What changed in this filing

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Item 8. Financial Statements and Supplementary Data

2023-11-17 compared with 2022-11-18 · 298 added, 348 removed, 1736 unchanged (27% of the section changed)

49 unchanged sentences

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

As of September 30, 2022, the ceiling exceeded the book value of the natural gas properties by approximately $3.2 billion.

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

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”).

1 unchanged sentence

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 the data, methods, and assumptions used by management and its specialists in developing the estimates 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 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.

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 that are utilized in the DD&A expense and ceiling test calculations.

These procedures also included, among others, evaluating the reasonableness of the significant assumptions used by management related to the quantities of natural gas that are ultimately recovered.

Evaluating the reasonableness of the significant assumptions included evaluating information on additional development activity, production history, if the assumptions used were reasonable considering the past performance of the Company, and whether they were 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.

As a basis for using this work, the specialists’ qualifications and objectivity 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 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 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.

/s/ P RICEWATERHOUSE C OOPERS LLP

32 unchanged sentences

Other Interest Expense ( 19,938 ) ( 9,850 ) ( 4,900 )

Income (Loss) Before Income Taxes 682,650 478,329 ( 105,033 )

Income Before Income Taxes 641,399 682,650 478,329

Income Tax Expense 164,533 116,629 114,682

Net Income (Loss) Available for Common Stock 566,021 363,647 ( 123,772 )

Net Income Available for Common Stock 476,866 566,021 363,647

EARNINGS REINVESTED IN THE BUSINESS

2 unchanged sentences

Dividends on Common Stock ( 178,095 ) ( 170,111 ) ( 164,102 )

Cumulative Effect of Adoption of Authoritative Guidance for

Balance at End of Year $ 1,885,856 $ 1,587,085 $ 1,191,175

Earnings (Loss) Per Common Share:

Net Income (Loss) Available for Common Stock $ 6.19 $ 3.99 $ ( 1.41 )

Net Income (Loss) Available for Common Stock $ 6.15 $ 3.97 $ ( 1.41 )

Earnings Per Common Share:

Net Income Available for Common Stock $ 5.20 $ 6.19 $ 3.99

Net Income Available for Common Stock $ 5.17 $ 6.15 $ 3.97

Weighted Average Common Shares Outstanding:

7 unchanged sentences

(Thousands of dollars)

Net Income (Loss) Available for Common Stock $ 566,021 $ 363,647 $ ( 123,772 )

Net Income Available for Common Stock $ 476,866 $ 566,021 $ 363,647

Other Comprehensive Income (Loss), Before Tax:

7 unchanged sentences

88,656 882,581 83,711

Cumulative Effect of Adoption of Authoritative Guidance for Hedging

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

7 unchanged sentences

5,806 241,559 22,465

Income Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging

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

17 unchanged sentences

Gas Stored Underground 32,509 32,364

Materials, Supplies and Emission Allowances 40,637 53,560

Materials and Supplies - at average cost 48,989 40,637

Unrecovered Purchased Gas Costs — 99,342

42 unchanged sentences

Other Regulatory Liabilities 165,441 188,803

Pension and Other Post-Retirement Liabilities 3,065 7,526

Other Post-Retirement Liabilities 2,915 3,065

Asset Retirement Obligations 165,492 161,545

10 unchanged sentences

Operating Activities

Net Income (Loss) Available for Common Stock $ 566,021 $ 363,647 $ ( 123,772 )

Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:

Net Income Available for Common Stock $ 476,866 $ 566,021 $ 363,647

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

Gain on Sale of Assets — ( 12,736 ) ( 51,066 )

23 unchanged sentences

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

Acquisition of Upstream Assets and Midstream Gathering Assets — — ( 506,258 )

Acquisition of Upstream Assets ( 124,758 ) — —

Other 12,279 8,683 13,935

1 unchanged sentence

Financing Activities

Change in Notes Payable to Banks and Commercial Paper ( 98,500 ) 128,500 ( 25,200 )

Proceeds from Issuance of Short-Term Note Payable to Bank 250,000 — —

Repayment of Short-Term Note Payable to Bank ( 250,000 ) — —

Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper 227,500 ( 98,500 ) 128,500

Net Proceeds from Issuance of Long-Term Debt 297,306 — 495,267

Reduction of Long-Term Debt ( 549,000 ) — ( 515,715 )

Net Proceeds from Issuance (Repurchase) of Common Stock ( 9,590 ) ( 3,702 ) 161,603

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

Dividends Paid on Common Stock ( 176,096 ) ( 168,147 ) ( 163,089 )

Net Cash Provided by (Used in) Financing Activities ( 276,237 ) ( 58,739 ) 476,088

Net Cash Used in Financing Activities ( 206,999 ) ( 276,237 ) ( 58,739 )

Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash ( 82,271 ) 17,580 99,597

2 unchanged sentences

Supplemental Disclosure of Cash Flow Information

Cash Paid (Refunded) For:

Cash Paid For:

Interest $ 124,441 $ 124,312 $ 135,136

19 unchanged sentences

The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment.

Account balances are charged 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.

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.

Activity in the allowance for uncollectible accounts are as follows:

10 unchanged sentences

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

1 unchanged sentence

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

rates of retail customers to reflect the impact of deviations from normal weather.

The WNC 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.

Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations 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 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.

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.

17 unchanged sentences

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 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 $ 1.9 billion at September 30, 2022 and 2021.

Under this methodology, all costs

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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'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.

4 unchanged sentences

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, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $ 3.2 billion.

In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2022, 2021 and 2020, estimated future net cash flows were decreased by $ 1.0 billion, decreased by $ 76.1 million and increased by $ 180.0 million, respectively.

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 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.

6 unchanged sentences

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 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 service lives of property in service.

The following is a summary of depreciable plant by segment:

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of September 30

5 unchanged sentences

$ 13,101,006 $ 12,233,508

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Average depreciation, depletion and amortization rates are as follows:

23 unchanged sentences

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Income (Loss) and changes for the years ended September 30, 2022 and 2021, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands):

Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss and changes for the years ended September 30, 2023 and 2022, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands):

Gains and Losses on Derivative Financial Instruments Funded Status of the Pension and Other Post-Retirement Benefit Plans Total

3 unchanged sentences

Other Comprehensive Gains and Losses Before Reclassifications 493,936 ( 7,376 ) 486,560

Amounts Reclassified From Other Comprehensive Income (Loss) 641,022 8,480 649,502

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

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

Balance at September 30, 2023

4 unchanged sentences

Other Comprehensive Gains and Losses Before Reclassifications ( 763,223 ) 7,392 ( 755,831 )

Amounts Reclassified From Other Comprehensive Income (Loss) 61,246 12,467 73,713

Amounts Reclassified From Other Comprehensive Loss 641,022 8,480 649,502

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

Balance at September 30, 2022

$ ( 572,163 ) $ ( 53,570 ) $ ( 625,733 )

The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses.

The total amount for prior service cost was $ 0.4 million and $ 0.7 million at September 30, 2022 and 2021, respectively.

The amounts included in accumulated other comprehensive loss related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses.

The total amount for prior service cost was $ 0.4 million at both September 30, 2023 and 2022.

The total amount for accumulated losses was $ 59.3 million and $ 53.2 million at September 30, 2023 and 2022, respectively.

1 unchanged sentence

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.

For further discussion of this regulatory proceeding, refer to Note F — Regulatory Matters under the heading “Pennsylvania Jurisdiction.”

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the years ended September 30, 2022 and 2021 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Reclassifications Out of Accumulated Other Comprehensive Loss

The details about the reclassification adjustments out of accumulated other comprehensive loss for the years ended September 30, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other

Comprehensive Income (Loss) Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the

Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss

September 30, Affected Line Item in the Statement Where Net Income is Presented

17 unchanged sentences

Based upon the average price of spot market gas purchased in September 2023, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $ 3.7 million at September 30, 2023.

Materials, Supplies and Emission Allowances

The components of the Company's materials, supplies and emission allowances are as follows:

Year Ended September 30

Materials and Supplies — at average cost

$ 40,637 $ 34,880

Emission Allowances — 18,680

$ 40,637 $ 53,560

Unamortized Debt Expense

Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

At September 30, 2023, the remaining weighted average amortization period for such costs was approximately 4 years.

3 unchanged sentences

A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return.

16 unchanged sentences

Prepaid Property and Other Taxes 14,186 14,321

Federal Income Taxes Receivable 14,602 —

State Income Taxes Receivable 16,133 5,933

1 unchanged sentence

$ 100,260 $ 59,369

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other Accruals and Current Liabilities

7 unchanged sentences

$ 160,974 $ 257,327

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Customer Advances

9 unchanged sentences

Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares.

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.

There were 2,858 securities excluded as being antidilutive for the year ended September 30, 2022 and 320,222 securities excluded as being antidilutive for the year ended September 30, 2021.

As the Company recognized a net loss for the year ended September 30, 2020, the aforementioned potentially dilutive securities, amounting to 411,890 securities, were not recognized in the diluted earnings per share calculation for 2020.

There were 3,888 securities, 2,858 securities and 320,222 securities excluded as being antidilutive for the years ended September 30, 2023, 2022 and 2021, respectively.

Stock-Based Compensation

2 unchanged sentences

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

the date of each grant.

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

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.

5 unchanged sentences

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

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

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.

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

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

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

For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.

1 unchanged sentence

Note B — Asset Acquisitions and Divestitures

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

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC (“SWN”) for total consideration of $ 124.8 million.

The purchase price, which reflects an effective date of January 1, 2023, was reduced for production revenues less expenses that were retained by SWN from the effective date to the closing date.

As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets.

This transaction was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment.

The following is a summary of the asset acquisition in thousands:

Purchase Price $ 124,178

Transaction Costs 580

Total Consideration $ 124,758

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

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

6 unchanged sentences

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 July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $ 506.3 million.

The purchase price, which reflected an effective date of January 1, 2020, was reduced for production revenues less expenses that were retained by Shell from the effective date to the closing

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As part of the transaction, the Company acquired over 400,000 net acres in Appalachia, including approximately 200,000 net acres in Tioga County, Pennsylvania.

The proved developed and undeveloped natural gas reserves associated with this acquisition amounted to 684,141 MMcf.

In addition, the Company acquired gathering pipelines and related compression, water pipelines, and associated water handling infrastructure, all of which support the acquired Tioga County production operations.

These gathering facilities are interconnected with various interstate pipelines, including the Company’s Empire pipeline system, with the potential to tie into the Company’s existing Covington gathering system.

Post-closing, the Company has integrated the assets into its existing operations in Tioga County, which has resulted in cost synergies.

This transaction was accounted for as an asset acquisition as substantially all the fair value of the gross assets acquired is concentrated in a single asset under the screen test comprised of Proved Developed Producing Reserves and the attached Gathering Property, Plant and Equipment.

The purchase consideration, including the transaction costs, has been allocated to the individual assets acquired based on their relative fair values.

The following is a summary of the asset acquisition (in thousands):

Purchase Price $ 503,908

Transaction Costs 2,350

Total Consideration $ 506,258

Allocation of Cost of Asset Acquisition:

Exploration and Production Reporting Segment Gathering Reporting Segment Total

Property, Plant and Equipment $ 281,648 (1)(2) $ 223,369 (2) $ 505,017

Inventory 1,132 109 1,241

Total Accounting $ 282,780 $ 223,478 $ 506,258

(1) Includes $ 241,134 in Proved Developed Producing Properties and $ 277,832 capitalized in the full cost pool.

(2) The Company utilized an income approach and market based approach to determine the fair value of the acquired property, plant and equipment in the Exploration and Production reporting segment.

The Company utilized a cost approach and an income approach to determine the fair value of the acquired property, plant and equipment in the Gathering reporting segment.

The acquisition of the upstream assets and midstream gathering assets from Shell was financed with a combination of debt and equity, as discussed in Note H — Capitalization and Short-Term Borrowings.

The purchase and sale agreement with Shell was structured, in part, as a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”).

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.

1 unchanged sentence

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 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 of the timber properties completed the Reverse 1031 Exchange related to the Company’s acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell, as discussed above.

In connection with the Reverse 1031 Exchange, the Company, through a subsidiary, assigned the rights

Since the sale did not

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

to acquire legal title to certain oil and natural gas properties to a Variable Interest Entity ("VIE") formed by an exchange accommodation titleholder.

The Company evaluated the VIE to determine whether the Company should be considered as the primary beneficiary having a controlling financial interest.

It was determined that the Company had the power to direct the activities of the VIE and the obligation to absorb significant losses of that entity or the right to receive significant benefits from that entity.

Therefore, the Company was considered to be the primary beneficiary.

From July 31, 2020 to December 10, 2020, a subsidiary of the Company operated the properties pursuant to a lease agreement with the VIE.

As the Company was deemed to be the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements of the Company.

Upon completion of the sale of the timber properties on December 10, 2020, the affected properties were conveyed to the Company and the VIE structure was terminated.

On August 1, 2020, the Company completed the sale of NFR’s commercial and industrial gas contracts in New York and Pennsylvania and certain other assets to Marathon Power LLC.

This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's operations.

The sale did not have a material impact to the Company’s financial statements.

The divestiture reflects the Company’s decision to focus on other strategic areas of the energy market.

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

30 unchanged sentences

Total Revenues $ 958,455 $ 379,191 $ 230,317 $ 942,360 $ 2,510,323 $ — $ ( 336,552 ) $ 2,173,771

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Year Ended September 30, 2022

20 unchanged sentences

— — — 4,902 4,902 — — 4,902

Natural Gas Marketing — — — — — 678 ( 49 ) 629

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

6 unchanged sentences

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

10 unchanged sentences

Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract.

The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

9 unchanged sentences

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

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

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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.

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

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

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

Natural gas is delivered and consumed by the customer simultaneously.

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

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

The NYPSC has 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.

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

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conservation have on margin.

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

These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs.

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Note D — Leases

On October 1, 2019, the Company adopted authoritative guidance regarding lease accounting, which requires entities that lease the use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, including leases classified as operating leases.

The Company implemented the new standard using the optional transition method and elected to apply the following practical expedients provided in the authoritative guidance:

For contracts that commenced prior to and existed as of October 1, 2019, a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification, and initial direct costs under the new authoritative guidance;

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

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

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);

A practical expedient to not reassess certain land easements that existed prior to October 1, 2019 and were not previously accounted for as leases under the prior authoritative guidance;

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).

Upon adoption, the Company increased assets and liabilities on its Consolidated Balance Sheet by $ 19.7 million.

The adoption did not result in a cumulative effect adjustment to earnings reinvested in the business or have a material impact on the Company’s Consolidated Statement of Income or Consolidated

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Statement of Cash Flows.

Comparative periods, including disclosures relating to those periods, were not restated.

Nature of Leases

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The Company did not have any material finance leases as of September 30, 2023 or September 30, 2022.

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

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.

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 two months to seventeen years .

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 .

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The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania.

Seneca’s drilling rig arrangements are structured with a non-cancelable primary term that exceeds one year .

Seneca’s drilling rig arrangements are structured with a non-cancelable primary term of one year or less.

Upon mutual agreement with the contractor, Seneca has the option to extend contracts with amended terms and conditions, including a renegotiated day rate fee.

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

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Compressor Equipment

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The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability.

In the absence of a rate of interest that is

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readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each lease.

In the absence of a rate of interest that is readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each lease.

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

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The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers.

The Company’s firm capacity contracts with non-affiliated entities do not provide rights to use substantially all of the underlying pipeline or storage asset.

The Company’s firm capacity contracts with third party shippers do not provide rights to use substantially all of the underlying pipeline or storage asset.

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

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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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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 full cost pool accounting, 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 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.

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

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

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

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Other Liabilities $ 29,510 $ 22,881

Cash paid for lease liabilities, and reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $ 5.7 million and $ 6.7 million for the years ended September 30, 2022 and 2021, respectively.

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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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, 2023 (in thousands):

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Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.

The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s natural gas wells and has capitalized such costs in

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property, plant and equipment (i.e.

the full cost pool).

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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.

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

As discussed in Note B — Asset Acquisitions and Divestitures, on July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell.

With the acquisition of these assets, the Company recorded an additional $ 57.2 million to its Asset Retirement Obligation at September 30, 2020, which is reflected in Liabilities Incurred in the table below.

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

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Balance at End of Year $ 165,492 $ 161,545 $ 209,639

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Note F — Regulatory Matters

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Total Long-Term Regulatory Assets $ 148,423 $ 182,232

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At September 30

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Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 59,019 419

Environmental Site Remediation Costs(4) (Note L) 619 —

Other(6) 43,167 44,549

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

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(5) $ 5,800 and $ 30,000 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months.

(5) $ 5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2023 and 2022, since such amounts are expected to be passed back to ratepayers in the next 12 months.

$ 153,960 and $ 161,505 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively.

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Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from customers that will be used in the future to fund asset retirement costs.

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New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017.

The 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.

The order also 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, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022.

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

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

On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of $ 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 will no longer be funding the pension from its New York jurisdiction and it will not be funding its VEBA trusts in its New York jurisdiction.

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.

Pennsylvania Jurisdiction

Distribution Corporation’s current delivery rates 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 with a proposed effective date of December 27, 2022.

The Company is also proposing, among other things, to implement a weather normalization adjustment mechanism and a new energy efficiency and conservation pilot program for residential customers.

The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.

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.

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

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

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

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 customers overcollected OPEB expenses in the amount of $ 50.0 million.

Certain other matters in the tariff supplement were unresolved.

These matters were resolved with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision on February 24, 2022.

Concurrent with that decision, the Company discontinued regulatory 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

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

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amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount.

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.

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FERC Jurisdiction

Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased.

If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025.

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.

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Total Income Taxes $ 164,533 $ 116,629 $ 114,682

On March 27, 2020, the “Coronavirus Aid, Relief and Economic Security (CARES) Act” was signed into law.

The CARES Act, among other things, includes provisions relating to alternative minimum tax (AMT) credit refunds, refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, and modifications to the net interest deduction limitation.

The Company filed for the acceleration of the remaining AMT credit refunds (under CARES) of $ 42.5 million, which were received in June 2020.

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

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

The Company's deferred income taxes were re-measured based upon the new tax rates.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

during the quarter ended September 30, 2022.

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

This amount is reflected in State Income Taxes.

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

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

The provisions of the IRA did not have a material impact on the fiscal 2022 financial statements, although some of the provisions may be applicable in future years.

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

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.

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

The following is a reconciliation of this difference:

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2023 2022 2021

Income (Loss) Before Income Taxes (1) $ 682,650 $ 478,327 $ ( 105,046 )

Income Tax Expense (Benefit), Computed at

Income Before Income Taxes $ 641,399 $ 682,650 $ 478,329

Income Tax Expense, Computed at

Federal Statutory Rate of 21 %

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State Valuation Allowance (1) — ( 24,850 ) ( 5,560 )

State Income Taxes (Benefit) (3) 8,736 24,300 ( 18,374 )

State Income Taxes (2) 36,331 8,736 24,300

Amortization of Excess Deferred Federal Income Taxes ( 6,053 ) ( 5,184 ) ( 5,215 )

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Total Income Taxes $ 164,533 $ 116,629 $ 114,682

(1) Amounts include the impact of deferred investment tax credits reported in Other Income (Deductions) on the Consolidated Statements of Income.

(2) During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets.

During fiscal 2022, the valuation allowance was removed.

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

See discussion below.

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

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

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

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Deferred Tax Liabilities:

Unrealized Hedging Gains $ 3,385 $ —

Property, Plant and Equipment 1,178,893 954,757

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Other ( 48,349 ) ( 32,430 )

Total Gross Deferred Tax Assets ( 335,553 ) ( 376,238 )

Valuation Allowance

Total Deferred Tax Assets ( 123,936 ) ( 335,553 )

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

As of March 31, 2020, the Company recorded a valuation allowance against certain state deferred tax assets based on its conclusion, considering all available objective evidence and the Company’s history of subsidiary state tax losses, that it was more likely than not that the deferred tax assets would not be realized.

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

The deferred tax assets and valuation allowance were written off as the Company determined that there was a remote possibility for use as the Company no longer has California operations.

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

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

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

The conclusion was primarily related to the use of net operating losses in Pennsylvania in the current year due to sustained strong operating results as well as the expectation for future forecasted earnings in Pennsylvania due to increased natural gas prices.

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

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

Regulatory liabilities representing the reduction of previously recorded deferred inc ome taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $ 362.1 million and $ 354.1 million at September 30, 2022 and 2021, respectively.

Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amoun ted to $ 106.2 million and $ 122.0 million at September 30, 2022 and 2021, respectively.

The Company is in the Bridge Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2022.

The Bridge Phase is intended for taxpayers with a low risk of non-compliance who are cooperative and transparent with few, if any, material issues that require resolution.

The IRS will not accept any disclosures, conduct any reviews, or provide any letters of assurance for the Bridge year.

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

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

Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $ 268.6 million and $ 362.1 million at September 30, 2023 and 2022, respectively.

Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amounted to $ 69.0 million and $ 106.2 million at September 30, 2023 and 2022, 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 2023.

The CAP program is intended for taxpayers with a low risk of non-compliance who are cooperative and transparent with few, if any, material issues that require resolution.

The federal statute of limitations remains open for fiscal 2020 and later years.

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The Company’s principal subsidiaries have state statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.

Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which

Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which time the statute of limitation begins.

The Company has no unrecognized tax benefits as of September 30, 2023, 2022, or 2021.

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time the statute of limitation begins.

The Company has no unrecognized tax benefits as of September 30, 2022, 2021, or 2020.

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 Company is awaiting the issuance of IRS guidance addressing the issue for natural gas utilities.

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:

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Comprehensive

Income (Loss)

Shares Amount

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90,955 $ 90,955 $ 1,004,158 $ 991,630 $ ( 114,757 )

Net Loss Available for Common Stock ( 123,772 )

Net Income Available for Common Stock 363,647

Dividends Declared on Common Stock ($ 1.80 Per Share)

Cumulative Effect of Adoption of Authoritative Guidance for Hedging

Other Comprehensive Loss, Net of Tax ( 398,840 )

Share-Based Payment Expense(1) 15,297

Common Stock Issued from Sale of Common Stock

4,370 4,370 161,399

Common Stock Issued (Repurchased) Under Stock and Benefit Plans

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Dividends Declared on Common Stock ($ 1.94 Per Share)

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

Other Comprehensive Income, Net of Tax 570,673

Share-Based Payment Expense(1) 18,746

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The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock.

The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s

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

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common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions.

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

Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent.

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

During 2023, the Company did no t issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan or the Company's 401(k) plans.

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

The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers, as partial consideration for the directors’ services during the fiscal year.

The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers (the "DCP"), as partial consideration for the directors’ services during the fiscal year.

Under this program, the Company issued 31,715 original issue shares of common stock during 2023.

On June 2, 2020, the Company completed a public offering and sale of 4,370,000 shares of the Company's common stock, par value $ 1.00 per share, at a price of $ 39.50 per share.

After deducting fees, commissions and other issuance costs, the net proceeds to the Company amounted to $ 165.8 million.

The proceeds of this issuance were used to fund a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020.

Refer to Note B — Asset Acquisitions and Divestitures for further discussion.

In addition, the Company issued 2,796 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 2023.

Stock Award Plans

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To Option Weighted

Exercise Price Weighted

Life (Years) Aggregate

Exercise Price Aggregate

(In thousands)

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Expired in 2023

( 5,000 ) $ 55.09

Outstanding at September 30, 2023

72,008 $ 53.05 0.22 $ 612

SARs exercisable at September 30, 2023

72,008 $ 53.05 0.22 $ 612

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

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

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, 2022 totaled approximately $ 2.0 million.

During the years ended September 30, 2021 and 2020, no SARs were exercised.

There were no SARs that became fully vested during the years ended September 30, 2022, 2021 and 2020, and all SARs outstanding have been fully vested since fiscal 2017.

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

The performance goal over the performance cycle for the ESG performance shares granted during 2022 consists of two parts:

The performance goal over the respective performance cycles for the ESG performance shares granted during 2023 and 2022 consists of two parts:

reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions.

The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance that helps position the Company to meet or exceed its 2030 methane intensity and greenhouse gas reduction targets.

The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards the Company's 2030 goals.

The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target.

The fair value of these ESG performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award.

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

There were no ESG performance shares granted in 2021 and 2020.

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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.

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Medium-Term Notes(1):

7.4 % due March 2023 to June 2025

7.4 % due June 2025

$ 50,000 $ 99,000

Notes(1)(2)(3):

2.95 % to 5.50 % due March 2023 to March 2031

2.95 % to 5.50 % due July 2025 to March 2031

2,350,000 2,550,000

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

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

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

The interest rate payable on $ 500.0 million of 5.50 % notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00 %, such that the coupon will not exceed 7.50 %, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade.

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) Current Portion of Long-Term Debt at September 30, 2022 consists of $ 500.0 million of 3.75 % notes and $ 49.0 million of 7.395 % notes that each mature in March 2023.

The Company has committed to redeeming $ 150.0 million of the 3.75 % notes on November 25, 2022.

(4) 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 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.

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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.

On June 3, 2020, the Company issued $ 500.0 million of 5.50 % notes due January 15, 2026.

After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $ 493.0 million.

The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.

As of September 30, 2023, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows:

$ 549.0 million in 2023, zero in 2024, $ 500.0 million in 2025, $ 500.0 million in 2026, $ 300.0 million in 2027, and $ 800.0 million thereafter.

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.

Short-Term Borrowings

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

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 is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the Company's outstanding long-term debt maturing in March 2023.

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

NATIONAL FUEL GAS COMPANY

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.

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

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The commercial paper program is backed by the Credit Agreement.

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, 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.

The Company had outstanding commercial paper of $ 158.5 million at September 30, 2021, with a weighted average interest rate on the commercial paper of 0.40 %.

The Company did not have any outstanding short-term notes payable to banks at September 30, 2021.

Debt Restrictions

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

As a result, at September 30, 2022, $ 190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement and 364-Day Credit Agreement.

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.

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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.

The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement.

At September 30, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and 364-Day Credit Agreement, was .49 .

The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $ 2.56 billion in short-term and/or long-term debt to be outstanding at September 30, 2022 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65 .

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 .

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 and 364-Day Credit Agreement 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 and 364-Day Credit Agreement.

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

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)

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.

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.

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, 2022, the Company would have been permitted to issue up to a maximum of approximately $ 2.0 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.

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.

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

The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties have historically entered into both gas and oil swap agreements with the Company.

NATIONAL FUEL GAS COMPANY

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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

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Derivative Financial Instruments:

Over the Counter Swaps — Gas and Oil — 1,802 — ( 1,802 ) —

Over the Counter Swaps — Gas — 5,177 — ( 4,178 ) 999

Contingent Consideration for Asset Sale — 8,176 — — 8,176

Foreign Currency Contracts — 128 — ( 128 ) —

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Derivative Financial Instruments:

Over the Counter Swaps — Gas and Oil $ — $ 601,551 $ — $ ( 1,802 ) $ 599,749

Over the Counter Swaps — Gas $ — $ 517,464 $ — $ ( 4,178 ) $ 513,286

Over the Counter No Cost Collars — Gas — 270,453 — — 270,453

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At September 30, 2023, 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.

The derivative financial instruments reported in Level 2 at September 30, 2021 consist of the same type of instruments in addition to crude oil price swap agreements.

The use of crude oil price swap agreements was discontinued during the year ended September 30, 2022 in conjunction with the sale of the Exploration and Production segment's California assets.

Hedging collateral deposits of $ 91.7 million (at September 30, 2022) and $ 88.6 million (at September 30, 2021), which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1.

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.

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

The fair value of the Level 2 foreign currency contracts at September 30, 2022 and September 30, 2021 are determined using the market approach based on observable market transactions of forward Canadian currency rates.

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

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

The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.

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To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

Derivative financial instruments reported in Level 2 at September 30, 2022 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note B — Asset Acquisitions and Divestitures and at Note J — Financial Instruments.

Derivative financial instruments reported in Level 2 at September 30, 2023 and September 30, 2022 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note B — Asset Acquisitions and Divestitures and at Note J — Financial Instruments.

The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk.

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At September 30

Fair Value 2021

Long-Term Debt $ 2,384,485 $ 2,210,478 $ 2,632,409 $ 2,453,209

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay.

Carrying amounts for other financial instruments recorded on the Company’s Consolidated

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Balance Sheets approximate fair value.

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.

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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.

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

considered to be Level 2.

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

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

The Company enters into over-the-counter no cost collars and over-the-counter swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas.

The Company enters into over-the-counter no cost collar and swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas.

In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment.

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

The fair value of this contingent consideration was estimated to be $ 12.6 million and $ 8.2 million at June 30, 2022 and September 30, 2022, respectively.

A $ 4.4 million mark-to-market adjustment was recorded during the quarter ended September 30, 2022.

The fair value of this contingent consideration was estimated to be $ 7.3 million and $ 8.2 million at September 30, 2023 and September 30, 2022, respectively.

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

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, 2023 and September 30, 2022.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of September 30, 2023, the Company had 411.3 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of September 30, 2023, the Company was hedging a total of $ 56.9 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of September 30, 2022, the Company had $ 784.7 million ($ 572.2 million after-tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance.

It is expected that $ 476.7 million ($ 347.6 million after-tax) of such unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.

As of September 30, 2023, the Company had $ 4.6 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance.

Of this amount, it is expected that $ 11.5 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 Effect of Derivative Financial Instruments on the Statement of Financial Performance for the

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The majority of the Company’s counterparties are financial institutions and energy traders.

The Company has over the-counter swap positions, no cost collars and applicable foreign currency forward contracts with nineteen counterparties of which one is in a net gain position.

The Company had $ 1.0 million of credit exposure with the counterparty in a gain position at September 30, 2022.

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.

On average, the Company had $ 3.9 million of credit exposure per counterparty in a gain position at September 30, 2023.

The maximum credit exposure per counterparty in a gain position at September 30, 2023 was $ 16.1 million.

As of September 30, 2023, no collateral was received from the counterparties by the Company.

The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

As of September 30, 2022, seventeen 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

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

applicable foreign currency forward contracts) had a common credit-risk related contingency feature.

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.

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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, 2022, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $ 564.3 million according to the Company's internal model (discussed in Note I — Fair Value Measurements) and the Company posted $ 91.7 million in hedging collateral deposits.

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.

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

The expected return on other

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)

post-retirement benefit assets (i.e.

(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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Retiree Drug Subsidy Receipts — — — 2,969 312 1,244

Actuarial (Gain) Loss ( 251,173 ) ( 8,141 ) 65,908 ( 120,276 ) ( 34,729 ) 16,396

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

Benefits Paid ( 65,468 ) ( 65,040 ) ( 64,059 ) ( 26,717 ) ( 25,631 ) ( 26,145 )

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Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2023(1)

Decrease (Increase) in Actuarial Loss, excluding amortization(2) $ ( 7,006 ) $ ( 3,932 ) $ 8,222

Change due to Amortization of Actuarial Loss 26,405 ( 7,610 ) 6,301

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

Change due to Amortization of Actuarial (Gain) Loss ( 7,680 ) ( 8,755 ) 3,572

Prior Service (Cost) Credit 436 ( 429 ) —

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

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

In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2022, the Company recorded a $ 1.9 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $ 20.6 million (pre-tax) increase to Accumulated Other Comprehensive Income.

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

In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2023, the Company recorded a $ 28.7 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $ 8.0 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 increased the projected benefit obligation of the Retirement Plan in 2022 by $ 1.8 million.

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

Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2023 by $ 1.8 million.

The effect of the discount rate change for the Retirement Plan in 2021 was to decrease the projected benefit

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

obligation of the Retirement Plan by $ 11.2 million.

The effect of the discount rate change for the Retirement Plan in 2020 was to increase the projected benefit obligation of the Retirement Plan by $ 61.3 million.

The Company made cash contributions totaling $ 20.4 million to the Retirement Plan during the year ended September 30, 2022.

benefit obligation of the Retirement Plan by $ 262.2 million.

The effect of the discount rate change for the Retirement Plan in 2021 was to decrease the projected benefit obligation of the Retirement Plan by $ 11.2 million.

The Company did not make any cash contributions to the Retirement Plan during the year ended September 30, 2023.

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

7 unchanged sentences

The effect of the discount rate change in 2023 was to decrease the other post-retirement benefit obligation by $ 10.7 million.

The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2023 by $ 0.4 million.

The health care cost trend rates were updated, which increased the other post-retirement benefit obligation in 2023 by $ 3.2 million.

Other actuarial experience decreased the other post-retirement benefit obligation in 2023 by $ 12.9 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

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

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

4 unchanged sentences

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 effect of the discount rate change in 2020 was to increase the other post-retirement benefit obligation by $ 25.4 million.

The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2020 by $ 2.5 million.

Other actuarial experience decreased the other post-retirement benefit obligation in 2020 by $ 6.5 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

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

22 unchanged sentences

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

The Company made cash contributions totaling $ 2.8 million to its VEBA trusts during the year ended September 30, 2022.

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.

31 unchanged sentences

International Fixed Income(5) 7,782 — 7,782 — —

Global Fixed Income(6) 42,454 — — — 42,454

Real Estate (6) 140,739 — — — 140,739

11 unchanged sentences

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

(6) Global Fixed Income securities are comprised of a collective trust fund.

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

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

38 unchanged sentences

Unrealized Gains/(Losses) 234 ( 18 ) 216

Sales ( 553 ) 42 ( 511 )

Balance at September 30, 2022

319 ( 24 ) 295

Unrealized Gains/(Losses) — — —

Sales ( 553 ) 42 ( 511 )

Balance at September 30, 2023

32 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, 2023.

The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately one year and is currently not aware of any material additional exposure to environmental liabilities.

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.

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

6 unchanged sentences

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.

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.

7 unchanged sentences

As of September 30, 2023, the future contractual commitments related to the system modernization and expansion projects are $ 74.9 million in 2024, $ 8.4 million in 2025, $ 7.2 million in 2026, $ 5.9 million in 2027, $ 3.3 million in 2028 and $ 4.7 million thereafter.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 $ 282.5 million in 2023, $ 180.4 million in 2024 and $ 153.8 million in 2025, and $ 43.8 million in 2026.

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 $ 279.5 million in 2024, $ 185.1 million in 2025, and $ 47.3 million in 2026.

There are no contractual commitments extending beyond 2026.

The Company is involved in other litigation arising in the normal course of business.

In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business.

These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings.

In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved in other regulatory and litigation matters arising in the normal course of business.

These other regulatory and litigation matters may include, for example, tax, regulatory or other governmental audits, inspections, investigations, negligence claims and other proceedings.

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

33 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:

11 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:

28 unchanged sentences

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

Significant Item:

Gain on Sale of Assets

$ — $ — $ — $ — $ — $ 51,066 $ — $ 51,066

Segment Profit:

6 unchanged sentences

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

(2) Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $ 208 million of the Company's consolidated revenue for the year ended September 30, 2023.

This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $ 14 million of the Company's consolidated revenue for the year ended September 30, 2023.

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

7 unchanged sentences

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.

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.

All monetary amounts are expressed in U.S.

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

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities

20 unchanged sentences

$ 161,097 $ 128,413 $ 3,001 $ 3,704 $ 25,979

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

9 unchanged sentences

$ 734,138 $ 561,239 $ 371,878

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(1) Amounts for 2022, 2021 and 2020 include capitalized interest of zero , $ 0.1 million and zero respectively.

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

(2) Amounts for 2023, 2022 and 2021 include capitalized interest of $ 0.1 million, $ 0.6 million and $ 0.4 million, respectively.

22 unchanged sentences

See further discussion in Note J — Financial Instruments.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 February 19, 2007.

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

The Company's Senior Manager of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit.

The Company's Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit.

His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 14 years of Petroleum Engineering experience with independent oil and gas companies, licensure as a Professional Engineer and is a member of the Society of Petroleum Engineers.

1 unchanged sentence

Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves.

The Senior Manager of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions.

The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions.

Access to the reserve database is restricted.

Significant changes to the reserve report are reviewed by senior management on a quarterly basis.

Periodically, the

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.

Periodically, the Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.

All of the Company's reserve estimates are audited annually by Netherland, Sewell & Associates, Inc.

14 unchanged sentences

Production ( 312,300 ) (2) ( 1,720 ) ( 314,020 )

Purchases of Minerals in Place 684,141 — 684,141

September 30, 2021 3,693,148 30,285 3,723,433

2 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

25 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

11 unchanged sentences

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.

1 unchanged sentence

PUD reserves in the Utica Shale increased from 411 Bcfe at September 30, 2021 to 503 Bcfe at September 30, 2022.

PUD reserves in the Marcellus Shale decreased from 287 Bcfe at September 30, 2020 to 220 Bcfe at September 30, 2021.

The Company’s total PUD reserves were 16.5 % of total proved reserves at September 30, 2021, roughly flat from 16 % of total proved reserves at September 30, 2020.

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.

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.

The Company’s total PUD reserves were 20.6 % of total proved reserves at September 30, 2022, up from 16.5 % of total proved reserves at September 30, 2021.

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.

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The increase in PUD reserves in 2021 of 85 Bcfe is a result of 344 Bcfe in new PUD reserve additions and 9 Bcfe in upward revisions to remaining PUD reserves, partially offset by 188 Bcfe in PUD conversions to developed reserves ( 82 Bcfe from the Marcellus Shale and 106 Bcfe from the Utica Shale), and 80 Bcfe in PUD reserves removed for eight PUD locations, half of these due to pad layout changes, and the other half due to schedule changes.

Six of these wells removed were in the Marcellus Shale ( 54 Bcfe) and two were in the Utica Shale ( 26 Bcfe).

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.

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.

The Company invested $ 154 million during the year ended September 30, 2022 to convert 287 Bcfe ( 333 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves.

This represents 45 % of the net PUD reserves recorded at September 30, 2021.

In the Appalachian region, 18 of 53 PUD locations were developed.

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.

27 unchanged sentences

United States

Standardized Measure of Discounted Future

Net Cash Flows at Beginning of Year $ 2,353,572 $ 1,222,470 $ 1,736,319

Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 5,448,330 $ 2,353,572 $ 1,222,470

Sales, Net of Production Costs ( 767,487 ) ( 1,572,402 ) ( 626,132 )

12 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