What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2025-11-21 compared with 2024-11-22 · 356 added, 400 removed, 1608 unchanged (32% of the section changed)

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Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes, of National Fuel Gas Company and its subsidiaries (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”).

We have audited the accompanying consolidated balance sheets of National Fuel Gas Company and its subsidiaries (the “Company”) as of September 30, 2025 and 2024, and the related consolidated statements of income and earnings reinvested in the business, of comprehensive income, and of cash flows for each of the three years in the period ended September 30, 2025, including the related notes (collectively referred to as the “consolidated financial statements”).

We also have audited the Company’s internal control over financial reporting as of September 30, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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Estimates of economically recoverable natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including quantities of natural gas that are ultimately recovered, the timing of the recovery of natural gas reserves, the production and operating costs to be incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.

The principal considerations for our determination that performing procedures relating to the impact of proved natural gas reserves on exploration and production properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved natural gas reserves and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved natural gas reserves.

procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved natural gas reserves.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

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Utility Revenues $ 817,274 $ 696,807 $ 941,779

Exploration and Production and Other Revenues 961,078 958,455 1,010,629

Pipeline and Storage and Gathering Revenues 286,925 273,537 277,501

Integrated Upstream and Gathering and Other Revenues 1,184,136 976,615 972,346

Pipeline and Storage Revenues 276,131 271,388 259,646

2,277,541 1,944,810 2,173,771

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Utility 230,639 218,393 205,239

Exploration and Production and Other

141,308 124,270 191,572

Pipeline and Storage and Gathering

160,317 149,247 136,571

Integrated Upstream and Gathering and Other 206,616 187,024 168,390

Pipeline and Storage 120,610 114,601 105,127

Property, Franchise and Other Taxes 94,380 88,851 92,700

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1,464,082 1,735,086 1,418,624

Gain on Sale of Assets — — 12,736

Operating Income 813,459 209,724 755,147

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( 45,891 ) ( 216,655 ) 88,656

Other Post-Retirement Adjustment for Regulatory Proceeding — — ( 7,351 )

Other Comprehensive Income (Loss), Before Tax ( 59,398 ) 55,235 788,876

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( 12,350 ) ( 62,134 ) 5,806

Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding — — ( 1,544 )

Income Taxes — Net ( 15,652 ) 15,651 218,203

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Materials and Supplies - at average cost 50,545 47,670

Unrecovered Purchased Gas Costs 5,769 —

Other Current Assets 80,759 92,229

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Other Regulatory Liabilities 121,944 151,452

Other Post-Retirement Liabilities 3,511 2,915

Pension and Other Post-Retirement Liabilities 5,252 3,511

Asset Retirement Obligations 236,787 203,006

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Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Gain on Sale of Assets — — ( 12,736 )

Impairment of Assets 141,802 519,129 —

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Deferred Income Taxes 121,274 ( 2,610 ) 151,403

Premium Paid on Early Redemption of Debt 2,385 — —

Stock-Based Compensation 19,754 22,080 20,630

Reduction of Other Post-Retirement Regulatory Liability — — ( 18,533 )

Other 24,936 24,411 19,647

Receivables and Unbilled Revenue ( 54,521 ) 34,369 213,579

Gas Stored Underground and Materials, Supplies and Emission Allowances 1,738 ( 8,406 ) 3,109

Gas Stored Underground and Materials and Supplies ( 1,378 ) 1,738 ( 8,406 )

Unrecovered Purchased Gas Costs ( 5,769 ) — 99,342

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Capital Expenditures ( 912,821 ) ( 931,236 ) ( 1,009,868 )

Net Proceeds from Sale of Exploration and Production Properties — — 254,439

Sale of Fixed Income Mutual Fund Shares in Grantor Trust 7,000 — 10,000

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Non-Cash Capital Expenditures $ 125,268 $ 119,988 $ 109,208

Non-Cash Contingent Consideration for Asset Sale $ — $ — $ 12,571

See Notes to Consolidated Financial Statements

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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 into one 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.

The Company is subject to regulation by certain state and federal authorities.

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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.

However, final billings were suppressed in the Utility segment during the COVID-19 pandemic as a result of state shut-off moratoriums.

Those moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby resulting in higher amounts being written off in 2023 and 2024.

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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Balance at End of Year $ 17,099 $ 26,194 $ 36,295

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Regulatory Mechanisms

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Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.

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Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds.

Reference is made to Note F — Regulatory Matters for further discussion.

The Utility segment’s tariff in its New York rate jurisdiction contains a system modernization/improvement tracker that is intended to provide recovery for leak prone pipe replacement.

Amounts calculated under the tracker that are in excess of the annual amount that can be billed to the ratepayer are deferred as a regulatory asset per commission authorization.

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 the eight-month period from October through May.

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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 weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism.

The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation.

Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills.

Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills.

The surcharge or credit is calculated over a twelve-month period ending March 31st, and applied to customer bills annually, beginning July 1st.

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 a twelve-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.

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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.

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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

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acquisition date.

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 Exploration and Production segment, property acquisition, exploration and development costs are capitalized under the full cost method of accounting.

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.

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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 Exploration and Production segment of $ 463.7 million for the year ended September 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, 2024, 2023 and 2022, estimated future net cash flows were increased by $ 428.5 million, increased by $ 38.8 million and decreased by $ 1.0 billion, respectively.

The Exploration and Production segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting.

As discussed in Note I — Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded at September 30, 2024.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost.

There were no indications of any impairments to property, plant and equipment in the Utility and Gathering segments at September 30, 2024.

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.

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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As of September 30

Exploration and Production $ 7,275,495 $ 6,741,095

Integrated Upstream and Gathering $ 9,151,025 $ 8,417,495

Pipeline and Storage 3,003,944 2,919,506

Gathering 1,142,000 1,032,969

Utility 2,801,821 2,645,981

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2025 2024 2023

Exploration and Production, per Mcfe(1) $ 0.71 $ 0.65 $ 0.59

Integrated Upstream and Gathering:

Exploration and Production Operations, per Mcfe(1) $ 0.61 $ 0.69 $ 0.63

Integrated Upstream and Gathering Other Operations 3.6 % 3.6 % 3.5 %

Pipeline and Storage 2.6 % 2.7 % 2.6 %

Gathering 3.6 % 3.6 % 3.6 %

Utility 2.8 % 2.8 % 2.7 %

All Other and Corporate 3.7 % 3.0 % 2.9 %

(1) Amounts include depletion of exploration and production properties as well as depreciation of fixed assets.

As disclosed in Note N — Supplementary Information for Exploration and Production Activities, depletion of exploration and production properties amounted to $ 0.69 , $ 0.63 and $ 0.57 per Mcfe of production in 2024, 2023 and 2022, respectively.

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

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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.

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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

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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.

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$ 55,799 $ ( 71,275 ) $ ( 15,476 )

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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.

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The total amount for accumulated losses was $ 78.8 million and $ 70.9 million at September 30, 2025 and 2024, respectively.

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Reclassifications Out of Accumulated Other Comprehensive Loss

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Gas Stored Underground

In the Utility segment, gas stored underground in the amount of $ 35.0 million is carried at lower of cost or net realizable value, on a LIFO method.

In the Utility segment, gas stored underground in the am ount 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.

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State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed.

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.

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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.

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$ 80,759 $ 92,229

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Other Accruals and Current Liabilities

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Liability for Royalty and Working Interests 28,076 15,007

Pennsylvania Impact Fee 14,923 9,972

Non-Qualified Benefit Plan Liability 11,567 14,135

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$ 174,689 $ 162,903

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Customer Advances

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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 2024, 2023 and/or 2022 were restricted stock units, performance shares and SARs.

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, performance shares and SARs that are antidilutive are excluded from the calculation of diluted earnings per common share.

There were 569 securities, 3,888 securities and 2,858 securities excluded as being antidilutive for the years ended September 30, 2024, 2023 and 2022, respectively.

Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share.

There were 3,228 securiti es, 569 securities and 3,888 securities excluded as being antidilutive for the years ended September 30, 2025, 2024 and 2023, respectively.

Share Repurchases

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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

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The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.

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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.

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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.

Note B — Asset Acquisitions and Divestitures

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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into the Company’s business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5 %.

The Company intends to execute permanent financing, inclusive of the amount to repay the promissory note, using the issuance of long-term debt and common equity, along with expected future free cash flow.

This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas.

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.

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Total Consideration $ 124,758

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $ 253.5 million, consisting of $ 240.9 million in cash and contingent consideration valued at $ 12.6 million at closing.

The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin.

Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $ 10 million per year, with the amount of each annual payment calculated as $ 1.0 million for each $ 1 per barrel that the ICE Brent Average for each calendar year exceeds $ 95 per barrel up to $ 105 per barrel.

The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date.

Under the full cost method of accounting for oil and natural gas properties, $ 220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center.

The remainder of the sale price ($ 32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $ 12.7 million on the sale of such assets.

The majority of this gain related to the sale of emission allowances.

The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets.

This obligation amounted to $ 50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting.

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Note C — Revenue from Contracts with Customers

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Revenues by Type of Service

Production Pipeline

Storage Gathering Utility Total

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Other Corporate

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Total Revenues $ 1,184,136 $ 427,601 $ 817,629 $ 2,429,366 $ — $ ( 151,825 ) $ 2,277,541

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Year Ended September 30, 2024

Revenues by Type of Service

Production Pipeline

Storage Gathering Utility Total

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Other Corporate

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Total Revenues $ 976,615 $ 412,393 $ 697,362 $ 2,086,370 $ — $ ( 141,560 ) $ 1,944,810

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Year Ended September 30, 2023

Revenues by Type of Service

Production Pipeline

Storage Gathering Utility Total

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Other Corporate

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Total Revenues $ 972,346 $ 379,191 $ 942,360 $ 2,293,897 $ — $ ( 120,126 ) $ 2,173,771

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment.

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.

Exploration and Production Segment Revenue

The Company’s Exploration and Production segment records revenue from the sale of the natural gas and oil that it produces and natural gas liquids (NGLs) processed based on entitlement, 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 NGLs, and the Company’s ownership interest.

Prior to the completion of the sale of the Company’s California assets on June 30, 2022, natural gas production occurred primarily in the Appalachian region of the United States and crude oil production occurred primarily in the West Coast region of the United States.

Subsequent to June 30, 2022, substantially all Exploration and Production segment production consists of natural gas production from the Appalachian region of the United States.

If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, oil and NGLs 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 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 Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and Production segment has the right to invoice) under the authoritative guidance for revenue recognition.

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contracts typically require payment within 30 days of the end of the calendar month in which the natural gas and oil is delivered, or picked up in the case of NGLs.

The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment related to sales of the natural gas that it produces.

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;

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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.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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:

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and $ 529.1 million thereafter.

Gathering Segment Revenue

The Company’s Gathering segment provides gathering and processing services in the Appalachian region of Pennsylvania, primarily for Seneca.

The Gathering segment’s primary performance obligation is to deliver gathered natural gas volumes from Seneca’s wells, and to a lesser extent, other 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 Gathering segment as specified by the “invoice practical expedient” (the amount that the 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 10th day after the invoice is received.

Utility Segment Revenue

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This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment.

The Utility segment recognizes

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

revenue when it satisfies its performance obligation by delivering natural gas to the customer.

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.

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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);

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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).

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The Company also does not have any material arrangements where the Company is the lessor.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania.

The primary non-cancelable terms of the Company’s building and property leases range from ten months to fifteen years .

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 from one month to fourteen 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 from one year to sixteen years .

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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 lease.

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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As such, the Company has concluded that these arrangements are not leases under the authoritative guidance.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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Short-term leases that have a lease term of one year or less are not recorded on the Consolidated Balance Sheet.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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Other Liabilities $ 29,683 $ 32,616

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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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 Exploration and Production segment’s natural gas wells and has capitalized such costs in property, plant and equipment (i.e.

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).

In addition to the asset retirement obligation recorded in the Exploration and Production 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, Pipeline and Storage, and Gathering 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, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment.

The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which

Asset retirement obligation costs

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, the Company experienced an increase in plugging and abandonment costs associated with the Exploration and Production segment’s natural gas wells and the Pipeline and Storage segment’s natural gas storage wells, which contributed to an increase in the asset retirement obligation.

This increase in plugging and abandonment costs is the primary component of the Revision of Estimates amount for fiscal 2024 shown in the table below.

As discussed in Note B — Asset Acquisitions and Divestitures, on June 30, 2022, the Company completed the sale of Seneca’s California oil and gas assets to Sentinel Peak Resources California LLC.

With the divestiture of these assets, the Company reduced its Asset Retirement Obligation at June 30, 2022 by $ 50.1 million.

This reduction is reflected in Liabilities Settled in the table below.

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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Balance at End of Year $ 236,787 $ 203,006 $ 165,492

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note F — Regulatory Matters

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Regulatory Assets:

Recoverable Future Taxes (Note G) $ 89,247 $ 80,084

Unamortized Debt Expense (Note A) 6,236 5,604

Other Regulatory Assets:

Pension Costs (Note K) 42,602 30,259

NY Rate Case Levelization and Tracking Mechanisms(1) 28,688 —

Asset Retirement Obligations (Note E) 24,634 21,951

Post-Retirement Benefit Costs (Note K) 13,306 7,932

Recoverable Future Taxes (Note G) 80,084 69,045

System Modernization / Improvement Tracker (See Regulatory

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12,625 31,362

Asset Retirement Obligations(1) (Note E) 21,951 19,384

Unamortized Debt Expense (Note A) 5,604 7,240

Other 13,631 16,518

Total Regulatory Assets 231,974 184,796

Amounts Included in Other Current Assets ( 38,264 ) ( 36,373 )

Total Long-Term Regulatory Assets $ 230,969 $ 193,710

Current Regulatory Assets:

Unrecovered Purchased Gas Costs (See Regulatory Mechanisms in Note A) 5,769 —

Other Current Assets:

System Modernization / Improvement Tracker (See Regulatory

Mechanisms in Note A)

14,481 15,681

Other 20,881 22,583

Total Regulatory Assets $ 272,100 $ 231,974

(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.

NATIONAL FUEL GAS COMPANY

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Regulatory Liabilities:

Cost of Removal Regulatory Liability $ 292,477 $ 277,694

Taxes Refundable to Customers (Note G) $ 306,335 $ 305,645

Cost of Removal Regulatory Liability 307,659 292,477

Other Regulatory Liabilities:

Post-Retirement Benefit Costs (Note K) 108,714 135,399

Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 42,720 59,019

Environmental Site Remediation Costs (Note L) 1,800 5,390

Other 11,430 10,663

Total Regulatory Liabilities 821,646 808,821

Amounts included in Current and Accrued Liabilities ( 72,072 ) ( 97,124 )

Total Long-Term Regulatory Liabilities $ 735,938 $ 749,574

(1) Included in Other Regulatory Assets on the Consolidated Balance Sheets.

(2) $ 15,681 and $ 19,584 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months.

$ 31,362 and $ 10,791 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively.

(3) $ 22,583 and $ 16,789 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months.

$ 16,518 and $ 18,968 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively.

(4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.

(5) $ 5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2024 and 2023, since such amounts are expected to be passed back to ratepayers in the next 12 months.

$ 135,399 and $ 153,960 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively.

(6) $ 23,552 and $ 32,305 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months.

$ 10,663 and $ 10,862 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively.

Current Regulatory Liabilities:

Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 968 42,720

Other Current and Accrued Liabilities:

Post-Retirement Benefit Costs (Note K) 5,800 5,800

Other 14,824 23,552

Total Regulatory Liabilities $ 757,530 $ 821,646

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.

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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 a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024.

It also reflects a return on equity of 9.7 % and 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 the three-year rate plan.

The revenue requirement for each year of the three-year plan has been reduced by $ 14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits.

Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings.

The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals.

It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

New York Jurisdiction

Distribution Corporation’s current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 (“2017 Rate Order”).

The 2017 Rate Order provided for a return on equity of 8.7 % and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of approximately $ 88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024.

A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024.

Thereafter, settlement discussions with parties commenced and to facilitate these discussions, the Company requested postponements of the evidentiary hearing and agreed to extensions of the suspension period for the effective date of new base delivery rates subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period.

The settlement negotiations were successful and resulted in a Joint Proposal (“JP”) that establishes a three-year rate plan allowing for an $ 86 million increase in annual revenue requirement over three years, with the first-year impact of $ 57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027.

The JP settles all contested issues among the signatory parties and includes, among other things, a return on equity of 9.7 %, a common equity ratio of 48 % for rate setting purposes, an earnings sharing mechanism, an uncollectible expense tracker, and continuation of the Company’s leak prone pipe replacement program.

The revenue requirement in the JP also includes the impact of negative pension/OPEB expense.

The JP was filed with the NYPSC on September 9, 2024.

On November 14, 2024, the NYPSC issued an order extending the suspension period through December 31, 2024.

That order also includes a “make-whole” provision from September 30, 2024 until the date new rates take effect under the final decision on the JP.

Pennsylvania Jurisdiction

On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $ 28.1 million.

A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023.

The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $ 23 million.

The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

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.

If approved as filed, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if its total plant in service exceeds approximately $ 781.3 million and its quarterly rate of return does not exceed the authorized PaPUC rate of return.

As of September 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division was $ 785.2 million.

The DSIC petition is currently pending before the PaPUC.

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, approved June 11, 2024 provides that Supply Corporation may make a rate filing for new rates to be effective at any time.

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.

Empire’s 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025.

Empire is not barred from filing a Section 4 rate case before the May 1, 2025 date.

Empire has no rate case currently on file.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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Total Income Taxes $ 175,549 $ 9,742 $ 164,533

On July 8, 2022, House Bill 1342 was signed into law in Pennsylvania.

The law reduces the corporate income tax rate to 8.99 % for fiscal 2024.

Starting with fiscal 2025, the rate is reduced by 0.5 % annually until it reaches 4.99 % for fiscal 2032.

Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted.

GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled.

During fiscal 2022, the Company’s deferred income taxes were initially re-measured based upon the new tax rates.

For the Company’s non-rate regulated activities, the change in deferred income taxes was $ 28.4 million as of the enactment date and was recorded as a reduction to income tax expense.

For the Company’s rate regulated activities, the reduction in deferred income taxes of $ 37.2 million was recorded as a decrease to Recoverable Future Taxes of $ 19.8 million and an increase to Taxes Refundable to Customers of $ 17.4 million during the quarter ended September 30, 2022.

As the rate reduction occurs through fiscal 2032, an annual re-measurement will be made.

This amount is reflected in State Income Taxes.

On August 16, 2022, the “Inflation Reduction Act” (IRA) was signed into law.

The IRA, among other things, includes provisions to expand energy incentives, impose a corporate minimum tax, and impose an excise tax on corporate stock buybacks.

The provisions of the IRA did not have a material impact on the accompanying financial statements, although some of the provisions may be applicable in future years.

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.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes.

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$ 145,751 $ 18,324 $ 134,694

State Valuation Allowance (1) — — ( 24,850 )

State Income Taxes 33,637 1,892 36,331

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Stock Compensation 2,245 1,758 957

Federal Tax Credits ( 5 ) ( 6 ) ( 5,701 )

Miscellaneous 3,603 ( 490 ) 1,460

Total Income Taxes $ 175,549 $ 9,742 $ 164,533

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(1) During fiscal 2022, the valuation allowance recorded against certain state deferred tax assets was removed.

See discussion below.

(2) The state income tax expense shown above includes adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes, including the Pennsylvania rate change discussed above.

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

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Total Net Deferred Income Taxes $ 1,225,262 $ 1,111,165

The following is a summary of changes in valuation allowances for deferred tax assets:

Year Ended September 30

2024 2023 2022

Balance at Beginning of Year $ — $ — $ 57,645

Additions — — —

Deductions — — 57,645

Balance at End of Year $ — $ — $ —

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.

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The Company considers both positive and negative evidence related to the likelihood of the realization of the deferred tax assets.

On June 30, 2022, the Company completed the sale of Seneca’s California oil and gas assets to Sentinel Peak Resources California, LLC.

As a result of the sale of the California oil and gas assets, the remaining deferred tax assets and valuation allowance of approximately $ 27.2 million related to the California net operating loss and tax credit carryforwards were written off, as the Company determined that there was a remote possibility for use as the Company no longer has California operations.

During the quarter ended September 30, 2022, the valuation allowance was adjusted because of the Pennsylvania corporate income tax rate change remeasurement described above and for current activity, for a cumulative adjustment of $ 5.5 million.

In addition, the Company determined there was sufficient positive evidence, despite a prior history of subsidiary tax losses, to conclude that it was more likely than not that the remaining state deferred tax assets would be realized.

The conclusion was primarily related to the use of net operating losses in Pennsylvania in 2022 due to

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:

Jurisdiction Tax Attribute Amount

(Thousands) Expires

Pennsylvania Net Operating Loss $ 422,900 2031-2045

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

sustained strong operating results as well as the expectation for future forecasted earnings in Pennsylvania.

The sale of California assets also resulted in higher apportionment of income to Pennsylvania on a prospective basis, which further supported realization of existing Pennsylvania net operating loss deferred tax assets.

Accordingly, as of September 30, 2022, the Company reversed the remaining valuation allowance and recognized an income tax benefit of approximately $ 24.9 million.

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 $ 305.6 million and $ 268.6 million at September 30, 2024 and 2023, respectively.

Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amounted to $ 80.1 million and $ 69.0 million at September 30, 2024 and 2023, respectively.

The Company is in the Compliance Maintenance Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2024.

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.

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The Company has no unrecognized tax benefits as of September 30, 2025, 2024, or 2023.

During fiscal 2009, preliminary consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property, subject to final guidance.

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 most recent consolidated tax return filing.

The Company is planning to elect this same change in tax accounting method for Supply Corporation with its consolidated tax return filing in the upcoming year and has reflected an estimate in the September 30, 2024 financial statements of what is intended to be treated as a repair for tax purposes rather than being capitalized.

That estimate has been recorded in Income Tax Expense.

Tax carryforwards available at September 30, 2024, were as follows:

Jurisdiction Tax Attribute Amount

(Thousands) Expires

Pennsylvania Net Operating Loss $ 438,058 2031-2044

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.

NATIONAL FUEL GAS COMPANY

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Dividends Declared on Common Stock ($ 1.94 Per Share)

Other Comprehensive Loss, Net of Tax ( 112,136 )

Other Comprehensive Income, Net of Tax 570,673

Share-Based Payment Expense(1) 18,746

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333 333 ( 1,955 )

Share Repurchases Under Repurchase Plan ( 1,146 ) ( 1,146 ) ( 13,187 ) ( 50,823 )

Balance at September 30, 2024

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Dividends Declared on Common Stock ($ 2.10 Per Share)

Other Comprehensive Income, Net of Tax 39,584

Other Comprehensive Loss, Net of Tax ( 43,746 )

Share-Based Payment Expense(1) 17,306

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The expense is included within Net Income Available for Common Stock, net of tax benefits.

(2) The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt.

At September 30, 2024, $ 1.6 billion of accumulated earnings was free of such limitations.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

alternatives.

During 2025, the Company did no t issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan or the Company’s 401(k) plans.

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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 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $ 56.32 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $ 65.2 million.

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 the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings.

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

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2029 - zero ;

2030 - 11,256 ;

and 45,044 shares thereafter.

The performance shares granted during the years ended September 30, 2024, 2023 and 2022 include awards that must meet a performance goal related to either relative return on capital over a three-year or five-year performance cycle (“ROC performance shares”), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle (“ESG performance shares”) or relative shareholder return over a three-year or five-year performance cycle (“TSR performance shares”).

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 a three-year or five-year performance cycle (“ROC Performance Shares”), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle (“Emissions Performance Shares”) or relative shareholder return over a three-year or five-year performance cycle (“TSR Performance Shares”).

NATIONAL FUEL GAS COMPANY

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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 ESG performance shares granted during 2024, 2023 and 2022 consists of two parts:

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 ESG 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 ESG 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 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.

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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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Year Ended September 30

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Expected Dividend Yield (Quarterly) N/A N/A N/A

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Redeemable Preferred Stock

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7.38 % due June 2025

$ 50,000 $ 50,000

Notes(1)(2)(3):

2.95 % to 5.50 % due July 2025 to March 2031

2.95 % to 5.95 % due October 2026 to March 2035

2,400,000 2,350,000

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(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 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 %, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade.

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 is a weighted average SOFR interest rate of 6.71 % that was locked in from April 2024 until the beginning of October 2024.

The current locked in interest rate is 4.62 % for $ 200.0 million until December 2024 and 4.58 % for the remaining $ 100.0 million until January 2025.

(5) 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.

None of the Company’s long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period.

On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement.

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

(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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(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, with six of the 12 banks that are lenders under the Credit Agreement.

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.

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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 %.

On May 18, 2023, the Company issued $ 300.0 million of 5.50 % notes due October 1, 2026.

After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $ 297.3 million.

The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under a $ 250.0 million unsecured committed delayed draw term loan under a previous 364-Day Credit Agreement.

As of September 30, 2025, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows:

$ 500.0 million in 2025, $ 800.0 million in 2026, $ 600.0 million in 2027, $ 300.0 million in 2028, zero in 2029, and $ 500.0 million thereafter.

$ 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.

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the “Credit Agreement”) with a syndicate of twelve banks.

The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement.

As initially entered, the Credit Agreement provided a $ 1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

In February 2024, the Company and eleven of the banks in the syndicate consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028.

In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $ 1.0 billion to February 25, 2028.

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 second one-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 to twelve 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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 %.

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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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity:

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, 2024, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and the Term Loan Agreement was 0.47 .

The constraints specified in the agreements would have permitted an additional $ 3.07 billion in short-term and/or long-term debt to be outstanding at September 30, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65 .

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.

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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.

The Company’s present liquidity position is believed to be adequate to satisfy known demands.

In order to issue incremental long-term debt, the Company must meet an interest coverage test under its existing indenture covenants.

In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance.

In addition, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the indenture) of not more than 60 %.

Under the Company’s 1974 indenture, given the impairments of exploration and production properties the Company recognized during the year ended September 30, 2024, the indenture covenants would preclude the Company from issuing incremental long-term debt beginning January 2025, for a period likely extending to June 2025, when the remaining debt outstanding under the 1974 indenture matures.

The indenture covenants do not, however, prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt.

Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

As of September 30, 2024, the Company has $ 50.0 million in principal and $ 3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture.

Currently, the Company does not anticipate a need to issue incremental long-term debt and only has plans for new long-term debt to replace maturing long-term debt.

To the extent a need arises to issue incremental long-term debt, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture.

Depositing the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

In addition to the covenants noted above, the Company’s 1974 indenture contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture.

In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

Note I — Fair Value Measurements

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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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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Over the Counter No Cost Collars — Gas — 24,149 — ( 12,805 ) 11,344

Contingent Consideration for Asset Sale — 729 — — 729

Foreign Currency Contracts — 144 — ( 675 ) ( 531 )

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Total Net Assets/(Liabilities) $ 54,419 $ 33,385 $ — $ — $ 87,804

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

At Fair Value as of September 30, 2024

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Total Net Assets/(Liabilities) $ 66,135 $ 83,170 $ — $ — $ 149,305

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(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.

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Impairment of Assets:

Water Disposal Assets Integrated Upstream and Gathering December 31, 2024 $ 12,880 $ 33,453 $ — $ —

Northern Access Project Pipeline and Storage September 30, 2024 $ 12,133 — 46,075 —

Water Disposal Assets Exploration and Production September 30, 2024 $ 3,000 9,362 — —

Water Disposal Assets Integrated Upstream and Gathering September 30, 2024 $ 3,000 — 9,362 —

Total Impairment $ 33,453 $ 55,437 $ —

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

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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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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The precedent agreements were subsequently terminated on October 16, 2024.

Accordingly, the Company will no longer pursue construction of the Northern Access project and has taken an impairment charge of $ 46.1 million at September 30, 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, 2024, 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 Exploration and Production segment.

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 discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas trading markets).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

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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 and September 30, 2023 also includes the contingent consideration associated with the sale of the Exploration and Production segment’s California assets on June 30, 2022, which is discussed at Note B — Asset Acquisitions and Divestitures and at Note J — Financial Instruments.

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 was zero 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.

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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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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).

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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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other Investments

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Derivative Financial Instruments

The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment.

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 Exploration and Production segment.

These instruments are accounted for as cash flow hedges.

The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 6 years.

On June 30, 2022, the Company completed the sale of Seneca’s California assets.

The terms of the purchase and sale agreement specified that the Company could receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $ 10 million per year, with the amount of each annual payment calculated as $ 1.0 million for each $ 1 per barrel that the ICE Brent Average for each calendar year exceeds $ 95 per barrel up to $ 105 per barrel.

The calendar 2023 contingency period expired with the ICE Brent Average falling below $ 95 per barrel.

The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance.

Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income.

The fair value of this contingent consideration was estimated to be $ 0.7 million and $ 7.3 million at September 30, 2024 and September 30, 2023, respectively.

A $ 6.6 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the year ended September 30, 2024.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Cash Flow Hedges

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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 gains will be reclassified into the Consolidated Statement of Income in subsequent periods.

The remaining unrealized loss will be reclassified into the Consolidated Statement of Income in subsequent periods.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

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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 nineteen counterparties of which seventeen are in a net gain position.

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.

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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.

As of September 30, 2024, sixteen of the nineteen counterparties to the Company’s outstanding derivative financial 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

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) and no 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

credit that could be extended to the Company when it is in a derivative financial liability position would either increase or decrease.

If the Company’s outstanding derivative financial 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, 2024, the Company did not have any derivative financial instrument liabilities with a credit-risk related contingency feature according to the Company’s internal model (discussed in Note I — Fair Value Measurements).

Depending on the movement of commodity prices in the future, it is possible that the Company’s derivative asset positions could swing into liability positions, at which point the Company could be required to post hedging collateral deposits.

The Company’s requirement to post hedging collateral deposits and the Company’s right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value.

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( 1,375 ) 16,231 21,512 ( 3,857 ) 8,759 15,157

Net Periodic Benefit Cost (Income) $ ( 5,334 ) $ ( 4,622 ) $ 23,087 $ ( 4,583 ) $ ( 3,404 ) $ ( 5,664 )

Net Periodic Benefit Income $ ( 12,195 ) $ ( 5,334 ) $ ( 4,622 ) $ ( 15,373 ) $ ( 4,583 ) $ ( 3,404 )

Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30

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Increase in Actuarial Loss, excluding amortization(2) $ ( 20,828 ) $ ( 19,722 ) $ ( 1,061 )

Change due to Amortization of Actuarial (Gain) Loss ( 1,339 ) ( 2,266 ) 4,772

Change due to Amortization of Actuarial Loss 6,481 37 1,101

Prior Service (Cost) Credit 302 ( 429 ) —

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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 2024 was to increase the projected benefit obligation of the Retirement Plan by $ 69.6 million.

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 2023 was to decrease the projected benefit obligation of the Retirement Plan by $ 28.4

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

NATIONAL FUEL GAS COMPANY

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and $ 297.8 million in the five years thereafter.

The effect of the discount rate change in 2024 was to increase the other post-retirement benefit obligation by $ 28.1 million.

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.

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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 effect of the discount rate change in 2022 was to decrease the other post-retirement benefit obligation by $ 98.9 million.

The mortality improvement projection scale was updated, which increased the other post-retirement benefit obligation in 2022 by $ 1.1 million.

Other actuarial experience decreased the other post-retirement benefit obligation in 2022 by $ 22.5 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.

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

(7) Domestic Fixed Income securities include $ 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.

(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.

At September 30, 2025

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However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

The Company, in its Utility segment and Exploration and Production 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 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:

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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, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects.

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 Exploration and Production 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 $ 218.6 million in 2025, $ 73.6 million in 2026, and $ 13.9 million in 2027.

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.

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Note M — Business Segment Information

The Company reports financial results for four segments:

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 for four segments:

Exploration and Production, Pipeline and Storage, Gathering, and Utility.

The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas reserves in the Appalachian region of the United States.

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 as one 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.

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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 Gathering segment is comprised of Midstream Company’s operations.

Midstream Company builds, owns and operates natural gas pipeline gathering facilities in the Appalachian region and currently provides gathering services primarily to Seneca.

The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation.

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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.

The Company evaluates segment performance based on income before discontinued operations (when applicable).

When this is not applicable, the Company evaluates performance based on net income.

NATIONAL FUEL GAS COMPANY

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Year Ended September 30, 2025

Production Pipeline

Storage Gathering Utility Total

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Other Corporate

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— 151,470 355 151,825 — ( 151,825 ) —

Interest Income $ 2,729 $ 8,632 $ 333 $ 5,736 $ 17,430 $ — $ ( 8,703 ) $ 8,727

Total Revenues 1,184,136 427,601 817,629 2,429,366 — ( 151,825 ) 2,277,541

Operation and Maintenance Expense(4):

Upstream General and Administrative Expense 75,280 — — 75,280 — ( 223 ) 75,057

Lease Operating Expense 50,665 — — 50,665 — ( 5,817 ) 44,848

Gathering Operation and Maintenance Expense 48,635 — — 48,635 — ( 246 ) 48,389

All Other Operation and Maintenance Expense 16,049 122,379 234,455 372,883 — 16,688 389,571

Purchased Gas Expense(4) — — 358,454 358,454 — ( 145,013 ) 213,441

Depreciation, Depletion and Amortization Expense(4) 311,817 74,480 69,701 455,998 — 596 456,594

Impairment of Assets (Significant Non-Cash Item)(4) 141,802 — — 141,802 — — 141,802

Interest Expense(4) 76,633 45,509 42,969 165,111 536 ( 9,813 ) 155,834

Depreciation, Depletion and Amortization $ 277,945 $ 74,530 $ 38,817 $ 65,261 $ 456,553 $ — $ 473 $ 457,026

Significant Non-Cash Item:

Impairment of Assets $ 473,054 $ 46,075 $ — $ — $ 519,129 $ — $ — $ 519,129

Interest Income ( 1,445 ) ( 6,085 ) ( 2,284 ) ( 9,814 ) ( 11 ) 3,809 ( 6,016 )

Income Tax Expense (Benefit)(4) 121,095 39,748 15,653 176,496 ( 245 ) ( 702 ) 175,549

$ ( 58,430 ) $ 26,045 $ 38,217 $ 3,951 $ 9,783 $ ( 186 ) $ 145 $ 9,742

Other Expense (Income) Items(5) 18,907 30,613 15,432 64,952 534 ( 1,518 ) 63,968

Segment Profit:

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Segment Assets $ 3,701,646 $ 2,412,747 $ 2,534,289 $ 8,648,682 $ 8,704 $ 61,718 $ 8,719,104

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Year Ended September 30, 2024

Production Pipeline

Storage Gathering Utility Total

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Other Corporate

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— 141,005 555 141,560 — ( 141,560 ) —

Interest Income $ 3,259 $ 7,052 $ 534 $ 6,296 $ 17,141 $ — $ ( 5,662 ) $ 11,479

Total Revenues 976,615 412,393 697,362 2,086,370 — ( 141,560 ) 1,944,810

Operation and Maintenance Expense(4):

Upstream General and Administrative Expense 71,148 — — 71,148 — ( 221 ) 70,927

Lease Operating Expense 52,053 — — 52,053 — ( 5,723 ) 46,330

Gathering Operation and Maintenance Expense 36,140 — — 36,140 — ( 237 ) 35,903

All Other Operation and Maintenance Expense 15,529 116,335 222,142 354,006 17 12,835 366,858

Purchased Gas Expense(4) — — 283,215 283,215 — ( 133,153 ) 150,062

Depreciation, Depletion and Amortization Expense(4) 316,762 74,530 65,261 456,553 — 473 457,026

Impairment of Assets (Significant Non-Cash Item)(4) 473,054 46,075 — 519,129 — — 519,129

Interest Expense(4) 74,005 47,428 34,727 156,160 374 ( 17,839 ) 138,695

Depreciation, Depletion and Amortization

$ 241,142 $ 70,827 $ 35,725 $ 61,450 $ 409,144 $ — $ 429 $ 409,573

Interest Income ( 3,062 ) ( 8,632 ) ( 5,736 ) ( 17,430 ) — 8,703 ( 8,727 )

Income Tax Expense (Benefit)(4) ( 20,213 ) 26,045 3,951 9,783 ( 186 ) 145 9,742

$ 87,796 $ 34,489 $ 36,128 $ 7,267 $ 165,680 $ ( 164 ) $ ( 983 ) $ 164,533

Other Expense (Income) Items(5) 18,240 30,942 36,713 85,895 412 ( 4,955 ) 81,352

Segment Profit:

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Year Ended September 30, 2023

Production Pipeline

Storage Gathering Utility Total

Integrated Upstream and Gathering Pipeline

Storage Utility Total

Other Corporate

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— 119,545 581 120,126 — ( 120,126 ) —

Interest Income $ 1,929 $ 2,275 $ 198 $ 2,730 $ 7,132 $ 3 $ ( 1,024 ) $ 6,111

Total Revenues 972,346 379,191 942,360 2,293,897 — ( 120,126 ) 2,173,771

Operation and Maintenance Expense(4):

Upstream General and Administrative Expense 66,074 — — 66,074 — ( 241 ) 65,833

Lease Operating Expense 47,854 — — 47,854 — ( 6,902 ) 40,952

Gathering Operation and Maintenance Expense 33,650 — — 33,650 — ( 255 ) 33,395

All Other Operation and Maintenance Expense 9,327 106,654 208,539 324,520 21 14,035 338,576

Purchased Gas Expense(4) — — 548,195 548,195 — ( 110,600 ) 437,595

Depreciation, Depletion and Amortization Expense(4) 276,867 70,827 61,450 409,144 — 429 409,573

Interest Expense(4) 69,306 43,499 34,233 147,038 157 ( 15,309 ) 131,886

Depreciation, Depletion and Amortization

$ 208,148 $ 67,701 $ 33,998 $ 59,760 $ 369,607 $ — $ 183 $ 369,790

Interest Income ( 3,793 ) ( 7,052 ) ( 6,296 ) ( 17,141 ) — 5,662 ( 11,479 )

Income Tax Expense (Benefit)(4) 123,924 34,489 7,267 165,680 ( 164 ) ( 983 ) 164,533

$ 43,898 $ 35,043 $ 24,949 $ 17,165 $ 121,055 $ 3 $ ( 4,429 ) $ 116,629

Significant Item:

Gain on Sale of Assets

$ 12,736 $ — $ — $ — $ 12,736 $ — $ — $ 12,736

Other Expense (Income) Items(5) 17,138 30,273 40,577 87,988 517 ( 2,464 ) 86,041

Segment Profit:

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

(2) Revenue from one customer of the Company’s Exploration and Production 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.

(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) Revenues from three customers of the Company’s Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $ 850 million of the Company’s consolidated revenue for the year ended September 30, 2022.

These three customers were also customers of the Company’s Pipeline and Storage segment, accounting for an additional $ 15 million of the Company’s consolidated revenue for the year ended September 30, 2022.

(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.

Geographic Information At September 30

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United States $ 8,308,377 $ 7,963,851 $ 7,865,832

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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

As discussed in Note B — Asset Acquisitions and Divestitures, the Company completed the sale of its California

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

assets on June 30, 2022.

With the completion of this sale, the Company no longer has any oil or gas reserves in the West Coast region of the U.S.

Capitalized Costs Relating to Exploration and Production Activities

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$ 556,059 $ 565,282 $ 734,138

(1) Amounts for 2024, 2023 and 2022 include capitalized interest of $ 0.1 million, zero and zero respectively.

(2) Amounts for 2024, 2023 and 2022 include capitalized interest of $ 0.7 million, $ 0.1 million and $ 0.6 million, respectively.

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

(2) Amounts for 2025, 2024 and 2023 include capitalized interest of zero , $ 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.

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Franchise/Ad Valorem Taxes 18,267 13,468 17,532

Purchased Emission Allowance Expense — — 1,305

Accretion Expense 7,721 5,992 5,673

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Region West Coast

Appalachian Region

Gas MMcf Oil Mbbl

Proved Developed and Undeveloped Reserves:

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Production ( 372,271 ) (2) ( 30 )

Sale of Minerals in Place ( 21,178 ) ( 29,145 ) ( 50,323 )

Purchases of Minerals in Place 33,876 —

September 30, 2023 4,535,084 216

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Production ( 392,047 ) (2) ( 31 )

Purchases of Minerals in Place 33,876 — 33,876

September 30, 2024 4,751,762 193

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Production includes 180,750 MMcf (during 2023), 154,701 MMcf (during 2024) and 215,681 MMcf (during 2025), from Utica Shale fields.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Region West Coast

Proved Developed and Undeveloped Reserves:

September 30, 2021 11 21,526 21,537

Extensions and Discoveries — 296 296

Revisions of Previous Estimates 255 532 787

Production ( 16 ) ( 1,588 ) ( 1,604 )

Sales of Minerals in Place — ( 20,766 ) ( 20,766 )

September 30, 2022 250 — 250

Revisions of Previous Estimates ( 4 ) — ( 4 )

Production ( 30 ) — ( 30 )

September 30, 2023 216 — 216

Revisions of Previous Estimates 8 — 8

Production ( 31 ) — ( 31 )

September 30, 2024 193 — 193

Proved Developed Reserves:

September 30, 2021 11 20,930 20,941

September 30, 2022 250 — 250

September 30, 2023 216 — 216

September 30, 2024 193 — 193

Proved Undeveloped Reserves:

September 30, 2021 — 596 596

September 30, 2022 — — —

September 30, 2023 — — —

September 30, 2024 — — —

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 increased from 112 Bcfe at September 30, 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.

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 decreased from 355 Bcfe at September 30, 2022 to 112 Bcfe at September 30, 2023.

PUD reserves in the Marcellus Shale increased from 112 Bcfe at September 30,

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 for one 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 for nine PUD locations due to schedule and pad layout changes.

The increase in PUD reserves in 2023 of 127 Bcfe is a result of 554 Bcfe in new PUD reserve additions, 14 Bcfe for one PUD well added back into the schedule and 23 Bcfe in upward revisions to remaining PUD reserves.

These upward revisions were partially offset by 402 Bcfe in PUD conversions to developed reserves

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

( 275 Bcfe from the Marcellus Shale and 127 Bcfe from the Utica Shale), and 62 Bcfe in PUD reserves removed for seven 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.

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The Company developed 20 of 73 PUD locations in 2024.

PUD expenditures in 2023 were higher than the 2022 estimate due to schedule changes and changes in service costs.

In 2026, the Company estimates that it will invest approximately $ 295 million to develop its PUD reserves.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 8. Financial Statements and Supplementary Data