted down for the Company’s ownership interest. Substantially all Integrated Upstream and Gathering segment production consists of natural gas production from the Appalachian region of the United States. If a production imbalance occurs between what

-82- was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance. The sales contracts generally require the Company to deliver a specific quantity of a commodity per day for a specific number of days at a price that is either fixed or variable and considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery.

The transaction price for the sale of natural gas and oil is contractually agreed upon based on prevailing market pricing (primarily tied to a market index with certain adjustments based on factors such as delivery location and prevailing supply and demand conditions) or fixed pricing. The Company allocates the transaction price to each performance obligation on the basis of the relative standalone selling price of each distinct unit sold. Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract. The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Integrated Upstream and Gathering segment as specified by the “invoice practical expedient” (the amount that the Integrated Upstream and Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. The contracts typically require payment within 30 days of the end of the calendar month in which the natural gas and oil is delivered.

The Company’s Integrated Upstream and Gathering segment also provides gathering and processing services in the Appalachian region of Pennsylvania. The primary performance obligation associated with the Integrated Upstream and Gathering segment’s gathering and processing services is to deliver gathered natural gas volumes from producers’ wells, into interstate pipelines at contractually agreed upon per unit rates. This obligation is satisfied over time. The performance obligation is satisfied based on the passage of time and meter reads, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the contracted volumetric rate, indicates the value to the customer, and is used for revenue recognition purposes by the Integrated Upstream and Gathering segment as specified by the “invoice practical expedient” (the amount that the Integrated Upstream and Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 10 th day after the invoice is received.

The Company uses derivative financial instruments to manage commodity price risk in the Integrated Upstream and Gathering segment related to sales of the natural gas that it produces. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.

Pipeline and Storage Segment Revenue

The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services in New York and Pennsylvania at tariff-based rates regulated by the FERC. Customers secure their own gas supply and the Pipeline and Storage segment provides transportation and/or storage services to move the customer-supplied gas to the intended location, including injections into or withdrawals from the storage field. This performance obligation is satisfied over time. The rate design for the Pipeline and Storage segment’s customers generally includes a combination of volumetric or commodity charges as well as monthly “fixed” charges (including charges commonly referred to as capacity charges, demand charges, or reservation charges). These types of fixed charges represent compensation for standing ready over the period of the month to deliver quantities of gas, regardless of whether the customer takes delivery of any quantity of gas. The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.

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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: $228.0 million for fiscal 2026; $214.1 million for fiscal 2027; $162.7 million for fiscal 2028; $129.7 million for fiscal 2029; $122.7 million for fiscal 2030; and $529.1 million thereafter.

Utility Segment Revenue

The Company’s Utility segment records revenue for natural gas sales and natural gas transportation services in western New York and northwestern Pennsylvania at tariff-based rates regulated by the NYPSC and the PaPUC, respectively. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment. The Utility segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Utility segment’s tariffs allow customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled withinone year.

Utility Segment Alternative Revenue Programs

As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and conservation have on margin. The NYPSC and PaPUC have also authorized additional alternative revenue programs that adjust billings for the effects of broad external factors or to compensate the Company for demand-side management initiatives. These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to customers within 24 months of the annual reconciliation period.

Note D —Leases

The Company follows authoritative guidance regarding lease accounting, which requires entities that lease the use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, including leases classified as operating leases. The Company has elected to apply the following practical expedients provided in the authoritative guidance:

1. An election not to apply the recognition requirements in the authoritative guidance to short-term leases (a lease that at commencement date has a lease term of one year or less);

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2. A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset-class).

Nature of Leases

The Company primarily leases building space and drilling rigs, and on a limited basis, compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the authoritative guidance. The Company did not have any material finance leases as of September 30, 2025 or September 30, 2024. The Company also does not have any material arrangements where the Company is the lessor.

Buildings and Property

The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Integrated Upstream and Gathering segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range fromone month tofourteen years. Most building leases include one or more options to renew, generally at the Company’s sole discretion, with renewal terms that can extend the lease terms fromone year tosixteen years. Renewal options are included in the lease term if they are reasonably certain to be exercised. The agreements do not contain any material restrictive covenants.

Drilling Rigs

The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania. Seneca’s drilling rig arrangements are structured with a non-cancelable primary term ofone year or less. Upon mutual agreement with the contractor, Seneca has the option to extend contracts with amended terms and conditions, including a renegotiated day rate fee.

Drilling rig lease costs are capitalized as part of natural gas properties on the Consolidated Balance Sheet when incurred.

Compressor Equipment

The Company enters into contracts for compressor services with third parties primarily to support its gathering system in Pennsylvania. The primary non-cancelable terms of the Company’s compressor equipment leases range from 3 months to 5 years. Most compressor equipment leases include one or more options to renew or to continue past the primary term on a month-to-month basis, generally at the Company’s sole discretion. Renewal options are included in the lease term if they are reasonably certain to be exercised.

Significant Judgments

Lease Identification

The Company uses judgment when determining whether or not an arrangement is or contains a lease. A contract is or contains a lease if the contract conveys the right to use an explicitly or implicitly identified asset that is physically distinct and the Company has the right to control the use of the identified asset for a period of time. When determining right of control, the Company evaluates whether it directs the use of the asset and obtains substantially all of the economic benefits from the use of the asset.

Discount Rate

The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability. In the absence of a rate of interest that is readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each

-85- lease. The IBR reflects the rate of interest that the Company would pay on the lease commencement date to borrow an amount equal to the lease payments on a collateralized basis over a similar term in similar economic environments.

Firm Transportation and Storage Contracts

The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers. The Company’s firm capacity contracts with third party shippers do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance.

Gas Leases

The authoritative guidance does not apply to leases to explore for or use natural gas resources, including the right to explore for those resources and rights to use the land in which those resources are contained. As such, the Company has concluded that its gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.

Amounts Recognized in the Financial Statements

Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of exploration and production properties under the full cost method of accounting as well as certain equipment leases related to construction projects, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the Company’s total operating lease costs (in thousands):

(1)Variable lease payments that are not dependent on an index or rate are not included in the lease liability.

(2)Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

(3)Lease costs relating to drilling rig leases that are capitalized as part of exploration and production properties under full cost pool accounting as well as certain equipment leases used on construction projects.

Right-of-use assets and lease liabilities are recognized at the commencement date of a leasing arrangement based on the present value of lease payments over the lease term. The weighted average remaining lease term was 5.0 years and 5.7 years as of September 30, 2025 and 2024, respectively. The weighted average discount rate was 5.65% and 5.68% as of September 30, 2025 and 2024, respectively.

The Company’s right-of-use operating lease assets are reflected as Deferred Charges on the Consolidated Balance Sheet. The corresponding operating lease liabilities are reflected in Other Accruals and Current Liabilities (current) and Other Liabilities (noncurrent). Short-term leases that have a lease term of one year or less are not recorded on the Consolidated Balance Sheet.

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The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands):

Cash paid for lease liabilities, reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $14.0 million and $12.7 million for the years ended September 30, 2025 and 2024, respectively. The Company didnot record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2025 or 2024.

The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2025 (in thousands):

Note E —Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.

The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Integrated Upstream and Gathering segment’s natural gas production wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool). Asset retirement obligation costs

-87- have also been recorded in the Integrated Upstream and Gathering segment for certain costs connected with the retirement of the gathering lines and other components of the gathering system, including storage tanks. These costs are primarily related to the capping and purging of pipe, which are generally abandoned in place when retired.

In addition to the asset retirement obligation recorded in the Integrated Upstream and Gathering segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. Asset retirement obligation costs related to storage tanks have been recorded in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains, services and other components of the pipeline system in the Utility segment and the transmission mains and other components in the pipeline system in the Pipeline and Storage segment. The retirement costs within the distribution and transmission systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.

During fiscal 2024 and fiscal 2025, the Company experienced an increase in plugging and abandonment costs associated with the Integrated Upstream and Gathering segment’s natural gas production wells and the Pipeline and Storage segment’s natural gas storage wells, which contributed to an increase in the asset retirement obligation in both years. The increase in plugging and abandonment costs is the primary component of the Revisions of Estimates amount for fiscal 2024 and fiscal 2025 shown in the table below.

The following is a reconciliation of the change in the Company’s asset retirement obligations:

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Note F —Regulatory Matters

Regulatory Assets and Liabilities

The Company has recorded the following regulatory assets and liabilities:

(1)New York Rate Case Levelization and Tracking Mechanisms were approved in accordance with Distribution Corporation’s New York rate settlement on December 19, 2024, as discussed below. The mechanisms include: (a) levelization deferral of $17.8 million which relates to a volumetric surcredit within the Company’s delivery adjustment charge that minimizes customer bill impacts, (b) uncollectible expense tracker of $9.8 million, which tracks and reconciles the actual uncollectible expense to the amounts recovered in base rates and, (c) property tax tracker of $1.1 million, which represents the amount deferred between actual property taxes incurred and the level included in customer rates.

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If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs.

Cost of Removal Regulatory Liability

In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note E — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from customers that will be used in the future to fund asset retirement costs.

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. These revenue requirement increases are being reflected in customer bills on a levelized basis over thethree-year rate plan. 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.

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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 year ended September 30, 2025, Distribution Corporation recovered $0.9 million from customers.

FERC Jurisdiction

Supply Corporation’s rate settlement was approved June 11, 2024 with rates effective February 1, 2024, and provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file.

On March 17, 2025, FERC approved an amendment to Empire’s 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire’s revenues on a yearly basis by approximately $0.5 million. Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031.

Note G —Income Taxes

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:

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 related to the Integrated Upstream and Gathering segment, domestic research cost expensing, and the business interest expense limitation. Additionally, the OBBBA permits the inclusion of intangible drilling cost deductions in the calculation of the Corporate Alternative Minimum Tax. The Company has evaluated the OBBBA. The results of such evaluations are reflected within the Company’s financial statements and the impacts were not material.

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Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:

Significant components of the Company’s deferred tax liabilities and assets were as follows:

A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. The Company, at each reporting date, assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to the likelihood of the realization of the deferred tax assets. As of September 30, 2025, the Company has determined that there is sufficient positive evidence to conclude that it is more likely than not that the deferred tax assets will be realized.

Tax carryforwards available at September 30, 2025, were as follows:

Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $306.3 million and $305.6 million at September 30, 2025 and 2024, respectively. Also, regulatory assets representing future

-92- amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amounted to $89.2 million and $80.1 million at September 30, 2025 and 2024, respectively.

The Company is in the Bridge Plus Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2025. This phase requires the submission of supplemental documentation to the IRS and allows the IRS to conduct a pre-filing review of material tax positions and to provide preliminary feedback prior to the filing of the Company’s federal income tax return. The CAP program is intended for taxpayers with a low risk of non-compliance who are cooperative and transparent with few, if any, material issues that require resolution. The federal statute of limitations remains open for fiscal 2022 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries have state statutes of limitations that generally expire between three to four years from the date of filing of the income tax return. Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which time the statute of limitation begins. The Company hasno unrecognized tax benefits as of September 30, 2025, 2024, or 2023.

The IRS released guidance on April 14, 2023, providing a natural gas transmission and distribution property safe harbor method of accounting (“NGSH method”) that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized or be allowable as deductions for repairs. The Company elected this change in tax accounting method for Distribution Corporation with its fiscal 2023 consolidated tax return filing. The Company elected this same change in tax accounting method for Supply Corporation with its fiscal 2024 consolidated tax return filing. The financial statements herein reflect the amounts of what is intended to be treated as a repair for tax purposes rather than being capitalized and have been recorded in Income Tax Expense.

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Note H —Capitalization and Short-Term Borrowings

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

The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent

-94- agent. During 2025, the Company didnot issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan or the Company’s 401(k) plans.

During 2025, the Company issued 128,028 original issue shares of common stock for restricted stock units that vested and 108,799 original issue shares of common stock for performance shares that vested. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During 2025,71,394 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company’s Deferred Compensation Plan for Directors and Officers (the “DCP”), as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 27,698 original issue shares of common stock during 2025. In addition, the Company issued 8,691 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment features of the Company’s DCP during 2025.

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.

During 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 2025 were funded with cash provided by operating activities and/or short-term borrowings. In light of the Company’s agreement to acquire CenterPoint Ohio’s natural gas utility, repurchases under the program have been suspended. The program has no fixed expiration date.

Stock Award Plans

The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares.

Stock-based compensation expense for the years ended September 30, 2025, 2024 and 2023 was approximately $17.2 million, $19.8 million and $18.6 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2025, 2024 and 2023 was approximately $2.2 million, $2.5 million and $2.4 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million was capitalized under these rules during each of the years ended September 30, 2025, 2024 and 2023. The tax benefit related to stock-based compensation exercises and vestings was $0.1 million for the year ended September 30, 2025.

Pursuant to registration statements for these plans, there were 3,711,717 shares available for future grant at September 30, 2025. These shares include shares available for future options, SARs, restricted stock and performance share grants.

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Restricted Stock Units

Transactions for 2025 involving nonperformance-based restricted stock units for all plans are summarized as follows:

The Company also granted 220,778 and 133,173 nonperformance-based restricted stock units during the years ended September 30, 2024 and 2023, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2024 and 2023 was $42.44 per share and $58.10 per share, respectively. As of September 30, 2025, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $8.3 million, which will be recognized over a weighted average period of 2.4 years.

Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2025 will lapse as follows: 2026 —149,295 units; 2027 —126,726 units; 2028 —78,002 units; 2029 —18,928 units; 2030 —11,258 units; and 45,038 units thereafter.

Performance Shares

Transactions for 2025 involving performance shares for all plans are summarized as follows:

The Company also granted 361,729 and 202,259 performance shares during the years ended September 30, 2024 and 2023, respectively. The weighted average grant date fair value of such performance shares granted in 2024 and 2023 was $44.23 per share and $64.28 per share, respectively. As of September 30, 2025, unrecognized compensation expense related to performance shares totaled approximately $11.4 million, which will be recognized over a weighted average period of 2.3 years. Vesting restrictions for the outstanding performance shares at September 30, 2025 will lapse as follows: 2026 —174,071 shares; 2027 —243,279 shares; 2028 —178,825 shares; 2029 -zero; 2030 -11,256; and 45,044 shares thereafter.

The performance shares granted during the years ended September 30, 2025, 2024 and 2023 include awards that must meet a performance goal related to either relative return on capital over athree-year orfive-year performance cycle (“ROC Performance Shares”), methane intensity and greenhouse gas emissions reductions over athree-year performance cycle (“Emissions Performance Shares”) or relative shareholder return over athree-year orfive-year performance cycle (“TSR Performance Shares”).

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The performance goal over the respective performance cycles for the ROC Performance Shares granted during 2025, 2024 and 2023 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 over the respective performance cycles for the Emissions Performance Shares granted during 2025, 2024 and 2023 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 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 over the respective performance cycles for the TSR Performance Shares granted during 2025, 2024 and 2023 is the Company’sthree-year (orfive-year) total shareholder return relative to thethree-year (orfive-year) total shareholder return of the other companies in the Report Group. Three-year (orfive-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. In calculating the fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR Performance Shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR Performance Shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following weighted average assumptions were used in estimating the fair value of the TSR Performance Shares at the date of grant:

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Redeemable Preferred Stock

As of September 30, 2025, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.

Long-Term Debt

The outstanding long-term debt is as follows:

(1)The Medium-Term Notes and Notes are unsecured.

(2)The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.

(3)The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes, $500.0 million of 2.95% notes and $300.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes and $500.0 million of 5.95% 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 in 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.

(4)The interest rate on the delayed draw term loan, which is based on a weighted average SOFR interest rate, was 5.62% and 6.71% as of September 30, 2025 and September 30, 2024, respectively. The current weighted average locked-in interest rate is 5.43% until mid-December 2025.

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(5)Current Portion of Long-Term Debt at September 30, 2025 consisted of a $300.0 million long-term delayed draw term loan that matures in February 2026. Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% medium-term notes and $450.0 million of 5.20% notes.

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 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 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.

The Company entered into its existing term loan agreement (the “Term Loan Agreement”) on February 14, 2024, withsix of the 12 banks that 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%.

As of September 30, 2025, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $300.0 million in 2026, $600.0 million in 2027, $300.0 million in 2028, zero in 2029, $500.0 million in 2030, and $1.0 billion thereafter.

Short-Term Borrowings

The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. 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 number of lenders under the Credit Agreement increased totwelve as a new lender joined the syndicate, assuming a portion of an existing lender’s commitment.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement. The Company also has 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 on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

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At September 30, 2025, the Company had outstanding commercial paper of $150.2 million with a weighted average interest rate on the commercial paper of 4.64%. At September 30, 2024, the Company had outstanding commercial paper of $90.7 million with a weighted average interest rate on the commercial paper of 5.30%. The Company didnot have any outstanding short-term notes payable to banks at September 30, 2025 and 2024.

Debt Restrictions

Both the Credit Agreement and the Term Loan Agreement provide 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, not to exceed $400 million. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at September 30, 2025, $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 and the Term Loan 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. At September 30, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements was 0.45. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $3.61 billion in short-term and/or long-term debt to be outstanding at September 30, 2025 before the Company’s debt to capitalization ratio exceeded 0.65.

The Company’s present liquidity position is believed to be adequate to satisfy known demands. 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 and the Term Loan Agreement each contain 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 or Term Loan Agreement, as applicable. 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 $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

Note I —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 September 30, 2025 and 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.

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(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 September 30, 2025, 2024 and 2023 (in thousands):

Water Disposal Assets

In exploring the potential sale of certain water disposal assets during both the quarters ended December 31, 2024 and September 30, 2024, the Company determined that the fair market value of such assets was less than the recorded net book value resulting in impairment charges of $33.5 million and $9.4 million, respectively, 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.

Northern Access Project

On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Substantial litigation ensued over the next several years concerning various federal and state authorizations for the project, with the majority of project development activities suspended pending resolution. These legal actions included, most recently, an appeal of FERC’s June 2022 order granting Supply Corporation and Empire an extension of time to construct the project through December 31, 2024. In March 2024, the U.S. Court of Appeals for the D.C. Circuit issued an order affirming FERC’s extension of time, with such order final as of late June 2024. Upon resolution of the extensive litigation, Supply Corporation and Empire began to assess next steps for the project, including a review of the status of necessary federal and state authorizations, as well as potential changes in expected capital expenditures and the related transportation rates that Supply Corporation and Empire needed to support the project. As a result of this review, and in accordance with the precedent agreements between the respective parties, Supply Corporation and Empire sent notifications to Seneca, the sole shipper for the project, indicating their intent to increase the project’s firm transportation rates to account for the anticipated increase in capital expenditures to complete the project. Upon receipt, Seneca indicated it was unwilling to accept the revised transportation rates and intended to terminate the precedent agreements for the project. The precedent agreements were subsequently terminated on October 16, 2024. Accordingly, the Company determined it would no longer pursue construction of the Northern Access project and took an impairment charge of $46.1 million at September 30, 2024.

Derivative Financial Instruments

At September 30, 2025, the derivative financial instruments reported in Level 2 consist of 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

-102- 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 September 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 September 30, 2024 also includes the contingent consideration associated with the sale of the Integrated Upstream and Gathering segment’s California assets on June 30, 2022. The fair value of this contingent consideration waszero at September 30, 2025. 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.

Note J —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:

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.

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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, as discussed in Note F — Regulatory Matters, 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 does not typically exceed 5 years, and the foreign currency forward contracts also do not 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 September 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 September 30, 2025, the Company had 414.3 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of September 30, 2025, the Company was hedging a total of $44.1 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of September 30, 2025, the Company had $19.9 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $35.7 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The remaining unrealized loss will be reclassified into the Consolidated Statement of Income in subsequent periods.

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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 eighteen counterparties of which thirteen are in a net gain position. On average, the Company had $3.0 million of credit exposure per counterparty in a gain position at September 30, 2025. The maximum credit exposure per counterparty in a gain position at September 30, 2025 was $8.7 million. As of September 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 September 30, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $1.9 million according to the Company’s internal model (discussed in Note I — Fair Value Measurements) andno hedging collateral deposits were required to be posted by the Company at September 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.

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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 K —Retirement Plan and Other Post-Retirement Benefits

The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan). The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $7.1 million, $6.5 million and $5.7 million for the years ended September 30, 2025, 2024 and 2023, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $9.8 million, $9.0 million and $8.2 million for the years ended September 30, 2025, 2024 and 2023, respectively.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.

The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations.

The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other post-retirement benefit assets (i.e. the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date.

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Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2025, 2024 and 2023.

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(1)Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.

The Net Periodic Benefit Cost (Income) in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.

In addition to the Retirement Plan discussed above, the Company also hasnon-qualified benefit plans that cover a group of management employees whose income level has exceeded certain IRS thresholds or who have been designated as participants by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were $4.6 million, $9.5 million and $8.3

-108- million in 2025, 2024 and 2023, respectively. The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $50.9 million, $57.5 million and $58.5 million at September 30, 2025, 2024 and 2023, respectively. The projected benefit obligations for the plans were $58.4 million, $66.0 million and $69.5 million at September 30, 2025, 2024 and 2023, respectively. At September 30, 2025, $11.6 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $46.8 million is recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2024, $14.1 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $51.9 million was recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2023, $13.1 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $56.4 million was recorded in Other Liabilities on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 4.86%,4.71% and 5.91% as of September 30, 2025, 2024 and 2023, respectively and the weighted average rate of compensation increase for these plans was 8.00% as of September 30, 2025, 2024 and 2023.

The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2025, as well as the changes in such amounts during 2025, are presented in the table below:

(1)Amounts presented are shown before recognizing deferred taxes.

(2)Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial Loss amounts presented in the Change in Benefit Obligation.

In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2025, the Company recorded a $23.8 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $10.3 million (pre-tax) decrease to Accumulated Other Comprehensive Income.

The effect of the discount rate change for the Retirement Plan in 2025 was to decrease the projected benefit obligation of the Retirement Plan by $21.4 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2025 by $4.2 million. The effect of the discount rate change for the Retirement Plan in 2024 was to increase the projected benefit obligation of the Retirement Plan by $69.6

-109- million. The effect of the discount rate change for the Retirement Plan in 2023 was to decrease the projected benefit obligation of the Retirement Plan by $28.4 million.

The Company didnot make any cash contributions to the Retirement Plan during the year ended September 30, 2025. The Company doesnot expect to make any contributions to the Retirement Plan in 2026.

The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $67.6 million in 2026; $66.9 million in 2027; $66.1 million in 2028; $65.1 million in 2029; $64.0 million in 2030; and $297.8 million in the five years thereafter.

The effect of the discount rate change in 2025 was to decrease the other post-retirement benefit obligation by $9.9 million. The health care cost trend rates were updated, which increased the other post-retirement benefit obligation in 2025 by $18.2 million. Other actuarial experience increased the other post-retirement benefit obligation in 2025 by $8.8 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

The effect of the discount rate change in 2024 was to increase the other post-retirement benefit obligation by $28.1 million. The healthcare cost trend rates were updated, which increased the other post-retirement benefit obligation in 2024 by $25.2 million. Other actuarial experience increased the other post-retirement benefit obligation in 2024 by $1.2 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

The effect of the discount rate change in 2023 was to decrease the other post-retirement benefit obligation by $10.7 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2023 by $0.4 million. The health care cost trend rates were updated, which increased the other post-retirement benefit obligation in 2023 by $3.2 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2023 by $12.9 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):

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Assumed health care cost trend rates as of September 30 were:

(1)It was assumed that this rate would gradually decline to 4% by 2050.

(2)It was assumed that this rate would gradually decline to 4% by 2049.

(3)It was assumed that this rate would gradually decline to 4% by 2048.

The Company made direct payments of $0.6 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2025. The Company didnot make any cash contributions to its VEBA trusts during the year ended September 30, 2025, and doesnot expect to make any contributions to its VEBA trusts in 2026.

Investment Valuation

The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note I — Fair Value Measurements for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.

The inputs or methodologies used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 2025 and 2024, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall, based on the lowest level input that is significant to the fair value measurement in its entirety (dollars in thousands):

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(1)Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.

(2)Global Equities are comprised of collective trust funds.

(3)Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.

(4)International Fixed Income securities are comprised mostly of corporate/government bonds.

(5)Real Estate consists of investments held in a collective trust fund and a partnership.

(6)Reflects the authoritative guidance related to investments measured at net asset value (NAV).

(7)Domestic Fixed Income securities include $6.2 million and $8.5 million of derivative instruments used as part of the Company’s overall liability-driven investment strategy as a way to assist in matching the duration of the assets of the Retirement Plan investments with its liability to plan participants as of September 30, 2025 and September 30, 2024, respectively.

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(1)Reflects the authoritative guidance related to investments measured at net asset value (NAV).

The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

For the years ended September 30, 2025 and September 30, 2024, there were no transfers from Level 1 to Level 2. For the years ended September 30, 2025 and September 30, 2024, there were no assets or liabilities measured at fair value and classified as Level 3.

The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.10% (Retirement Plan) and 6.10% (other post-retirement benefits), effective for fiscal 2026. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.

The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trust, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity. The actual asset allocations as of September 30, 2025 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets in conjunction with the Company’s liability driven investment strategy. Given the level of the VEBA trust and 401(h) assets in relation to the Other Post-Retirement Benefits, the majority of those assets are and will remain in fixed income securities.

Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.

The Company determines the service and interest cost components of net periodic benefit cost using the spot rate approach, which uses individual spot rates along the yield curve that correspond to the timing of each

-113- benefit payment in order to determine the discount rate. The individual spot rates along the yield curve are determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile are excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities.

Note L —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 September 30, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.2 million. The Company’s liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2025. The Company has a regulatory liability of $1.8 million related to environmental clean-up costs at September 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, in its Utility segment and Integrated Upstream and Gathering segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $236.6 million in 2026, $75.8 million in 2027, $113.8 million in 2028, $123.2 million in 2029, $135.2 million in 2030 and $900.1 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.

The Company, in its Pipeline and Storage segment, Integrated Upstream and Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. As of September 30, 2025, the future contractual commitments related to the system modernization and expansion projects are $58.1 million in 2026, $9.2 million in 2027, $5.6 million in 2028, $4.4 million in 2029, $4.5 million in 2030 and $4.6 million thereafter.

The Company, in its Integrated Upstream and Gathering segment, has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. The future contractual commitments are $180.8 million in 2026 and $25.9 million in 2027. There are no contractual commitments extending beyond 2027.

In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved in other regulatory and litigation matters arising in the normal course of business. These other regulatory and litigation matters may include, for example, tax, regulatory or other governmental audits, inspections, investigations, negligence claims 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

-114- 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 M —Business Segment Information

In the Company’s 2024 Form 10-K and its Form 10-Q’s for the first three quarters of 2025, the Company reported 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 as well as regulatory environment. During the quarter ended September 30, 2025, the president and chief executive officer, who is the chief operating decision maker (CODM), determined that the Exploration and Production segment and Gathering segment should be treated asone operating segment. The CODM made this decision to provide more clarity for management and investors as to the interdependence of both Seneca and Midstream Company in bringing Appalachian natural gas to market. As a result of this decision, during the quarter ended September 30, 2025, the CODM began reviewing financial information of these three segments: Integrated Upstream and Gathering, Pipeline and Storage, and Utility. As a result, the Company is now reporting financial results for these three segments. Prior year segment information shown below has been recast to reflect this change in presentation.

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 in the 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 natural gas marketers and exploration and production companies (including Seneca) from natural gas 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 reconciliations to consolidated amounts. The CODM uses net income (loss) by segment, or income (loss) by segment before discontinued operations when applicable, to assess performance and allocate capital and other resources, considering actual-to-budget and actual-to-prior year variances on a monthly basis when making such decisions. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable.

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(1)All Revenue from External Customers originated in the United States.

(2)Revenue from one customer of the Company’s Integrated Upstream and Gathering segment, exclusive of hedging losses transacted with separate parties, represented approximately $258 million of the Company’s consolidated revenue for the year ended September 30, 2025. This one customer was also a customer of the Company’s Pipeline and Storage segment, accounting for an additional $16 million of the Company’s consolidated revenue for the year ended September 30, 2025.

(3)Revenue from one customer of the Company’s Integrated Upstream and Gathering segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million of the Company’s consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company’s Pipeline and Storage segment, accounting for an additional $14 million of the Company’s consolidated revenue for the year ended September 30, 2023.

(4)The Company considers this line to be a significant expense.

(5)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.

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Note N —Supplementary Information for Exploration and Production Activities (unaudited, except for Capitalized Costs Relating to Exploration and Production Activities)

The Company follows authoritative guidance related to exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using 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.

The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about exploration and production activities and related SEC authoritative guidance.

Capitalized Costs Relating to Exploration and Production Activities

(1)Includes asset retirement costs of $233.9 million and $175.2 million at September 30, 2025 and 2024, respectively.

Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. 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. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2030. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2027. Following is a summary of costs excluded from amortization at September 30, 2025:

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Costs Incurred in Property Acquisition, Exploration and Development Activities

(1)Amounts for 2025, 2024 and 2023 include capitalized interest ofzero, $0.1 million andzero respectively.

(2)Amounts for 2025, 2024 and 2023 include capitalized interest ofzero, $0.7 million and $0.1 million, respectively.

For the years ended September 30, 2025, 2024 and 2023, the Company spent $246.3 million, $305.6 million and $342.0 million, respectively, developing proved undeveloped reserves.

Results of Operations for Producing Activities

(1)There wereno revenues from sales to affiliates for all years presented.

(2)Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments.

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Reserve Quantity Information

The Company’s proved reserve estimates are prepared by the Company’s petroleum engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of June 25, 2019. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.

The Company’s Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company’s reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 15 years of Petroleum Engineering experience with independent oil and gas companies, licensure as a Professional Engineer and is a member of the Society of Petroleum Engineers.

The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company’s internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.

All of the Company’s reserve estimates are audited annually by Netherland, Sewell & Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2019 and with over 6 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2025 and did not identify any problems which would cause it to take exception to those estimates.

The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company’s and competitors’ wells. Geophysical data includes data from the Company’s wells, third-party wells, published documents and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.

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(1)Extensions and discoveries include 163 Bcf (during 2023),230 Bcf (during 2024) and 0 Bcf (during 2025), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 507 Bcf (during 2023),372 Bcf (during 2024) and 633 Bcf (during 2025), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

(2)Production includes 190,290 MMcf (during 2023),235,955 MMcf (during 2024) and 209,379 MMcf (during 2025), from Marcellus Shale fields. Production includes 180,750 MMcf (during 2023),154,701 MMcf (during 2024) and 215,681 MMcf (during 2025), from Utica Shale fields.

The Company’s proved undeveloped (PUD) reserves increased from 1,267 Bcfe at September 30, 2024 to 1,316 Bcfe at September 30, 2025. PUD reserves in the Utica Shale increased from 925 Bcfe at September 30, 2024 to 1,119 Bcfe at September 30, 2025. PUD reserves in the Marcellus Shale decreased from 342 Bcfe at September 30, 2024 to 197 Bcfe at September 30, 2025. The Company’s total PUD reserves were 26.4% of total proved reserves at September 30, 2025, down from 26.7% of total proved reserves at September 30, 2024.

The Company’s PUD reserves increased from 985 Bcfe at September 30, 2023 to 1,267 Bcfe at September 30, 2024. PUD reserves in the Utica Shale increased from 873 Bcfe at September 30, 2023 to 925 Bcfe at September 30, 2024. PUD reserves in the Marcellus Shale increased from 112 Bcfe at September 30,

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2023 to 342 Bcfe at September 30, 2024. The Company’s total PUD reserves were 26.7% of total proved reserves at September 30, 2024, up from 21.7% of total proved reserves at September 30, 2023.

The increase in PUD reserves in 2025 of 49 Bcfe is a result of 473 Bcfe in new PUD reserve additions. These additions were partially offset by 399 Bcfe in PUD conversions to developed reserves (145 Bcfe from the Marcellus Shale and 254 Bcfe from the Utica Shale),18 Bcfe in PUD reserves removed forone PUD location due to schedule and pad layout changes and 7 Bcfe for adjustments to remaining PUD reserves.

The increase in PUD reserves in 2024 of 282 Bcfe is a result of 602 Bcfe in new PUD reserve additions and 76 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 291 Bcfe in PUD conversions to developed reserves (all Utica Shale), and 105 Bcfe in PUD reserves removed fornine PUD locations due to schedule and pad layout changes.

The Company invested $246 million during the year ended September 30, 2025 to convert 399 Bcfe (415 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 31% of the net PUD reserves recorded at September 30, 2024. The Company developed 27 of 73 PUD locations in 2025.

The Company invested $306 million during the year ended September 30, 2024 to convert 291 Bcfe (374 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 30% of the net PUD reserves recorded at September 30, 2023. The Company developed 20 of 73 PUD locations in 2024.

In 2026, the Company estimates that it will invest approximately $295 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule was adopted, and over the last five years, the Company developed 34% of its beginning year PUD reserves in fiscal 2021,45% of its beginning year PUD reserves in fiscal 2022,47% of its beginning year PUD reserves in fiscal 2023,30% of its beginning year PUD reserves in fiscal 2024 and 31% of its beginning year PUD reserves in fiscal 2025.

At September 30, 2025, the Company does not have any proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s exploration and production properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the 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 and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.

The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other exploration and production companies than is provided by a simple comparison of raw proved reserve quantities.

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The principal sources of change in the standardized measure of discounted future net cash flows were as follows:

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