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Item 8. Financial Statements and Supplementary Data

2024-11-22 compared with 2023-11-17 · 342 added, 368 removed, 1666 unchanged (30% of the section changed)

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Supplementary Data

Supplementary data that is included in Note N — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.

Supplementary data that is included in Note N — Supplementary Information for Exploration and Production Activities (unaudited), appears under this Item, and reference is made thereto.

Report of Independent Registered Public Accounting Firm

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Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Natural Gas Reserves on Natural Gas Properties, Net

As described in Note A to the consolidated financial statements, the Exploration and Production segment includes capitalized costs relating to natural gas producing activities, net of depreciation, depletion, and amortization (DD&A) of $2.4 billion as of September 30, 2023.

The Exploration and Production segment follows the full cost method of accounting.

Under this method, all costs associated with property acquisition, exploration and development activities are capitalized and DD&A is computed based on quantities produced in relation to proved reserves using the units of production method.

As disclosed by management, in addition to DD&A under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test.

The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized.

The Impact of Proved Natural Gas Reserves on Exploration and Production Properties, Net

As described in Note A to the consolidated financial statements, the Company’s capitalized costs relating to exploration and production activities, net of depreciation, depletion and amortization (DD&A) were $2.3 billion as of September 30, 2024.

The Company follows the full cost method of accounting.

Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized.

For exploration and production properties, DD&A is computed based on quantities produced in relation to proved reserves using the units-of-production method.

As disclosed by management, in addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test.

The full cost ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized.

If capitalized costs, net of accumulated DD&A and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter.

There were no ceiling test impairment charges for the year ended September 30, 2023 .

As of September 30, 2023, the ceiling exceeded the book value of the natural gas properties by approximately $794.7 million.

For the year ended September 30, 2024, pre-tax impairment charges of $463.7 million were recognized.

Estimates of the Company’s proved natural gas reserves and the future net cash flows from those reserves were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers (together referred to as “management’s specialists”).

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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 natural gas properties, net is a critical audit matter are the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved natural gas reserves, which in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating evidence related to data, methods, and assumptions used by management and its specialists in developing the estimates of proved natural gas reserves and the related assumption of quantities of proved natural gas that are ultimately recovered.

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.

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

These procedures included testing the effectiveness of controls relating to management’s estimates of proved natural gas reserves and the related assumption of quantities of proved natural gas that are ultimately recovered which is utilized in the DD&A expense and ceiling test calculations.

These procedures also included, among others, evaluating the reasonableness of the significant assumption used by management related to the quantities of proved natural gas that are ultimately recovered which included evaluating information on additional development activity, production history, if the assumption used was reasonable considering the past performance of the Company, and whether it was consistent with evidence obtained in other areas of the audit.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved natural gas reserves and the related assumption of quantities of proved natural gas that are ultimately recovered.

As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists assessed.

The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the completeness and accuracy of data used by the specialists and an evaluation of the specialists’ findings.

These procedures included testing the effectiveness of controls relating to management’s estimates of proved natural gas reserves.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved natural gas reserves.

As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed.

The procedures performed also included (i) evaluating the methods and assumptions used by the specialists;

(ii) testing the completeness and accuracy of the underlying data used by the specialists;

and (iii) evaluating the specialists’ findings.

/s/ P RICEWATERHOUSE C OOPERS LLP

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Operating Revenues:

Utility and Energy Marketing Revenues $ 941,779 $ 897,916 $ 667,549

Utility Revenues $ 696,807 $ 941,779 $ 897,916

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

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Operation and Maintenance:

Utility and Energy Marketing

205,239 193,058 179,547

Utility 218,393 205,239 193,058

Exploration and Production and Other

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Depreciation, Depletion and Amortization 457,026 409,573 369,790

Impairment of Oil and Gas Producing Properties — — 76,152

Impairment of Assets 519,129 — —

1,735,086 1,418,624 1,384,266

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1,963,369 2,063,951 1,757,196

Share Repurchases under Repurchase Plan ( 50,823 ) — —

Dividends on Common Stock ( 185,220 ) ( 178,095 ) ( 170,111 )

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Other Comprehensive Income (Loss) 39,584 570,673 ( 112,136 )

Comprehensive Income (Loss) $ 1,047,539 $ 453,885 $ ( 35,193 )

Comprehensive Income $ 117,097 $ 1,047,539 $ 453,885

See Notes to Consolidated Financial Statements

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Cash and Temporary Cash Investments 38,222 55,447

Hedging Collateral Deposits — 91,670

Receivables — Net of Allowance for Uncollectible Accounts of $ 26,194 and $ 36,295 , Respectively

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Materials and Supplies - at average cost 47,670 48,989

Unrecovered Purchased Gas Costs — 99,342

Other Current Assets 92,229 100,260

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Gain on Sale of Assets — — ( 12,736 )

Impairment of Oil and Gas Producing Properties — — 76,152

Impairment of Assets 519,129 — —

Depreciation, Depletion and Amortization 457,026 409,573 369,790

Deferred Income Taxes ( 2,610 ) 151,403 104,415

Premium Paid on Early Redemption of Debt — — 15,715

Stock-Based Compensation 22,080 20,630 19,506

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Capital Expenditures ( 931,236 ) ( 1,009,868 ) ( 811,826 )

Net Proceeds from Sale of Oil and Gas Producing Properties — 254,439 —

Net Proceeds from Sale of Timber Properties — — 104,582

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

Sale of Fixed Income Mutual Fund Shares in Grantor Trust — 10,000 30,000

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Net Proceeds from Issuance of Long-Term Debt 299,359 297,306 —

Shares Repurchased Under Repurchase Plan ( 64,086 ) — —

Reduction of Long-Term Debt — ( 549,000 ) —

Net Repurchases of Common Stock ( 6,709 ) ( 9,590 ) ( 3,702 )

Net Repurchases of Common Stock Under Stock and Benefit Plans ( 3,956 ) ( 6,709 ) ( 9,590 )

Dividends Paid on Common Stock ( 183,798 ) ( 176,096 ) ( 168,147 )

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All significant intercompany balances and transactions are eliminated.

The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.

The Company uses proportionate consolidation when accounting for drilling arrangements related to exploration and production properties accounted for under the full cost method of accounting.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

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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.

During 2022 and 2021, final billings were suppressed in the Utility segment as a result of state shut-off moratoriums arising from the COVID-19 pandemic.

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.

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.

Activity in the allowance for uncollectible accounts are as follows:

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

The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May.

The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather.

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.

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.

The WNA is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather.

Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills.

On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNC as a five-year pilot program.

The program is effective October 2023 and covers the eight-month period from October through May.

Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNC, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues.

On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNA as a five-year pilot program.

The program became effective October 2023 and covers the eight-month period from October through May.

Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNA, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues.

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

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In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business.

If the initial screening test is not met, the Company evaluates whether the set is a business based on whether there are inputs and a substantive process in place.

If the initial screening test is not met, the Company evaluates whether the set of activities is a business based on whether there are inputs and a substantive process in place.

The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance.

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When the Company acquires assets and liabilities deemed to be a business combination, the acquisition method is applied.

Goodwill is measured as the fair value of the consideration transferred less the net recognized fair value of the identifiable assets acquired and the liabilities assumed, all measured at the acquisition date.

Transaction costs that the Company incurs in connection with a business combination, such as finders’ fees, legal fees, due diligence fees and other professional and consulting fees are expensed as incurred.

Property, Plant and Equipment

In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting.

Under this methodology, all costs

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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associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities.

acquisition date.

Property, Plant and Equipment

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

Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities.

The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities.

The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $ 2.4 billion and $ 1.9 billion at September 30, 2023 and 2022, respectively.

For further discussion of capitalized costs, refer to Note N — Supplementary Information for Oil and Gas Producing Activities.

The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center.

The Company’s capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $ 2.3 billion and $ 2.4 billion at September 30, 2024 and 2023, respectively.

For further discussion of capitalized costs, refer to Note N — Supplementary Information for Exploration and Production Activities.

Capitalized costs are subject to the SEC full cost ceiling test.

The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized.

The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10 %, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties.

The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period.

The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10 %, which is computed by applying commodity pricing (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties.

The commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period.

If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter.

At September 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $ 794.7 million.

In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2023, 2022 and 2021, estimated future net cash flows were increased by $ 38.8 million, decreased by $ 1.0 billion and decreased by $ 76.1 million, respectively.

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.

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, Pipeline and Storage and Gathering segments at September 30, 2023.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense.

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Depreciation, Depletion and Amortization

For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method.

The cost of unproved oil and gas properties is excluded from this computation.

Depreciation, depletion and amortization expense for oil and gas properties was $ 235.7 million, $ 202.4 million and $ 177.1 million for the years ended September 30, 2023, 2022 and 2021, respectively.

For exploration and production properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method.

The cost of unproved exploration and production properties is excluded from this computation.

Depreciation, depletion and amortization expense for exploration and production properties was $ 270.6 million, $ 235.7 million and $ 202.4 million for the years ended September 30, 2024, 2023 and 2022, respectively.

For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated useful lives of property in service.

The following is a summary of depreciable plant by segment:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of September 30

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All Other and Corporate 3.0 % 2.9 % 1.4 %

(1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets.

As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $ 0.63 , $ 0.57 and $ 0.54 per Mcfe of production in 2023, 2022 and 2021, respectively.

(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.

The Company has recognized goodwill of $ 5.5 million as of September 30, 2024 and 2023 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 fluctuations associated with transportation costs denominated in Canadian 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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Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges.

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Accumulated Other Comprehensive Loss

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Amounts Reclassified From Other Comprehensive Loss 82,850 1,263 84,113

Other Post-Retirement Adjustment for Regulatory Proceeding — ( 5,807 ) ( 5,807 )

Balance at September 30, 2023

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The total amount for accumulated losses was $ 70.9 million and $ 59.3 million at September 30, 2024 and 2023, respectively.

During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of OPEB expenses in Distribution Corporation's Pennsylvania service territory.

As a result of that proceeding, Distribution Corporation discontinued regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $ 7.4 million ($ 5.8 million after tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss.

NATIONAL FUEL GAS COMPANY

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$ 152,598 $ ( 84,113 ) Net of Tax

(1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost.

(1) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost.

Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.

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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 2023, 2022 and/or 2021 were SARs, restricted stock units and performance shares.

For the years ended September 30, 2023 and September 30, 2022, 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.

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

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 fiscal 2024, 2023 and 2022, 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.

Share Repurchases

The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings.

Refer to Note H — Capitalization and Short-Term Borrowings for further discussion of the Company’s share repurchase program.

Stock-Based Compensation

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The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments.

SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no SAR is exercisable less than one year or more than ten years after the date of each grant.

The Company chose the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs.

For all Company stock awards, forfeitures are recognized as they occur.

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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.

Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied.

Earned performance shares may be distributed in the form of shares of common stock of

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the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company.

Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company.

The performance shares do not entitle the participant to receive dividends during the vesting period.

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

On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $ 104.6 million.

These assets were a component of the Company’s All Other category and did not have a major impact on the Company’s operations or financial results.

After purchase price adjustments and transaction costs, a gain of $ 51.1 million was recognized on the sale of these assets.

Since the sale did not

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

represent a strategic shift in focus for the Company, the financial results associated with operating these assets as well as the gain on sale have not been reported as discontinued operations.

The sale completed the financing of a July 31, 2020 acquisition of certain upstream assets and midstream gathering assets in Pennsylvania.

Note C — Revenue from Contracts with Customers

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Year Ended September 30, 2022

Revenues by Type of Service

Production Pipeline

Storage Gathering Utility Total

Other Corporate

Eliminations Total

Production of Natural Gas

$ 1,730,723 $ — $ — $ — $ 1,730,723 $ — $ — $ 1,730,723

Production of Crude Oil 150,957 — — — 150,957 — — 150,957

Natural Gas Processing 3,511 — — — 3,511 — — 3,511

Natural Gas Gathering Service

— — 214,843 — 214,843 — ( 202,757 ) 12,086

Natural Gas Transportation Service

— 289,967 — 106,495 396,462 — ( 74,749 ) 321,713

Natural Gas Storage Service

— 84,565 — — 84,565 — ( 36,382 ) 48,183

Natural Gas Residential Sales

— — — 688,271 688,271 — — 688,271

Natural Gas Commercial Sales

— — — 95,114 95,114 — — 95,114

Natural Gas Industrial Sales

— — — 4,902 4,902 — — 4,902

Other 7,867 2,512 — ( 3,918 ) 6,461 6 ( 644 ) 5,823

Total Revenues from Contracts with Customers

1,893,058 377,044 214,843 890,864 3,375,809 6 ( 314,532 ) 3,061,283

Alternative Revenue Programs

— — — 7,357 7,357 — — 7,357

Derivative Financial Instruments

( 882,594 ) — — — ( 882,594 ) — — ( 882,594 )

Total Revenues $ 1,010,464 $ 377,044 $ 214,843 $ 898,221 $ 2,500,572 $ 6 $ ( 314,532 ) $ 2,186,046

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

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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.

The 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.

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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.

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The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced.

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billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition.

The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition.

Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.

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

The Utility segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer.

The Utility segment recognizes

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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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As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the authoritative guidance regarding revenue recognition.

The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

conservation have on margin.

The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and conservation have on margin.

The NYPSC and PaPUC have also authorized additional alternative revenue programs that adjust billings for the effects of broad external factors or to compensate the Company for demand-side management initiatives.

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The Company has elected to apply the following practical expedients provided in the authoritative guidance:

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

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);

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 did not have any material finance leases as of September 30, 2024 or September 30, 2023.

Aside from a sublease of office space at the Company’s corporate headquarters, which terminated April 30, 2022, the Company does not have any material arrangements where the Company is the lessor.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Buildings and Property

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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 one month to sixteen 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 eighteen years .

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

Renewal options are included in the lease term if they are reasonably certain to be exercised.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Compressor Equipment

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

The authoritative guidance does not apply to leases to explore for or use natural gas resources, including the right to explore for those resources and rights to use the land in which those resources are contained.

As such, the Company has concluded that its gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As such, the Company has concluded that its gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.

Amounts Recognized in the Financial Statements

Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of oil and natural gas properties under the full cost method of accounting as well as certain equipment leases related to construction projects, are presented in Operations and Maintenance expense on the Consolidated Statement of Income.

Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of exploration and production properties under the full cost method of accounting as well as certain equipment leases related to construction projects, are presented in Operations and Maintenance expense on the Consolidated Statement of Income.

The following table summarizes the components of the Company’s total operating lease costs (in thousands):

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Short-Term Lease Expense(2) 299 1,694

Sublease Income — ( 166 )

Total Lease Expense $ 12,727 $ 9,685

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

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

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

Right-of-use assets and lease liabilities are recognized at the commencement date of a leasing arrangement based on the present value of lease payments over the lease term.

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Other Liabilities $ 32,616 $ 29,510

Cash paid for lease liabilities, reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $ 9.7 million and $ 5.7 million for the years ended September 30, 2023 and 2022, respectively.

The Company did no t record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2023 or 2022.

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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 $ 12.7 million and $ 9.7 million for the years ended September 30, 2024 and 2023, respectively.

The Company did no t record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2024 or 2023.

The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2024 (in thousands):

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the full cost pool).

During fiscal 2021, this segment’s Appalachian operations were required to implement additional water testing on a portion of its assets, which contributed to an increase in the asset retirement obligation.

This increase is the primary component of the Revisions of Estimates amount for fiscal 2021 shown in the table below.

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.

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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 are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.

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

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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.

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

Environmental Site Remediation Costs(2) (Note L) — 3,646

System Modernization / Improvement Tracker (2) (See Regulatory

Mechanisms in Note A)

47,043 30,375

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

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Post-Retirement Benefit Costs(5) (Note K) 141,199 159,760

Pension Costs(4) (Note K) — 8,242

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

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Total Long-Term Regulatory Liabilities $ 749,574 $ 711,697

(1) The Company recovers the cost of its regulatory assets but generally does not earn a return on them.

There are a few exceptions to this rule.

For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.

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

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$ 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.

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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 $ 88.8 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 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing").

The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the Climate Leadership and Community Protection Act.

The 2017 Rate Order authorized the Company to recover approximately $ 15 million annually for pension and OPEB expenses from customers.

Because the Company’s future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a temporary pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022.

On September 16, 2022, the NYPSC issued an order approving the filing.

With the implementation of this surcredit, Distribution Corporation ceased funding the Retirement Plan and its VEBA trusts in its New York jurisdiction.

The 2023 Rate Filing proposes to keep the rate recovery of pension and OPEB costs at zero in the rate year and reflect the $ 15 million of savings in new base delivery rates.

On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023).

On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023.

The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024.

The 2023 Rate Filing proposes to stop accruing and collecting revenues under its current system modernization and system improvement trackers and shift those revenues into the Company’s new base delivery rates.

In the absence of a multi-year rate plan settlement, the Company is requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization tracker.

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

Distribution Corporation’s delivery rates effective through July 31, 2023 in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.

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.

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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.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $ 7.7 million in order to stop collecting OPEB expenses from customers.

It also began to refund to customers overcollected OPEB expenses in the amount of $ 50.0 million.

All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision.

Concurrent with that decision, the Company discontinued regulatory

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.

FERC Jurisdiction

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

As well, any party can make a filing under NGA Section 5.

Supply Corporation has no rate case currently on file.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

accounting for OPEB expenses and recorded an $ 18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount.

The Company also increased customer refunds of overcollected OPEB expenses from $ 50.0 million to $ 54.0 million.

All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet.

With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

FERC Jurisdiction

Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024.

The proposed rates reflect an annual cost of service of $ 385.4 million, a rate base of $ 1.32 billion and a proposed cost of equity of 15.12 %.

If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate.

If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.

Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.

Note G — Income Taxes

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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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

during the quarter ended September 30, 2022.

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.

1 unchanged sentence

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

The IRA, among other things, includes provisions to expand energy incentives and impose a corporate minimum tax.

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.

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Total Income Taxes $ 9,742 $ 164,533 $ 116,629

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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Deferred Tax Assets:

Unrealized Hedging Losses — ( 215,187 )

Tax Loss and Credit Carryforwards ( 31,111 ) ( 33,744 )

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Total Net Deferred Income Taxes $ 1,111,165 $ 1,124,170

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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

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

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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.

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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 primary change in these was due to Distribution Corporation's rate settlement in Pennsylvania.

For further discussion of Distribution Corporation rate matters, refer to Note F — Regulatory Matters.

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

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The Company has no unrecognized tax benefits as of September 30, 2024, 2023, or 2022.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 is planning to elect this change in tax accounting method with its consolidated tax return filing in the upcoming year and has reflected an estimate in the September 30, 2023 financial statements of what is intended to be treated as a repair for tax purposes rather than being capitalized.

That estimate, which amounted to $ 99.5 million, has been recorded in Income Tax Expense.

Tax carryforwards available, prior to valuation allowance, at September 30, 2023, were as follows:

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

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Pennsylvania Net Operating Loss $ 438,058 2031-2044

Federal General Business Credits $ 1,819 2042

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)

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Common Stock Issued (Repurchased) Under Stock and Benefit Plans 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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The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions.

The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives.

Generally, at the discretion of the Company, shares purchased under these plans are either original

The 401(k) plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.

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 agent.

During 2024, 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.

During 2023, the Company issued 12,055 original issue shares of common stock as a result of SARs exercises, 119,147 original issue shares of common stock for restricted stock units that vested and 278,687 original issue shares of common stock for performance shares that vested.

During 2024, the Company issued 115,337 original issue shares of common stock for restricted stock units that vested and 251,255 original issue shares of common stock for performance shares that vested.

Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes.

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In addition, the Company issued 8,318 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment features of the Company’s DCP during 2024.

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.

Share repurchases that settled during 2024 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.

Stock Award Plans

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Transactions for 2023 involving SARs for all plans are summarized as follows:

Shares Subject

To Option Weighted

Exercise Price Aggregate

(In thousands)

Outstanding at September 30, 2022

72,008 $ 53.05

Granted in 2023

Exercised in 2023

( 72,008 ) $ 53.05

Forfeited in 2023

Expired in 2023

Outstanding at September 30, 2023

SARs exercisable at September 30, 2023

The Company did no t grant any SARs during the years ended September 30, 2022 and 2021.

The Company’s SARs included both performance-based and nonperformance-based SARs, but the performance conditions associated with the performance-based SARs at the time of grant were all subsequently met.

The SARs are considered equity awards under the current authoritative guidance for stock-based compensation.

The accounting for SARs is the same as the accounting for stock options.

The total intrinsic value of SARs exercised during the years ended September 30, 2023 and 2022 totaled approximately $ 0.8 million and $ 2.0 million, respectively.

During the year ended September 30, 2021, no SARs were exercised.

There were no SARs that became fully vested during the years ended September 30, 2023, 2022 and 2021.

The SARs that were outstanding at September 30, 2022 had been fully vested since fiscal 2017.

Restricted Stock Units

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2028 — 34,757 units;

and 2028 — 15,643 units.

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2029 — 19,228 units;

and 56,296 units thereafter.

Performance Shares

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2026 — 188,767 shares;

and 2026 — 193,313 shares.

The performance shares granted during the years ended September 30, 2023, 2022 and 2021 include awards that must meet a performance goal related to either relative return on capital over a three-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 performance cycle ("TSR performance shares").

2027 — 297,392 shares;

2028 - zero ;

2029 - zero ;

and 56,300 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”).

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The performance goal over the respective performance cycles for the ROC performance shares granted during 2024, 2023 and 2022 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”).

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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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The fair value is recorded as compensation expense over the vesting term of the award.

There were no ESG performance shares granted in 2021.

The performance goal over the respective performance cycles for the TSR performance shares granted during 2023, 2022 and 2021 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group.

Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database.

The performance goal over the respective performance cycles for the TSR performance shares granted during 2024, 2023 and 2022 is the Company’s three-year (or five-year ) total shareholder return relative to the three-year (or five-year ) total shareholder return of the other companies in the Report Group.

Three-year (or five-year ) total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database.

The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company.

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For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees.

The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:

The following weighted average assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:

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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2,350,000 2,350,000

Delayed Draw Term Loan(4):

Variable Rate due February 2026 300,000 —

Total Long-Term Debt 2,700,000 2,400,000

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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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.

Current Portion of Long-Term Debt at September 30, 2022 consisted of $ 500.0 million of 3.75 % notes and $ 49.0 million of 7.395 % notes.

The Company redeemed $ 150.0 million of the 3.75 % notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed below.

In March 2023, the Company redeemed the remaining $ 350.0 million of the 3.75 % notes as well as the $ 49.0 million of 7.395 % notes .

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

After deducting debt issuance costs, the net proceeds to the Company amounted to $ 299.4 million.

The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper.

Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10 %, plus a spread of 1.375 %.

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 the $ 250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement, discussed below.

On February 24, 2021, the Company issued $ 500.0 million of 2.95 % notes due March 1, 2031.

After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $ 495.3 million.

The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $ 500.0 million of 4.90 % notes on March 11, 2021 that were scheduled to mature in December 2021.

The Company redeemed those notes for $ 515.7 million, plus accrued interest.

The early redemption premium of $ 15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.

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, 2024, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows:

zero in 2024, $ 500.0 million in 2025, $ 500.0 million in 2026, $ 600.0 million in 2027, $ 300.0 million in 2028, and $ 500.0 million thereafter.

$ 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.

Short-Term Borrowings

2 unchanged sentences

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

The Credit Agreement provides a $ 1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into a 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement.

The 364-Day Credit Agreement provided an additional $ 250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023.

The Company elected to draw $ 250.0 million under the facility on October 27, 2022.

The Company used the proceeds for general corporate purposes, which included using $ 150.0 million for the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

November 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date of March 1, 2023.

All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023.

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 total amount available to be issued under the Company’s commercial paper program is $ 500.0 million.

The commercial paper program is backed by the Credit Agreement.

The Company also has uncommitted lines of credit with financial institutions for general corporate purposes.

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

The total amount available to be issued under the Company’s commercial paper program is $ 500.0 million.

The commercial paper program is backed by the Credit Agreement.

At September 30, 2024, the Company had outstanding commercial paper of $ 90.7 million with a weighted average interest rate on the commercial paper of 5.30 %.

The Company did not have any outstanding short-term notes payable to banks at September 30, 2023.

At September 30, 2022, the Company had outstanding short-term notes payable to banks of $ 60.0 million, all of which was issued under the Credit Agreement, with an interest rate of 4.02 %.

The Company did not have any outstanding commercial paper at September 30, 2022.

At September 30, 2023, the Company had outstanding commercial paper of $ 287.5 million with a weighted average interest rate on the commercial paper of 6.13 %.

The Company did not have any outstanding short-term notes payable to banks at September 30, 2024 and 2023.

Debt Restrictions

The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter.

Both the Credit Agreement and the Term Loan Agreement provide that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter.

For purposes of calculating the debt to capitalization ratio, the Company’s total capitalization will be increased by adding back 50 % of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $ 400 million.

Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $ 381.4 million.

As a result, at September 30, 2023, $ 190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement.

On May 3, 2022, the Company entered into Amendment No.

1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement.

The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, 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 included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet.

Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation.

At September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.46 .

The constraints specified in the Credit Agreement would have permitted an additional $ 3.17 billion in short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65 .

Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $ 717.9 million.

As a result, at September 30, 2024, $ 358.9 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 .

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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However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement.

In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable.

In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $ 40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $ 40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

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.

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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 existing indenture covenants at September 30, 2023, the Company would have been permitted to issue up to a maximum of approximately $ 3.43 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Company's Credit Agreement, as discussed above).

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

It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued.

Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions.

The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt.

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.

The Company’s 1974 indenture pursuant to which $ 50.0 million (or 2.1 %) of the Company’s long-term debt (as of September 30, 2023) was issued, 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.

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.

8 unchanged sentences

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

At Fair Value as of September 30, 2024

18 unchanged sentences

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

At Fair Value as of September 30, 2023

3 unchanged sentences

Cash Equivalents — Money Market Mutual Funds $ 39,332 $ — $ — $ — $ 39,332

Hedging Collateral Deposits 91,670 — — — 91,670

Derivative Financial Instruments:

Over the Counter Swaps — Gas — 65,800 — ( 37,508 ) 28,292

Over the Counter No Cost Collars — Gas — 30,966 — ( 14,745 ) 16,221

Contingent Consideration for Asset Sale — 7,277 — — 7,277

12 unchanged sentences

The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of September 30, 2024, 2023 and 2022 (in thousands):

Nonrecurring Fair Value Measures Year Ended September 30,

Segment Date of Measurement Fair Value 2024 2023 2022

Impairment of Assets:

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 — —

Total Impairment $ 55,437 $ — $ —

Northern Access Project

On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein.

Substantial litigation ensued over the next several years concerning various federal and state authorizations for the project, with the majority of project development activities suspended pending resolution.

These legal actions included, most recently, an appeal of FERC’s June 2022 order granting Supply Corporation and Empire an extension of time to construct the project through December 31, 2024.

In March 2024, the U.S.

Court of Appeals for the D.C.

Circuit issued an order affirming FERC’s extension of time, with such order final as of late June 2024.

Upon resolution of the extensive litigation, Supply Corporation and Empire began to assess next steps for the project, including a review of the status of necessary federal and state authorizations, as well as potential changes in expected capital expenditures and the related transportation rates

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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.

Upon receipt, Seneca indicated it was unwilling to accept the revised transportation rates and intended to terminate the precedent agreements for the project.

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

Accordingly, the Company will no longer pursue construction of the Northern Access project and has taken 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.

Hedging collateral deposits of $ 91.7 million at September 30, 2022, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1.

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 and crude oil trading markets).

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

The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates.

4 unchanged sentences

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.

For the years ended September 30, 2023 and 2022, there were no assets or liabilities measured at fair value and classified as Level 3.

Note J — Financial Instruments

6 unchanged sentences

Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value.

The fair value of long-term debt was calculated using observable inputs (U.S.

Treasuries for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt).

As such, the Company considers the debt to be Level 2.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost.

Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are

The fair value of long-term debt was calculated using observable inputs

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

considered to be Level 2.

Treasuries or SOFR for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt).

As such, the Company considers the debt to be Level 2.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost.

Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2.

Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

17 unchanged sentences

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

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 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.

1 unchanged sentence

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 $ 0.9 million mark-to-market adjustment was recorded during the year ended September 30, 2023.

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 Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2024 and September 30, 2023.

Cash Flow Hedges

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Cash Flow Hedges

As of September 30, 2024, the Company had 349.4 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

2 unchanged sentences

Of this amount, it is expected that $ 33.3 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 losses will be being reclassified into the Consolidated Statement of Income in subsequent periods.

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

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

27 unchanged sentences

Total $ 286,894 $ 708,206 $ 216,655 $ ( 88,656 )

(1) On June 30, 2022, the Company completed the sale of Seneca's California assets.

Because of this sale, the Company terminated its remaining crude oil derivative contracts and discontinued hedge accounting for such contracts.

A loss of $ 44.6 million was reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet to Operating Revenues on the Consolidated Statement of Income for the year ended September 30, 2022.

This loss is included in the reported reclassification amounts.

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position.

2 unchanged sentences

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 eleven are in a net gain position.

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.

On average, the Company had $ 5.1 million of credit exposure per counterparty in a gain position at September 30, 2024.

2 unchanged sentences

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, 2023, 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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 extended to the Company would either increase or decrease.

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 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, 2023, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $ 7.7 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, 2023.

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.

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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The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets.

The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(from previous years) that have not been reflected in net periodic benefit costs.

The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs.

The expected return on other post-retirement benefit assets (i.e.

the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below.

11 unchanged sentences

Retiree Drug Subsidy Receipts — — — 1,208 2,969 312

Actuarial Gain ( 27,313 ) ( 251,173 ) ( 8,141 ) ( 20,789 ) ( 120,276 ) ( 34,729 )

Actuarial (Gain) Loss 72,016 ( 27,313 ) ( 251,173 ) 54,443 ( 20,789 ) ( 120,276 )

Benefits Paid ( 66,215 ) ( 65,468 ) ( 65,040 ) ( 28,300 ) ( 26,717 ) ( 25,631 )

55 unchanged sentences

These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee.

The net periodic benefit costs associated with these plans were $ 8.3 million, $ 8.9

The net periodic benefit costs associated with these plans were $ 9.5 million, $ 8.3 million and $ 8.9

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

million and $ 8.3 million in 2023, 2022 and 2021, respectively.

million in 2024, 2023 and 2022, respectively.

The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on the Consolidated Statements of Income.

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Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)

Net Actuarial Gain (Loss) $ ( 128,118 ) $ 18,440 $ ( 17,286 )

Net Actuarial Loss $ ( 164,328 ) $ ( 128 ) $ ( 13,394 )

Prior Service (Cost) Credit ( 1,674 ) 686 —

1 unchanged sentence

Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2024(1)

Increase in Actuarial Gain (Loss), excluding amortization(2) $ ( 34,305 ) $ 12,626 $ ( 2,139 )

Increase in Actuarial Loss, excluding amortization(2) $ ( 34,871 ) $ ( 16,302 ) $ ( 880 )

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

4 unchanged sentences

In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2024, the Company recorded a $ 36.0 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $ 15.0 million (pre-tax) decrease to Accumulated Other Comprehensive Income.

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

The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2023 by $ 0.7 million.

The effect of the discount rate change for the Retirement Plan in 2024 was to increase the projected benefit obligation of the Retirement Plan by $ 69.6 million.

Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2024 by $ 2.5 million.

The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

benefit obligation of the Retirement Plan by $ 262.2 million.

The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected benefit obligation of the Retirement Plan by $ 262.2 million.

The Company did not make any cash contributions to the Retirement Plan during the year ended September 30, 2024.

The Company expects that the annual contribution to the Retirement Plan in 2024 will be in the range of zero to $ 5.0 million.

The Company does not expect to make any contributions to the Retirement Plan in 2025.

The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter:

5 unchanged sentences

and $ 305.1 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 health care 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.

5 unchanged sentences

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 effect of the discount rate change in 2021 was to decrease the other post-retirement benefit obligation by $ 2.5 million.

The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2021 by $ 2.0 million.

The health care cost trend rates were updated, which decreased the other post-retirement benefit obligation in 2021 by $ 3.7 million.

Other actuarial experience decreased the other post-retirement benefit obligation in 2021 by $ 26.6 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.

22 unchanged sentences

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

The Company did not make any cash contributions to its VEBA trusts during the year ended September 30, 2023.

In addition, the Company made direct payments of $ 0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2023.

The Company does not expect to make any contributions to its VEBA trusts in 2024.

(3) It was assumed that this rate would gradually decline to 4 % by 2046.

The Company made direct payments of $ 0.5 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2024.

The Company did not make any cash contributions to its VEBA trusts during the year ended September 30, 2024, and does not expect to make any contributions to its VEBA trusts in 2025.

Investment Valuation

7 unchanged sentences

Domestic Equities(1) $ 37,984 $ 37,984 $ — $ — $ —

International Equities(2) — — — — —

Global Equities(2) 38,234 — — — 38,234

15 unchanged sentences

Domestic Equities(1) $ 37,611 $ 37,611 $ — $ — $ —

International Equities(2) 1,363 — — — 1,363

Global Equities(2) 36,088 — — — 36,088

10 unchanged sentences

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

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

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

1 unchanged sentence

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

(6) Real Estate consists of investments held in a collective trust fund and a real estate investment trust.

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

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

(7) Domestic Fixed Income securities include $ 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.

At September 30, 2024

28 unchanged sentences

Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3).

For the years ended September 30, 2024 and September 30, 2023, there were no transfers from Level 1 to Level 2.

In addition, as shown in the following tables, there were no transfers in or out of Level 3.

Retirement Plan Level 3 Assets

Estate Excluding

Investments Total

Balance at September 30, 2021

$ 319 $ ( 24 ) $ 295

Unrealized Gains/(Losses) 234 ( 18 ) 216

Sales ( 553 ) 42 ( 511 )

Balance at September 30, 2022

Unrealized Gains/(Losses) — — —

Balance at September 30, 2023

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other Post-Retirement Benefit Level 3 Assets

Balance at September 30, 2021

Unrealized Gains/(Losses) 18

Balance at September 30, 2022

Unrealized Gains/(Losses) —

Balance at September 30, 2023

For the years ended September 30, 2024 and September 30, 2023, there were no assets or liabilities measured at fair value and classified as Level 3.

The Company’s assumption regarding the expected long-term rate of return on plan assets is 6.60 % (Retirement Plan) and 5.40 % (other post-retirement benefits), effective for fiscal 2025.

5 unchanged sentences

The assets of the Retirement Plan trust, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity.

In fiscal 2021 and fiscal 2022, capital market conditions led to significant improvements in the funded status of the Retirement Plan.

As a result, the Company reduced the return seeking portion of its assets during both years, particularly equity securities and return seeking fixed income securities, held in the Retirement Plan, and increased its allocation to hedging fixed income securities in conjunction with the Company’s liability driven investment strategy.

The actual asset allocations as of September 30, 2023 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets.

The actual asset allocations as of September 30, 2024 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets in conjunction with the Company’s liability driven investment strategy.

Given the level of the VEBA trust and 401(h) assets in relation to the Other Post-Retirement Benefits, the majority of those assets are and will remain in fixed income securities.

1 unchanged sentence

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

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

The individual spot rates along the yield curve are determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile are excluded based on the assumption that the Company would not utilize more expensive (i.e.

lower yield) instruments to settle its liabilities.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

benefit payment in order to determine the discount rate.

lower yield) instruments to settle its liabilities.

Note L — Commitments and Contingencies

5 unchanged sentences

The Company’s liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2024.

The Company has recovered its environmental clean-up costs through rate recovery and is currently not aware of any material additional exposure to environmental liabilities.

The Company has a regulatory liability of $ 5.4 million related to environmental clean-up costs at September 30, 2024 and is currently not aware of any material additional exposure to environmental liabilities.

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

Northern Access Project

On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein.

Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017).

Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.

FERC denied rehearing requests associated with its Order and FERC's decisions were appealed.

The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders.

In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted.

The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project, which is the subject of an ongoing appeal at the U.S.

Court of Appeals for the D.C.

As of September 30, 2023, the Company has spent approximately $ 55.9 million on the project, all of which is recorded on the balance sheet.

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.

6 unchanged sentences

As of September 30, 2024, the future contractual commitments related to the system modernization and expansion projects are $ 86.3 million in 2025, $ 8.7 million in 2026, $ 6.5 million in 2027, $ 3.8 million in 2028, $ 3.8 million in 2029 and $ 3.9 million thereafter.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 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.

3 unchanged sentences

These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things.

While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

While these other matters arising in the normal course of business could have a material effect on

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Note M — Business Segment Information

8 unchanged sentences

The Gathering segment is comprised of Midstream Company’s operations.

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

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.

18 unchanged sentences

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

Income Tax Expense (Benefit)

21 unchanged sentences

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

Significant Item:

Gain on Sale of Assets

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

Segment Profit:

13 unchanged sentences

Revenue from External Customers(1)(3) $ 1,010,464 $ 265,415 $ 12,086 $ 897,916 $ 2,185,881 $ — $ 165 $ 2,186,046

$ 836,697 $ 234,397 $ 3,116 $ 666,920 $ 1,741,130 $ 1,173 $ 356 $ 1,742,659

Intersegment Revenues

6 unchanged sentences

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

Significant Non-Cash Item:

Impairment of Oil and Gas Producing Properties

$ 76,152 $ — $ — $ — $ 76,152 $ — $ — $ 76,152

Significant Item:

17 unchanged sentences

United States $ 7,963,851 $ 7,865,832 $ 7,135,131

Note N — Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)

The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows.

The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period.

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

The Company follows authoritative guidance related to exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows.

The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of first day of the month commodity price for each month within the twelve month period prior to the end of the reporting period.

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

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)

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

As discussed in Note B — Asset Acquisitions and Divestitures, the Company completed the sale of its California assets on June 30, 2022.

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 Oil and Gas Producing Activities

Capitalized Costs Relating to Exploration and Production Activities

At September 30

21 unchanged sentences

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Costs Incurred in Property Acquisition, Exploration and Development Activities

Year Ended September 30

8 unchanged sentences

$ 565,282 $ 734,138 $ 561,239

(1) Amounts for 2023, 2022 and 2021 include capitalized interest of zero , zero and $ 0.1 million respectively.

(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.

15 unchanged sentences

270,648 235,694 202,418

Impairment of Oil and Gas Producing Properties — — 76,152

Income Tax Expense 145,574 368,925 98,593

Impairment of Exploration and Production Properties 463,692 — —

Income Tax Expense (Benefit) ( 76,983 ) 145,574 368,925

Results of Operations for Producing Activities (excluding corporate overheads and interest charges)

6 unchanged sentences

Reserve Quantity Information

The Company's proved oil and gas reserve estimates are prepared by the Company's petroleum engineers who meet the qualifications of Reserve Estimator per the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers as of June 25, 2019.

The Company’s proved reserve estimates are prepared by the Company’s petroleum engineers who meet the qualifications of Reserve Estimator per the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information” promulgated by the Society of Petroleum Engineers as of June 25, 2019.

The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.

23 unchanged sentences

Production ( 341,700 ) (2) ( 1,211 ) ( 342,911 )

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

September 30, 2022 4,170,662 — 4,170,662

2 unchanged sentences

Production ( 372,271 ) (2) — ( 372,271 )

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

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

September 30, 2023 4,535,084 — 4,535,084

2 unchanged sentences

Production ( 392,047 ) (2) — ( 392,047 )

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

September 30, 2024 4,751,762 — 4,751,762

21 unchanged sentences

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

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

September 30, 2022 250 — 250

Extensions and Discoveries — 296 296

Revisions of Previous Estimates ( 4 ) — ( 4 )

Production ( 30 ) — ( 30 )

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

September 30, 2023 216 — 216

14 unchanged sentences

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, 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.

1 unchanged sentence

PUD reserves in the Utica Shale increased from 503 Bcfe at September 30, 2022 to 873 Bcfe at September 30, 2023.

PUD reserves in the Marcellus Shale increased from 220 Bcfe at September 30, 2021 to 355 Bcfe at September 30, 2022.

PUD reserves in the West Coast region decreased from 5 Bcfe at September 30, 2021 to zero at September 30, 2022.

PUD reserves in the Marcellus Shale decreased from 355 Bcfe at September 30, 2022 to 112 Bcfe at September 30, 2023.

The Company’s total PUD reserves were 21.7 % of total proved reserves at September 30, 2023, up from 20.6 % of total proved reserves at September 30, 2022.

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 ( 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.

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)

The increase in PUD reserves in 2022 of 222 Bcfe is a result of 502 Bcfe in new PUD reserve additions and 23 Bcfe in upward revisions to remaining PUD reserves, partially offset by 287 Bcfe in PUD conversions to developed reserves ( 55 Bcfe from the Marcellus Shale, 231 Bcfe from the Utica Shale and 1 Bcfe from the West Coast region), and 13 Bcfe in PUD reserves removed for one Utica PUD location due to pad layout changes.

The remaining change of 3 Bcf was due to removing West Coast region PUDs included in the beginning of year balances through development and divesture of Seneca's California assets.

( 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 $ 306 million during the year ended September 30, 2024 to convert 291 Bcfe ( 374 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves.

1 unchanged sentence

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.

The Company invested $ 342 million during the year ended September 30, 2023 to convert 402 Bcfe ( 440 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves.

This represents 47 % of the net PUD reserves recorded at September 30, 2022.

In the Appalachian region, 31 of 65 PUD locations were developed while the West Coast region developed 6 of 17 PUD locations prior to the divesture.

PUD expenditures in 2022 were lower than the 2021 estimate primarily due to changes in the development schedule.

The Company developed 39 of 77 PUD locations in 2023.

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

In 2025, the Company estimates that it will invest approximately $ 300 million to develop its PUD reserves.

3 unchanged sentences

All of the Company’s proved reserves are in the United States.

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

The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production.

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

The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s exploration and production properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production.

It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage.

Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes.

Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes.

It assumes an arbitrary discount rate of 10 %.

Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.

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

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

NATIONAL FUEL GAS COMPANY

29 unchanged sentences

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