NATIONAL FUEL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| (Thousands of dollars) |
| 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: | | | | | |
| Gain on Sale of Assets | (12,736) | | | (51,066) | | | — | |
| Impairment of Oil and Gas Producing Properties | — | | | 76,152 | | | 449,438 | |
| Depreciation, Depletion and Amortization | 369,790 | | | 335,303 | | | 306,158 | |
| Deferred Income Taxes | 104,415 | | | 105,993 | | | 54,313 | |
| Premium Paid on Early Redemption of Debt | — | | | 15,715 | | | — | |
| | | | | |
| | | | | |
| Stock-Based Compensation | 19,506 | | | 17,065 | | | 14,931 | |
| Reduction of Other Post-Retirement Regulatory Liability | (18,533) | | | — | | | — | |
| Other | 31,983 | | | 10,896 | | | 6,527 | |
| Change in: | | | | | |
| | | | | |
| Receivables and Unbilled Revenue | (168,769) | | | (61,413) | | | (2,578) | |
| Gas Stored Underground and Materials, Supplies and Emission Allowances | 3,109 | | | (2,014) | | | (6,625) | |
| Unrecovered Purchased Gas Costs | (66,214) | | | (33,128) | | | 2,246 | |
| Other Current Assets | 291 | | | (11,972) | | | 49,367 | |
| Accounts Payable | 11,907 | | | 31,352 | | | (4,657) | |
| Amounts Payable to Customers | 398 | | | (10,767) | | | 6,771 | |
| Customer Advances | 8,885 | | | 1,904 | | | 2,275 | |
| Customer Security Deposits | 4,991 | | | 2,093 | | | 989 | |
| Other Accruals and Current Liabilities | 34,260 | | | 34,314 | | | 5,001 | |
| Other Assets | (58,924) | | | 1,250 | | | (24,203) | |
| Other Liabilities | (17,859) | | | (33,771) | | | 4,628 | |
| Net Cash Provided by Operating Activities | 812,521 | | | 791,553 | | | 740,809 | |
| Investing Activities | | | | | |
| Capital Expenditures | (811,826) | | | (751,734) | | | (716,153) | |
| Net Proceeds from Sale of Oil and Gas Producing Properties | 254,439 | | | — | | | — | |
| Net Proceeds from Sale of Timber Properties | — | | | 104,582 | | | — | |
| Sale of Fixed Income Mutual Fund Shares in Grantor Trust | 30,000 | | | — | | | — | |
| Acquisition of Upstream Assets and Midstream Gathering Assets | — | | | — | | | (506,258) | |
| Other | 8,683 | | | 13,935 | | | (1,205) | |
| Net Cash Used in Investing Activities | (518,704) | | | (633,217) | | | (1,223,616) | |
| Financing Activities | | | | | |
| Change in Notes Payable to Banks and Commercial Paper | (98,500) | | | 128,500 | | | (25,200) | |
| | | | | |
| Net Proceeds from Issuance of Long-Term Debt | — | | | 495,267 | | | 493,007 | |
| Reduction of Long-Term Debt | — | | | (515,715) | | | — | |
| Net Proceeds from Issuance (Repurchase) of Common Stock | (9,590) | | | (3,702) | | | 161,603 | |
| Dividends Paid on Common Stock | (168,147) | | | (163,089) | | | (153,322) | |
| Net Cash Provided by (Used in) Financing Activities | (276,237) | | | (58,739) | | | 476,088 | |
| Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | 17,580 | | | 99,597 | | | (6,719) | |
| Cash, Cash Equivalents and Restricted Cash At Beginning of Year | 120,138 | | | 20,541 | | | 27,260 | |
| Cash, Cash Equivalents and Restricted Cash At End of Year | $ | 137,718 | | | $ | 120,138 | | | $ | 20,541 | |
| Supplemental Disclosure of Cash Flow Information | | | | | |
| Cash Paid (Refunded) For: | | | | | |
| Interest | $ | 124,312 | | | $ | 135,136 | | | $ | 103,479 | |
| Income Taxes | $ | 16,680 | | | $ | 6,374 | | | $ | (82,876) | |
| Non-Cash Investing Activities: | | | | | |
| Non-Cash Capital Expenditures | $ | 120,262 | | | $ | 102,700 | | | $ | 87,328 | |
| Non-Cash Contingent Consideration for Asset Sale | $ | 12,571 | | | $ | — | | | $ | — | |
| | | | | |
See Notes to Consolidated Financial Statements
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note A — Summary of Significant Accounting Policies
Principles of Consolidation
The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation
The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note F — Regulatory Matters for further discussion.
Allowance for Uncollectible Accounts
The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances 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.
Activity in the allowance for uncollectible accounts are as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 31,639 | | | $ | 22,810 | | | $ | 25,788 | |
| Additions Charged to Costs and Expenses | 13,209 | | | 14,940 | | | 12,339 | |
| Add: Discounts on Purchased Receivables | 1,314 | | | 1,168 | | | 1,353 | |
| Deduct: Net Accounts Receivable Written-Off | 5,934 | | | 7,279 | | | 16,670 | |
| Balance at End of Year | $ | 40,228 | | | $ | 31,639 | | | $ | 22,810 | |
Regulatory Mechanisms
The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.
Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note F — Regulatory Matters for further discussion.
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. 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.
The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending March 31st, and applied to customer bills annually, beginning July 1st.
In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.
Asset Acquisition and Business Combination Accounting
In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business. If the initial screening test is not met, the Company evaluates whether the set is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance.
When the Company acquires assets and liabilities deemed to be an asset acquisition, the fair value of the purchase consideration, including the transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to the individual assets and liabilities assumed based on their relative fair values. Transaction costs associated with asset acquisitions are capitalized as part of the costs of the group of assets acquired.
When the Company acquires assets and liabilities deemed to be a business combination, the acquisition method is applied. Goodwill is measured as the fair value of the consideration transferred less the net recognized fair value of the identifiable assets acquired and the liabilities assumed, all measured at the acquisition date. Transaction costs that the Company incurs in connection with a business combination, such as finders’ fees, legal fees, due diligence fees and other professional and consulting fees are expensed as incurred.
Property, Plant and Equipment
In the Company’s 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.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
For further discussion of capitalized costs, refer to Note N — Supplementary Information for Oil and Gas Producing Activities.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. 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.
The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2022.
Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion and Amortization
For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. Depreciation, depletion and amortization expense for oil and gas properties was $202.4 million, $177.1 million and $166.8 million for the years ended September 30, 2022, 2021 and 2020, 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:
| | | | | | | | | | | |
| | As of September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Exploration and Production | $ | 6,088,476 | | | $ | 6,827,122 | |
| Pipeline and Storage | 2,747,948 | | | 2,467,891 | |
| Gathering | 971,665 | | | 932,583 | |
| Utility | 2,411,707 | | | 2,306,603 | |
| | | |
| All Other and Corporate | 13,712 | | | 13,585 | |
| $ | 12,233,508 | | | $ | 12,547,784 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Average depreciation, depletion and amortization rates are as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| Exploration and Production, per Mcfe(1) | $ | 0.59 | | | $ | 0.56 | | | $ | 0.71 | |
| Pipeline and Storage | 2.7 | % | | 2.6 | % | | 2.4 | % |
| Gathering | 3.6 | % | | 3.6 | % | | 3.2 | % |
| Utility | 2.7 | % | | 2.7 | % | | 2.7 | % |
| | | | | |
| All Other and Corporate | 1.4 | % | | 3.4 | % | | 3.6 | % |
(1)Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.57, $0.54 and $0.69 per Mcfe of production in 2022, 2021 and 2020, respectively.
Goodwill
The Company has recognized goodwill of $5.5 million as of September 30, 2022 and 2021 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2022, 2021 and 2020, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.
Financial Instruments
The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include natural gas price swap agreements and no cost collars and foreign currency forward contracts. The Company accounts for these instruments as cash flow hedges for which the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note I — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.
For cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues on the Consolidated Statements of Income. Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges.
NATIONAL FUEL GAS COMPANY
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):
| | | | | | | | | | | | | | | | | | | |
| | Gains and Losses on Derivative Financial Instruments | | | | Funded Status of the Pension and Other Post-Retirement Benefit Plans | | Total |
Year Ended September 30, 2022 | | | | | | | |
Balance at October 1, 2021 | $ | (449,962) | | | | | $ | (63,635) | | | $ | (513,597) | |
| Other Comprehensive Gains and Losses Before Reclassifications | (763,223) | | | | | 7,392 | | | (755,831) | |
| Amounts Reclassified From Other Comprehensive Income (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) | |
Year Ended September 30, 2021 | | | | | | | |
Balance at October 1, 2020 | $ | (24,865) | | | | | $ | (89,892) | | | $ | (114,757) | |
| Other Comprehensive Gains and Losses Before Reclassifications | (486,343) | | | | | 13,790 | | | (472,553) | |
| Amounts Reclassified From Other Comprehensive Income (Loss) | 61,246 | | | | | 12,467 | | | 73,713 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Balance at September 30, 2021 | $ | (449,962) | | | | | $ | (63,635) | | | $ | (513,597) | |
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 total amount for accumulated losses was $53.2 million and $62.9 million at September 30, 2022 and 2021, respectively.
During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of OPEB expenses in Distribution Corporation's Pennsylvania service territory. As a result of that proceeding, Distribution Corporation discontinued regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $7.4 million ($5.8 million after tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss. For further discussion of this regulatory proceeding, refer to Note F — Regulatory Matters under the heading “Pennsylvania Jurisdiction.”
NATIONAL FUEL GAS COMPANY
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):
| | | | | | | | | | | | | | | | | | | | |
Details About Accumulated Other
Comprehensive Income (Loss) Components | | Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the
Year Ended
September 30, | | Affected Line Item in the Statement Where Net Income is Presented |
| | 2022 | | 2021 | | |
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: | | | | | | |
Commodity Contracts | | ($882,594) | | | ($83,973) | | | Operating Revenues |
| | | | | | |
Foreign Currency Contracts | | 13 | | | 262 | | | Operating Revenues |
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: | | | | | | |
Prior Service Cost | | (103) | | | (208) | | | (1) |
Net Actuarial Loss | | (10,951) | | | (16,021) | | | (1) |
| | | (893,635) | | | (99,940) | | | Total Before Income Tax |
| | | 244,133 | | | 26,227 | | | Income Tax Expense |
| | | ($649,502) | | | ($73,713) | | | Net of Tax |
(1)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground
In the Utility segment, gas stored underground in the amount of $32.4 million is carried at lower of cost or net realizable value, on a LIFO method. Based upon the average price of spot market gas purchased in September 2022, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $178.5 million at September 30, 2022.
Materials, Supplies and Emission Allowances
The components of the Company's materials, supplies and emission allowances are as follows:
| | | | | | | | | | | |
| Year Ended September 30 |
| 2022 | | 2021 |
| (Thousands) |
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)
treatment. At September 30, 2022, the remaining weighted average amortization period for such costs was approximately 5 years.
Income Taxes
The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed.
The Company follows the asset and liability approach in accounting for income taxes, which requires the recognition of deferred income taxes for the expected future tax consequences of net operating losses, credits and temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.
The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income (Deductions).
Consolidated Statement of Cash Flows
The components, as reported on the Company's Consolidated Balance Sheets, of the total cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 | | 2019 |
| Cash and Temporary Cash Investments | $ | 46,048 | | | $ | 31,528 | | | $ | 20,541 | | | $ | 20,428 | |
| Hedging Collateral Deposits | 91,670 | | | 88,610 | | | — | | | 6,832 | |
| Cash, Cash Equivalents, and Restricted Cash | $ | 137,718 | | | $ | 120,138 | | | $ | 20,541 | | | $ | 27,260 | |
The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents. The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for derivative financial instruments in an unrealized loss position. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.
Other Current Assets
The components of the Company’s Other Current Assets are as follows:
| | | | | | | | | | | |
| | Year Ended September 30 |
| 2022 | | 2021 |
| | (Thousands) |
| Prepayments | $ | 17,757 | | | $ | 14,164 | |
| Prepaid Property and Other Taxes | 14,321 | | | 14,788 | |
| | | |
| State Income Taxes Receivable | 5,933 | | | 1,502 | |
| | | |
| Regulatory Assets | 21,358 | | | 29,206 | |
| $ | 59,369 | | | $ | 59,660 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other Accruals and Current Liabilities
The components of the Company’s Other Accruals and Current Liabilities are as follows:
| | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Accrued Capital Expenditures | $ | 64,720 | | | $ | 42,541 | |
| Regulatory Liabilities | 31,293 | | | 60,860 | |
| | | |
| | | |
| | | |
| Liability for Royalty and Working Interests | 86,206 | | | 31,483 | |
| Non-Qualified Benefit Plan Liability | 17,474 | | | 15,408 | |
| Other | 57,634 | | | 43,877 | |
| $ | 257,327 | | | $ | 194,169 | |
Customer Advances
The Company, primarily in its Utility segment, has balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2022 and 2021, customers in the balanced billing programs had advanced excess funds of $26.1 million and $17.2 million, respectively.
Customer Security Deposits
The Company, primarily in its Utility and Pipeline and Storage segments, oftentimes requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2022 and 2021, the Company had received customer security deposits amounting to $24.3 million and $19.3 million, respectively.
Earnings Per Common Share
Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares. For the years ended September 30, 2022 and September 30, 2021, 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.
Stock-Based Compensation
The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. 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. For all Company stock awards, forfeitures are recognized as they occur.
Restricted stock units are subject to restrictions on vesting and transferability. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The restricted stock units do not entitle the participants to dividend and voting rights. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal and greenhouse gas emissions reductions, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.
Refer to Note H — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.
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. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets. This obligation amounted to $50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting.
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
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
date. 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. These assets were a component of the Company’s All Other category and did not have a major impact on the Company’s operations or financial results. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets. Since the sale did not 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
NATIONAL FUEL GAS COMPANY
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.
Note C — Revenue from Contracts with Customers
The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2022 and 2021, presented by type of service from each reportable segment.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2022 |
Revenues by Type of Service | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
Production of Natural Gas | $ | 1,730,723 | | | $ | — | | | $ | — | | | $ | — | | | $ | 1,730,723 | | | $ | — | | | $ | — | | | $ | 1,730,723 | |
| Production of Crude Oil | 150,957 | | | — | | | — | | | — | | | 150,957 | | | — | | | — | | | 150,957 | |
| Natural Gas Processing | 3,511 | | | — | | | — | | | — | | | 3,511 | | | — | | | — | | | 3,511 | |
Natural Gas Gathering Service | — | | | — | | | 214,843 | | | — | | | 214,843 | | | — | | | (202,757) | | | 12,086 | |
Natural Gas Transportation Service | — | | | 289,967 | | | — | | | 106,495 | | | 396,462 | | | — | | | (74,749) | | | 321,713 | |
Natural Gas Storage Service | — | | | 84,565 | | | — | | | — | | | 84,565 | | | — | | | (36,382) | | | 48,183 | |
Natural Gas Residential Sales | — | | | — | | | — | | | 688,271 | | | 688,271 | | | — | | | — | | | 688,271 | |
Natural Gas Commercial Sales | — | | | — | | | — | | | 95,114 | | | 95,114 | | | — | | | — | | | 95,114 | |
Natural Gas Industrial Sales | — | | | — | | | — | | | 4,902 | | | 4,902 | | | — | | | — | | | 4,902 | |
| Other | 7,867 | | | 2,512 | | | — | | | (3,918) | | | 6,461 | | | 6 | | | (644) | | | 5,823 | |
Total Revenues from Contracts with Customers | 1,893,058 | | | 377,044 | | | 214,843 | | | 890,864 | | | 3,375,809 | | | 6 | | | (314,532) | | | 3,061,283 | |
Alternative Revenue Programs | — | | | — | | | — | | | 7,357 | | | 7,357 | | | — | | | — | | | 7,357 | |
Derivative Financial Instruments | (882,594) | | | — | | | — | | | — | | | (882,594) | | | — | | | — | | | (882,594) | |
| Total Revenues | $ | 1,010,464 | | | $ | 377,044 | | | $ | 214,843 | | | $ | 898,221 | | | $ | 2,500,572 | | | $ | 6 | | | $ | (314,532) | | | $ | 2,186,046 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2021 |
Revenues by Type of Service | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
Production of Natural Gas | $ | 780,477 | | | $ | — | | | $ | — | | | $ | — | | | $ | 780,477 | | | $ | — | | | $ | — | | | $ | 780,477 | |
| Production of Crude Oil | 135,191 | | | — | | | — | | | — | | | 135,191 | | | — | | | — | | | 135,191 | |
| Natural Gas Processing | 2,960 | | | — | | | — | | | — | | | 2,960 | | | — | | | — | | | 2,960 | |
Natural Gas Gathering Service | — | | | — | | | 193,264 | | | — | | | 193,264 | | | — | | | (190,148) | | | 3,116 | |
Natural Gas Transportation Service | — | | | 255,849 | | | — | | | 103,141 | | | 358,990 | | | — | | | (72,920) | | | 286,070 | |
Natural Gas Storage Service | — | | | 83,080 | | | — | | | — | | | 83,080 | | | — | | | (35,841) | | | 47,239 | |
Natural Gas Residential Sales | — | | | — | | | — | | | 492,567 | | | 492,567 | | | — | | | — | | | 492,567 | |
Natural Gas Commercial Sales | — | | | — | | | — | | | 62,634 | | | 62,634 | | | — | | | — | | | 62,634 | |
Natural Gas Industrial Sales | — | | | — | | | — | | | 3,071 | | | 3,071 | | | — | | | — | | | 3,071 | |
| Natural Gas Marketing | — | | | — | | | — | | | — | | | — | | | 678 | | | (49) | | | 629 | |
| Other | 2,042 | | | 4,628 | | | — | | | (5,249) | | | 1,421 | | | 544 | | | (374) | | | 1,591 | |
Total Revenues from Contracts with Customers | 920,670 | | | 343,557 | | | 193,264 | | | 656,164 | | | 2,113,655 | | | 1,222 | | | (299,332) | | | 1,815,545 | |
Alternative Revenue Programs | — | | | — | | | — | | | 11,087 | | | 11,087 | | | — | | | — | | | 11,087 | |
Derivative Financial Instruments | (83,973) | | | — | | | — | | | — | | | (83,973) | | | — | | | — | | | (83,973) | |
| Total Revenues | $ | 836,697 | | | $ | 343,557 | | | $ | 193,264 | | | $ | 667,251 | | | $ | 2,040,769 | | | $ | 1,222 | | | $ | (299,332) | | | $ | 1,742,659 | |
The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.
Exploration and Production Segment Revenue
The Company’s Exploration and Production segment records revenue from the sale of the natural gas and oil that it produces and natural gas liquids (NGLs) processed based on entitlement, which means that revenue is recorded based on the actual amount of natural gas or oil that is delivered to a pipeline, or upon pick-up in the case of NGLs, and the Company’s ownership interest. Prior to the completion of the sale of the Company’s California assets on June 30, 2022, natural gas production occurred primarily in the Appalachian region of the United States and crude oil production occurred primarily in the West Coast region of the United States. Subsequent to June 30, 2022, substantially all Exploration and Production segment production consists of natural gas production from the Appalachian region of the United States. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance. The sales contracts generally require the Company to deliver a specific quantity of a commodity per day for a specific number of days at a price that is either fixed or variable and considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery.
The transaction price for the sale of natural gas, oil and NGLs is contractually agreed upon based on prevailing market pricing (primarily tied to a market index with certain adjustments based on factors such as delivery location and prevailing supply and demand conditions) or fixed pricing. The Company allocates the transaction price to each performance obligation on the basis of the relative standalone selling price of each distinct unit sold. Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract. The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and
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.
The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment related to sales of the natural gas that it produces. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.
Pipeline and Storage Segment Revenue
The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services in New York and Pennsylvania at tariff-based rates regulated by the FERC. Customers secure their own gas supply and the Pipeline and Storage segment provides transportation and/or storage services to move the customer-supplied gas to the intended location, including injections into or withdrawals from the storage field. This performance obligation is satisfied over time. The rate design for the Pipeline and Storage segment’s customers generally includes a combination of volumetric or commodity charges as well as monthly “fixed” charges (including charges commonly referred to as capacity charges, demand charges, or reservation charges). These types of fixed charges represent compensation for standing ready over the period of the month to deliver quantities of gas, regardless of whether the customer takes delivery of any quantity of gas. The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.
The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $212.4 million for fiscal 2023; $191.0 million for fiscal 2024; $166.9 million for fiscal 2025; $143.8 million for fiscal 2026; $121.1 million for fiscal 2027; and $691.7 million thereafter.
Gathering Segment Revenue
The Company’s Gathering segment provides gathering and processing services in the Appalachian region of Pennsylvania, primarily for Seneca. The Gathering segment’s primary performance obligation is to deliver gathered natural gas volumes from Seneca’s wells, and to a lesser extent, other producers' wells, into interstate pipelines at contractually agreed upon per unit rates. This obligation is satisfied over time. The performance obligation is satisfied based on the passage of time and meter reads, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the contracted volumetric rate, indicates the value to the customer, and is used for revenue recognition purposes by the Gathering segment as specified by the “invoice practical expedient” (the amount that the Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 10th day after the invoice is received.
Utility Segment Revenue
The Company’s Utility segment records revenue for natural gas sales and natural gas transportation services in western New York and northwestern Pennsylvania at tariff-based rates regulated by the NYPSC and the PaPUC, respectively. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment. The Utility segment recognizes
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Utility segment’s tariffs allow customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.
Utility Segment Alternative Revenue Programs
As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and conservation have on margin. The NYPSC 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. These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to customers within 24 months of the annual reconciliation period.
Note D — Leases
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:
1.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;
2.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);
3.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; and
4.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
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Statement of Cash Flows. Comparative periods, including disclosures relating to those periods, were not restated.
Nature of Leases
The Company primarily leases building space and drilling rigs, and on a limited basis, compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the authoritative guidance. The Company did not have any material finance leases as of September 30, 2022 or September 30, 2021. 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.
Buildings and Property
The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range from two months to seventeen 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. Renewal options are included in the lease term if they are reasonably certain to be exercised. The agreements do not contain any material restrictive covenants.
Drilling Rigs
The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania. Seneca’s drilling rig arrangements are structured with a non-cancelable primary term that exceeds one year. Upon mutual agreement with the contractor, Seneca has the option to extend contracts with amended terms and conditions, including a renegotiated day rate fee.
Drilling rig lease costs are capitalized as part of natural gas properties on the Consolidated Balance Sheet when incurred.
Compressor Equipment
The Company enters into contracts for compressor services with third parties primarily to support its gathering system in Pennsylvania. The primary non-cancelable terms of the Company's compressor equipment leases range from 21 months to 4 years. Most compressor equipment leases include one or more options to renew or to continue past the primary term on a month-to-month basis, generally at the Company's sole discretion. Renewal options are included in the lease term if they are reasonably certain to be exercised.
Significant Judgments
Lease Identification
The Company uses judgment when determining whether or not an arrangement is or contains a lease. A contract is or contains a lease if the contract conveys the right to use an explicitly or implicitly identified asset that is physically distinct and the Company has the right to control the use of the identified asset for a period of time. When determining right of control, the Company evaluates whether it directs the use of the asset and obtains substantially all of the economic benefits from the use of the asset.
Discount Rate
The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability. In the absence of a rate of interest that is
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
Firm Transportation and Storage Contracts
The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers. The Company’s firm capacity contracts with non-affiliated entities do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance.
Gas Leases
The authoritative guidance does not apply to leases to explore for or use natural gas resources, including the right to explore for those resources and rights to use the land in which those resources are contained. As such, the Company has concluded that its gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.
Amounts Recognized in the Financial Statements
Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting, 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):
| | | | | | | | | | | |
| Year Ended September 30 |
| 2022 | | 2021 |
| Operating Lease Expense | $ | 4,909 | | | $ | 5,268 | |
| Variable Lease Expense(1) | 462 | | | 537 | |
| Short-Term Lease Expense(2) | 461 | | | 1,279 | |
| Sublease Income | (166) | | | (356) | |
| Total Lease Expense | $ | 5,666 | | | $ | 6,728 | |
| | | |
| Lease Costs Recorded to Property, Plant and Equipment(3) | $ | 19,839 | | | $ | 14,188 | |
(1)Variable lease payments that are not dependent on an index or rate are not included in the lease liability.
(2)Short-term lease costs exclude expenses related to leases with a lease term of one month or less.
(3)Lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting as well as certain equipment leases used on construction projects.
Right-of-use assets and lease liabilities are recognized at the commencement date of a leasing arrangement based on the present value of lease payments over the lease term. The weighted average remaining lease term was 6.0 years and 8.8 years as of September 30, 2022 and 2021, respectively. The weighted average discount rate was 3.92% and 4.24% as of September 30, 2022 and 2021, respectively.
The Company’s right-of-use operating lease assets are reflected as Deferred Charges on the Consolidated Balance Sheet. The corresponding operating lease liabilities are reflected in Other Accruals and Current Liabilities (current) and Other Liabilities (noncurrent). Short-term leases that have a lease term of one year or less are not recorded on the Consolidated Balance Sheet.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands):
| | | | | | | | | | | |
| Year Ended September 30 |
| 2022 | | 2021 |
| Assets: | | | |
| Deferred Charges | $ | 37,120 | | | $ | 23,601 | |
| | | |
| Liabilities: | | | |
| Other Accruals and Current Liabilities | $ | 14,239 | | | $ | 3,963 | |
| Other Liabilities | $ | 22,881 | | | $ | 19,638 | |
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. The Company did not record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2022 or 2021.
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, 2022 (in thousands):
| | | | | |
| At September 30, 2022 |
| 2023 | $ | 14,420 | |
2024 | 5,353 | |
2025 | 4,828 | |
2026 | 3,578 | |
2027 | 2,889 | |
| Thereafter | 11,656 | |
| Total Lease Payments | 42,724 | |
| Less: Interest | (5,604) | |
| Total Lease Liability | $ | 37,120 | |
Note E — Asset Retirement Obligations
The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.
The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s natural gas wells and has capitalized such costs in
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
property, plant and equipment (i.e. the full cost pool). During fiscal 2021, this segment’s Appalachian operations were required to implement additional water testing on a portion of its assets, which contributed to an increase in the asset retirement obligation. This increase is the primary component of the Revisions of Estimates amount for fiscal 2021 shown in the table below.
In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. Asset retirement obligation costs related to storage tanks have been recorded in the Utility, Pipeline and Storage, and Gathering segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains, services and other components of the pipeline system in the Utility segment, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment. The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.
As discussed in Note B — Asset Acquisitions and Divestitures, on June 30, 2022, the Company completed the sale of Seneca’s California oil and gas assets to Sentinel Peak Resources California LLC. With the divestiture of these assets, the Company reduced its Asset Retirement Obligation at June 30, 2022 by $50.1 million. This reduction is reflected in Liabilities Settled in the table below.
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:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 209,639 | | | $ | 192,228 | | | $ | 127,458 | |
| Liabilities Incurred | 2,401 | | | 7,035 | | | 61,246 | |
| Revisions of Estimates | 10,700 | | | 14,509 | | | 3,267 | |
| Liabilities Settled | (71,171) | | | (14,270) | | | (7,268) | |
| Accretion Expense | 9,976 | | | 10,137 | | | 7,525 | |
| Balance at End of Year | $ | 161,545 | | | $ | 209,639 | | | $ | 192,228 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note F — Regulatory Matters
Regulatory Assets and Liabilities
The Company has recorded the following regulatory assets and liabilities:
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Regulatory Assets(1): | | | |
| Pension Costs(2) (Note K) | $ | 11,677 | | | $ | 21,655 | |
| Post-Retirement Benefit Costs(2) (Note K) | 6,814 | | | 10,075 | |
| Recoverable Future Taxes (Note G) | 106,247 | | | 121,992 | |
| Environmental Site Remediation Costs(2) (Note L) | 3,646 | | | 7,256 | |
| Asset Retirement Obligations(2) (Note E) | 18,517 | | | 16,799 | |
| Unamortized Debt Expense (Note A) | 8,884 | | | 10,589 | |
| Other(3) | 47,805 | | | 33,566 | |
| Total Regulatory Assets | 203,590 | | | 221,932 | |
| Less: Amounts Included in Other Current Assets | (21,358) | | | (29,206) | |
| Total Long-Term Regulatory Assets | $ | 182,232 | | | $ | 192,726 | |
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Regulatory Liabilities: | | | |
| Cost of Removal Regulatory Liability | $ | 259,947 | | | $ | 245,636 | |
| Taxes Refundable to Customers (Note G) | 362,098 | | | 354,089 | |
| Post-Retirement Benefit Costs(5) (Note K) | 167,305 | | | 213,112 | |
| Pension Costs(4) (Note K) | 8,242 | | | — | |
| Amounts Payable to Customers (See Regulatory Mechanisms in Note A) | 419 | | | 21 | |
| Other(6) | 44,549 | | | 48,391 | |
| Total Regulatory Liabilities | 842,560 | | | 861,249 | |
| Less: Amounts included in Current and Accrued Liabilities | (31,712) | | | (60,881) | |
| Total Long-Term Regulatory Liabilities | $ | 810,848 | | | $ | 800,368 | |
(1)The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
(2)Included in Other Regulatory Assets on the Consolidated Balance Sheets.
(3)$21,358 and $29,206 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $26,447 and $4,360 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively.
(4)Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(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. $161,505 and $183,112 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively.
(6)$25,493 and $30,860 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. $19,056 and $17,531 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2022 and 2021, respectively.
If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs.
Cost of Removal Regulatory Liability
In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note E — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from customers that will be used in the future to fund asset retirement costs.
New York Jurisdiction
Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on 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. 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.
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.
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
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.
FERC Jurisdiction
Supply Corporation’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.
Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.
Note G — Income Taxes
The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Current Income Taxes — | | | | | |
| Federal | $ | — | | | $ | (10) | | | $ | (42,548) | |
| State | 12,214 | | | 8,699 | | | 6,974 | |
| Deferred Income Taxes — | | | | | |
| Federal | 137,025 | | | 90,970 | | | 4,538 | |
| State | (32,610) | | | 15,023 | | | 49,775 | |
| Total Income Taxes | $ | 116,629 | | | $ | 114,682 | | | $ | 18,739 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
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. The law reduces the corporate income tax rate to 8.99% for fiscal 2024. Starting with fiscal 2025, the rate is reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. The Company's deferred income taxes were re-measured based upon the new tax rates. For the Company's non-rate regulated activities, the change in deferred income taxes was $28.4 million as of the enactment date and was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $37.2 million was recorded as a decrease to Recoverable Future Taxes of $19.8 million and an increase to Taxes Refundable to Customers of $17.4 million.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 following is a reconciliation of this difference:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| U.S. Income (Loss) Before Income Taxes (1) | $ | 682,650 | | | $ | 478,327 | | | $ | (105,046) | |
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 21% | $ | 143,357 | | | $ | 100,449 | | | $ | (22,060) | |
| State Valuation Allowance (2) | (24,850) | | | (5,560) | | | 63,205 | |
| State Income Taxes (Benefit) (3) | 8,736 | | | 24,300 | | | (18,374) | |
| | | | | |
| Amortization of Excess Deferred Federal Income Taxes | (5,184) | | | (5,215) | | | (4,749) | |
| Plant Flow Through Items | (814) | | | (1,503) | | | (2,848) | |
| Stock Compensation | 820 | | | 2,239 | | | 3,867 | |
| Federal Tax Credits | (5,701) | | | (310) | | | (217) | |
| | | | | |
| Miscellaneous | 265 | | | 282 | | | (85) | |
| Total Income Taxes | $ | 116,629 | | | $ | 114,682 | | | $ | 18,739 | |
(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. 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.
Significant components of the Company’s deferred tax liabilities and assets were as follows:
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Deferred Tax Liabilities: | | | |
| Property, Plant and Equipment | $ | 954,757 | | | $ | 920,692 | |
| Pension and Other Post-Retirement Benefit Costs | 30,132 | | | 23,240 | |
| Other | 48,893 | | | 35,081 | |
| Total Deferred Tax Liabilities | 1,033,782 | | | 979,013 | |
| Deferred Tax Assets: | | | |
| Unrealized Hedging Losses | (215,187) | | | (170,155) | |
| Tax Loss and Credit Carryforwards | (50,686) | | | (120,725) | |
| Pension and Other Post-Retirement Benefit Costs | (37,250) | | | (53,765) | |
| Other | (32,430) | | | (31,593) | |
| Total Gross Deferred Tax Assets | (335,553) | | | (376,238) | |
Valuation Allowance | — | | | 57,645 | |
| Total Deferred Tax Assets | (335,553) | | | (318,593) | |
| Total Net Deferred Income Taxes | $ | 698,229 | | | $ | 660,420 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following is a summary of changes in valuation allowances for deferred tax assets:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Balance at Beginning of Year | $ | 57,645 | | | $ | 63,205 | | | $ | — | |
| Additions | — | | | — | | | 63,205 | |
| Deductions | 57,645 | | | 5,560 | | | — | |
| Balance at End of Year | $ | — | | | $ | 57,645 | | | $ | 63,205 | |
A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. The Company, at each reporting date, assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to the likelihood of the realization of the deferred tax assets. As of 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. 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. 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. 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 income 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, amounted 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 federal statute of limitations remains open for fiscal 2019 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries have state statutes of limitations that generally expire between three to four years from the date of filing of the income tax return. Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
Tax carryforwards available, prior to valuation allowance, at September 30, 2022, were as follows:
| | | | | | | | | | | | | | | | | | | | |
| Jurisdiction | | Tax Attribute | | Amount
(Thousands) | | Expires |
| | | | | | |
| | | | | | |
| Pennsylvania | | Net Operating Loss | | $ | 378,631 | | | 2030-2042 |
| | | | | | |
| | | | | | |
| | | | | | |
| Federal | | General Business Credits | | 20,677 | | | 2035-2042 |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note H — Capitalization and Short-Term Borrowings
Summary of Changes in Common Stock Equity
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Paid In
Capital | | Earnings
Reinvested
in the
Business | | Accumulated
Other
Comprehensive
Loss |
| Shares | | Amount | |
| | (Thousands, except per share amounts) |
Balance at September 30, 2019 | 86,315 | | | $ | 86,315 | | | $ | 832,264 | | | $ | 1,272,601 | | | $ | (52,155) | |
| Net Loss Available for Common Stock | | | | | | | (123,772) | | | |
| Dividends Declared on Common Stock ($1.76 Per Share) | | | | | | | (156,249) | | | |
Cumulative Effect of Adoption of Authoritative Guidance for Hedging | | | | | | | (950) | | | |
| | | | | | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (62,602) | |
| Share-Based Payment Expense(1) | | | | | 13,180 | | | | | |
Common Stock Issued from Sale of Common Stock | 4,370 | | | 4,370 | | | 161,399 | | | | | |
Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 270 | | | 270 | | | (2,685) | | | | | |
Balance at September 30, 2020 | 90,955 | | | 90,955 | | | 1,004,158 | | | 991,630 | | | (114,757) | |
| Net Income Available for Common Stock | | | | | | | 363,647 | | | |
| Dividends Declared on Common Stock ($1.80 Per Share) | | | | | | | (164,102) | | | |
| | | | | | | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (398,840) | |
Share-Based Payment Expense(1) | | | | | 15,297 | | | | | |
| | | | | | | | | |
Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 227 | | | 227 | | | (2,009) | | | | | |
Balance at September 30, 2021 | 91,182 | | | 91,182 | | | 1,017,446 | | | 1,191,175 | | | (513,597) | |
| Net Income Available for Common Stock | | | | | | | 566,021 | | | |
| Dividends Declared on Common Stock ($1.86 Per Share) | | | | | | | (170,111) | | | |
| Other Comprehensive Loss, Net of Tax | | | | | | | | | (112,136) | |
| Share-Based Payment Expense(1) | | | | | 17,699 | | | | | |
| Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 296 | | | 296 | | | (8,079) | | | | | |
Balance at September 30, 2022 | 91,478 | | | $ | 91,478 | | | $ | 1,027,066 | | | $ | 1,587,085 | | (2) | $ | (625,733) | |
(1)Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available for Common Stock, net of tax benefits.
(2)The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2022, $1.4 billion of accumulated earnings was free of such limitations.
Common Stock
The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. During 2022, the Company did not issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan or the Company's 401(k) plans.
During 2022, the Company issued 30,769 original issue shares of common stock as a result of SARs exercises, 129,169 original issue shares of common stock for restricted stock units that vested and 265,607 original issue shares of common stock for performance shares that vested. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During 2022, 157,812 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 28,782 original issue shares of common stock during 2022.
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.
Stock Award Plans
The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares.
Stock-based compensation expense for the years ended September 30, 2022, 2021 and 2020 was approximately $17.6 million, $15.2 million and $13.1 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2022, 2021 and 2020 was approximately $2.5 million, $2.4 million and $2.1 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million was capitalized under these rules during each of the years ended September 30, 2022, 2021 and 2020. The tax benefit related to stock-based compensation exercises and vestings was $0.6 million for the year ended September 30, 2022.
Pursuant to registration statements for these plans, there were 2,149,203 shares available for future grant at September 30, 2022. These shares include shares available for future options, SARs, restricted stock and performance share grants.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SARs
Transactions for 2022 involving SARs for all plans are summarized as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Number of
Shares Subject
To Option | | Weighted
Average
Exercise Price | | Weighted
Average
Remaining
Contractual
Life (Years) | | Aggregate
Intrinsic
Value
(In thousands) |
Outstanding at September 30, 2021 | 318,445 | | | $ | 53.60 | | | | | |
Granted in 2022 | — | | | $ | — | | | | | |
Exercised in 2022 | (241,437) | | | $ | 55.73 | | | | | |
Forfeited in 2022 | — | | | $ | — | | | | | |
Expired in 2022 | (5,000) | | | $ | 55.09 | | | | | |
| | | | | | | |
Outstanding at September 30, 2022 | 72,008 | | | $ | 53.05 | | | 0.22 | | $ | 612 | |
SARs exercisable at September 30, 2022 | 72,008 | | | $ | 53.05 | | | 0.22 | | $ | 612 | |
| | | | | | | |
The Company did not grant any SARs during the years ended September 30, 2021 and 2020. 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 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.
Restricted Stock Units
Transactions for 2022 involving nonperformance-based restricted stock units for all plans are summarized as follows:
| | | | | | | | | | | |
| Number of
Restricted
Stock Units | | Weighted Average
Fair Value per
Award |
Outstanding at September 30, 2021 | 365,481 | | | $ | 41.45 | |
Granted in 2022 | 128,950 | | | $ | 54.10 | |
Vested in 2022 | (129,169) | | | $ | 45.24 | |
Forfeited in 2022 | (17,835) | | | $ | 44.61 | |
Outstanding at September 30, 2022 | 347,427 | | | $ | 44.58 | |
The Company also granted 172,513 and 150,839 nonperformance-based restricted stock units during the years ended September 30, 2021 and 2020, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2021 and 2020 was $37.98 per share and $40.38 per share, respectively. As of September 30, 2022, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $6.4 million, which will be recognized over a weighted average period of 2.2 years.
Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2022 will lapse as follows: 2023 — 119,612 units; 2024 — 97,614 units; 2025 — 73,797 units; 2026 — 37,052 units; and 2027 — 19,352 units.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Performance Shares
Transactions for 2022 involving performance shares for all plans are summarized as follows:
| | | | | | | | | | | |
| Number of
Performance
Shares | | Weighted Average
Fair Value per
Award |
Outstanding at September 30, 2021 | 600,634 | | | $ | 45.13 | |
Granted in 2022 | 195,397 | | | $ | 65.39 | |
Vested in 2022 | (265,607) | | | $ | 55.93 | |
Forfeited in 2022 | (23,414) | | | $ | 49.84 | |
| Change in Units Based on Performance Achieved | 100,169 | | | $ | 56.36 | |
Outstanding at September 30, 2022 | 607,179 | | | $ | 48.60 | |
The Company also granted 309,470 and 254,608 performance shares during the years ended September 30, 2021 and 2020, respectively. The weighted average grant date fair value of such performance shares granted in 2021 and 2020 was $39.19 per share and $43.32 per share, respectively. As of September 30, 2022, unrecognized compensation expense related to performance shares totaled approximately $11.3 million, which will be recognized over a weighted average period of 1.8 years. Vesting restrictions for the outstanding performance shares at September 30, 2022 will lapse as follows: 2023 — 199,842 shares; 2024 — 220,914 shares; and 2025 — 186,423 shares.
The performance shares granted during the years ended September 30, 2022, 2021 and 2020 include awards that must meet a performance goal related to either relative return on capital over a three-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year performance cycle ("TSR performance shares"). The performance goal over the respective performance cycles for the ROC performance shares granted during 2022, 2021 and 2020 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of the ROC performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.
The performance goal over the performance cycle for the ESG performance shares granted during 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 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.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The performance goal over the respective performance cycles for the TSR performance shares granted during 2022, 2021 and 2020 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. In calculating the fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR performance shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| Risk-Free Interest Rate | 0.85 | % | | 0.19 | % | | 1.63 | % |
| Remaining Term at Date of Grant (Years) | 2.80 | | 2.80 | | 2.81 |
| Expected Volatility | 29.7 | % | | 29.1 | % | | 19.3 | % |
| Expected Dividend Yield (Quarterly) | N/A | | N/A | | N/A |
Redeemable Preferred Stock
As of September 30, 2022, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.
Long-Term Debt
The outstanding long-term debt is as follows:
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Medium-Term Notes(1): | | | |
7.4% due March 2023 to June 2025 | $ | 99,000 | | | $ | 99,000 | |
| Notes(1)(2)(3): | | | |
2.95% to 5.50% due March 2023 to March 2031 | 2,550,000 | | | 2,550,000 | |
| Total Long-Term Debt | 2,649,000 | | | 2,649,000 | |
| Less Unamortized Discount and Debt Issuance Costs | 16,591 | | | 20,313 | |
| Less Current Portion(4) | 549,000 | | | — | |
| $ | 2,083,409 | | | $ | 2,628,687 | |
(1)The Medium-Term Notes and Notes are unsecured.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2)The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
(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). 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. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.
On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest. The early redemption premium of $15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.
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, 2022, 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.
Short-Term Borrowings
The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. 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. 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.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement.
At September 30, 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
The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 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. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. 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.
A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.
The Credit Agreement and 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
NATIONAL FUEL GAS COMPANY
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.
In order to issue incremental long-term debt, the Company must meet an interest coverage test under its existing indenture covenants. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the indenture) of not more than 60%. Under the Company's 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. The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.
The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of September 30, 2022) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
Note I — Fair Value Measurements
The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2022 and 2021. 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At Fair Value as of September 30, 2022 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Netting
Adjustments(1) | | Total(1) |
| | (Dollars in thousands) |
| Assets: | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | $ | 35,015 | | | $ | — | | | $ | — | | | $ | — | | | $ | 35,015 | |
| Hedging Collateral Deposits | 91,670 | | | — | | | — | | | — | | | 91,670 | |
| Derivative Financial Instruments: | | | | | | | | | |
| | | | | | | | | |
| Over the Counter Swaps — Gas | — | | | 5,177 | | | — | | | (4,178) | | | 999 | |
| | | | | | | | | |
| Contingent Consideration for Asset Sale | — | | | 8,176 | | | — | | | — | | | 8,176 | |
| Foreign Currency Contracts | — | | | 128 | | | — | | | (128) | | | — | |
| Other Investments: | | | | | | | | | |
| Balanced Equity Mutual Fund | 19,506 | | | — | | | — | | | — | | | 19,506 | |
| Fixed Income Mutual Fund | 33,348 | | | — | | | — | | | — | | | 33,348 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total | $ | 179,539 | | | $ | 13,481 | | | $ | — | | | $ | (4,306) | | | $ | 188,714 | |
| Liabilities: | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | |
| | | | | | | | | |
| Over the Counter Swaps — Gas | $ | — | | | $ | 517,464 | | | $ | — | | | $ | (4,178) | | | $ | 513,286 | |
| Over the Counter No Cost Collars — Gas | — | | | 270,453 | | | — | | | — | | | 270,453 | |
| Foreign Currency Contracts | — | | | 2,048 | | | — | | | (128) | | | 1,920 | |
| Total | $ | — | | | $ | 789,965 | | | $ | — | | | $ | (4,306) | | | $ | 785,659 | |
| Total Net Assets/(Liabilities) | $ | 179,539 | | | $ | (776,484) | | | $ | — | | | $ | — | | | $ | (596,945) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | At Fair Value as of September 30, 2021 |
| Recurring Fair Value Measures | Level 1 | | Level 2 | | Level 3 | | Netting
Adjustments(1) | | Total(1) |
| | (Dollars in thousands) |
| Assets: | | | | | | | | | |
| Cash Equivalents — Money Market Mutual Funds | $ | 22,269 | | | $ | — | | | $ | — | | | $ | — | | | $ | 22,269 | |
| Hedging Collateral Deposits | 88,610 | | | — | | | — | | | — | | | 88,610 | |
| Derivative Financial Instruments: | | | | | | | | | |
| Over the Counter Swaps — Gas and Oil | — | | | 1,802 | | | — | | | (1,802) | | | — | |
| | | | | | | | | |
| Foreign Currency Contracts | — | | | 938 | | | — | | | (938) | | | — | |
| Other Investments: | | | | | | | | | |
| Balanced Equity Mutual Fund | 34,433 | | | — | | | — | | | — | | | 34,433 | |
| Fixed Income Mutual Fund | 70,639 | | | — | | | — | | | — | | | 70,639 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total | $ | 215,951 | | | $ | 2,740 | | | $ | — | | | $ | (2,740) | | | $ | 215,951 | |
| Liabilities: | | | | | | | | | |
| Derivative Financial Instruments: | | | | | | | | | |
| Over the Counter Swaps — Gas and Oil | $ | — | | | $ | 601,551 | | | $ | — | | | $ | (1,802) | | | $ | 599,749 | |
| Over the Counter No Cost Collars — Gas | — | | | 17,385 | | | — | | | — | | | 17,385 | |
| Foreign Currency Contracts | — | | | 214 | | | — | | | (938) | | | (724) | |
| Total | $ | — | | | $ | 619,150 | | | $ | — | | | $ | (2,740) | | | $ | 616,410 | |
| Total Net Assets/(Liabilities) | $ | 215,951 | | | $ | (616,410) | | | $ | — | | | $ | — | | | $ | (400,459) | |
(1)Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Derivative Financial Instruments
At September 30, 2022, 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.
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.
The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2022, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.
Derivative financial instruments reported in Level 2 at September 30, 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.
For the years ended September 30, 2022 and 2021, there were no assets or liabilities measured at fair value and classified as Level 3.
Note J — Financial Instruments
Long-Term Debt
The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | At September 30 |
| | 2022
Carrying
Amount | | 2022
Fair Value | | 2021
Carrying
Amount | | 2021
Fair Value |
| | (Thousands) |
| Long-Term Debt | $ | 2,632,409 | | | $ | 2,453,209 | | | $ | 2,628,687 | | | $ | 2,898,552 | |
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. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.
Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.
Other Investments
The components of the Company's Other Investments are as follows (in thousands):
| | | | | | | | | | | |
| At September 30 |
| 2022 | | 2021 |
| (Thousands) |
| Life Insurance Contracts | $ | 42,171 | | | $ | 44,560 | |
| Equity Mutual Fund | 19,506 | | | 34,433 | |
| Fixed Income Mutual Fund | 33,348 | | | 70,639 | |
| | | |
| $ | 95,025 | | | $ | 149,632 | |
Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction, as discussed in Note F — Regulatory Matters, and for various benefit obligations the Company has to certain employees.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage commodity price risk in the 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. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 8 years.
On June 30, 2022, the Company completed the sale of Seneca’s California assets. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be $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 Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2022 and September 30, 2021.
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.
As of September 30, 2022, the Company had 420.8 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.
As of September 30, 2022, the Company was hedging a total of $49.4 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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2022 and 2021 (Dollar Amounts in Thousands) |
Derivatives in Cash
Flow Hedging
Relationships | | Amount of
Derivative Gain or (Loss) Recognized in Other
Comprehensive
Income (Loss) on the Consolidated Statement
of Comprehensive
Income (Loss)
for the Year Ended
September 30, | | Location of
Derivative Gain or (Loss) Reclassified
from Accumulated
Other Comprehensive
Income (Loss) on
the Consolidated
Balance Sheet into the Consolidated
Statement of Income | | Amount of
Derivative Gain or (Loss) Reclassified from Accumulated
Other Comprehensive
Income (Loss) on the Consolidated Balance
Sheet into the Consolidated
Statement of Income
for the Year Ended
September 30, |
| | | 2022 | | 2021 | | | | 2022 | | | 2021 |
| Commodity Contracts | | $ | (1,048,200) | | | $ | (668,074) | | | Operating Revenue | | $ | (882,594) | | (1) | | $ | (83,973) | |
| | | | | | | | | | | |
| Foreign Currency Contracts | | (2,631) | | | 2,703 | | | Operating Revenue | | 13 | | | | 262 | |
| Total | | $ | (1,050,831) | | | $ | (665,371) | | | | | $ | (882,581) | | | | $ | (83,711) | |
(1)On June 30, 2022, the Company completed the sale of Seneca's California assets. Because of this sale, the Company terminated its remaining crude oil derivative contracts and discontinued hedge accounting for such contracts. A loss of $44.6 million was reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet to Operating Revenues on the Consolidated Statement of Income for the year ended September 30, 2022. This loss is included in the reported reclassification amounts.
Credit Risk
The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over the-counter swap positions, no cost collars and applicable foreign currency forward contracts with 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. As of September 2022, 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
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At September 30, 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. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits.
The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value.
Note K — Retirement Plan and Other Post-Retirement Benefits
The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan). The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003 are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $5.3 million, $4.8 million and $4.2 million for the years ended September 30, 2022, 2021 and 2020, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $7.8 million, $7.2 million, and $6.7 million for the years ended September 30, 2022, 2021 and 2020, respectively.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.
The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations.
The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2022, 2021 and 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits |
| | Year Ended September 30 | | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Change in Benefit Obligation | | | | | | | | | | | |
Benefit Obligation at Beginning of Period | $ | 1,098,456 | | $ | 1,139,105 | | $ | 1,097,625 | | $ | 431,213 | | $ | 476,722 | | $ | 468,163 |
| Service Cost | 8,758 | | 9,865 | | 9,318 | | 1,328 | | 1,602 | | 1,609 |
| Interest Cost | 22,827 | | 21,686 | | 29,930 | | 9,066 | | 9,303 | | 12,913 |
| Plan Participants’ Contributions | — | | — | | — | | 3,271 | | 3,216 | | 3,058 |
| Retiree Drug Subsidy Receipts | — | | — | | — | | 312 | | 1,244 | | 1,411 |
| | | | | | | | | | | |
| Actuarial (Gain) Loss | (251,173) | | (8,141) | | 65,908 | | (120,276) | | (34,729) | | 16,396 |
| Benefits Paid | (65,040) | | (64,059) | | (63,676) | | (25,631) | | (26,145) | | (26,828) |
Benefit Obligation at End of Period | $ | 813,828 | | $ | 1,098,456 | | $ | 1,139,105 | | $ | 299,283 | | $ | 431,213 | | $ | 476,722 |
| Change in Plan Assets | | | | | | | | | | | |
Fair Value of Assets at Beginning of Period | $ | 1,095,729 | | $ | 1,016,796 | | $ | 968,449 | | $ | 575,565 | | $ | 547,885 | | $ | 524,127 |
| Actual Return on Plan Assets | (205,884) | | 122,992 | | 87,402 | | (94,849) | | 47,541 | | 44,448 |
| Employer Contributions | 20,400 | | 20,000 | | 24,621 | | 3,082 | | 3,068 | | 3,080 |
| Plan Participants’ Contributions | — | | — | | — | | 3,271 | | 3,216 | | 3,058 |
| Benefits Paid | (65,040) | | (64,059) | | (63,676) | | (25,631) | | (26,145) | | (26,828) |
Fair Value of Assets at End of Period | $ | 845,205 | | $ | 1,095,729 | | $ | 1,016,796 | | $ | 461,438 | | $ | 575,565 | | $ | 547,885 |
Net Amount Recognized at End of Period (Funded Status) | $ | 31,377 | | $ | (2,727) | | $ | (122,309) | | $ | 162,155 | | $ | 144,352 | | $ | 71,163 |
Amounts Recognized in the Balance Sheets Consist of: | | | | | | | | | | | |
| Non-Current Liabilities | $ | — | | $ | (2,727) | | $ | (122,309) | | $ | (3,065) | | $ | (4,799) | | $ | (4,872) |
| Non-Current Assets | 31,377 | | — | | — | | 165,220 | | 149,151 | | 76,035 |
Net Amount Recognized at End of Period | $ | 31,377 | | $ | (2,727) | | $ | (122,309) | | $ | 162,155 | | $ | 144,352 | | $ | 71,163 |
| Accumulated Benefit Obligation | $ | 793,555 | | $ | 1,060,659 | | $ | 1,096,427 | | N/A | | N/A | | N/A |
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 | | | | | | | | | | | |
| Discount Rate | 5.57 | % | | 2.75 | % | | 2.66 | % | | 5.56 | % | | 2.76 | % | | 2.71 | % |
| Rate of Compensation Increase | 4.60 | % | | 4.70 | % | | 4.70 | % | | 4.60 | % | | 4.70 | % | | 4.70 | % |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Retirement Plan | | Other Post-Retirement Benefits |
| | Year Ended September 30 | | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 |
| | (Thousands) |
Components of Net Periodic Benefit Cost | | | | | | | | | | | |
| Service Cost | $ | 8,758 | | $ | 9,865 | | $ | 9,318 | | $ | 1,328 | | $ | 1,602 | | $ | 1,609 |
| Interest Cost | 22,827 | | 21,686 | | 29,930 | | 9,066 | | 9,303 | | 12,913 |
| Expected Return on Plan Assets | (52,294) | | (58,148) | | (60,063) | | (29,359) | | (28,964) | | (29,232) |
Amortization of Prior Service Cost (Credit) | 537 | | 631 | | 729 | | (429) | | (429) | | (429) |
| | | | | | | | | | | |
| Recognition of Actuarial (Gain) Loss(1) | 26,405 | | 36,814 | | 39,384 | | (7,610) | | 849 | | 535 |
Net Amortization and Deferral for Regulatory Purposes | 16,854 | | 14,063 | | 5,359 | | 21,340 | | 28,010 | | 25,596 |
| Net Periodic Benefit Cost (Income) | $ | 23,087 | | $ | 24,911 | | $ | 24,657 | | $ | (5,664) | | $ | 10,371 | | $ | 10,992 |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 | | | | | | | | | | | |
Effective Discount Rate for Benefit Obligations | 2.75 | % | | 2.66 | % | | 3.15 | % | | 2.76 | % | | 2.71 | % | | 3.17 | % |
Effective Rate for Interest on Benefit Obligations | 2.14 | % | | 1.96 | % | | 2.81 | % | | 2.17 | % | | 2.01 | % | | 2.84 | % |
Effective Discount Rate for Service Cost | 2.95 | % | | 3.01 | % | | 3.31 | % | | 3.00 | % | | 3.20 | % | | 3.39 | % |
Effective Rate for Interest on Service Cost | 2.70 | % | | 2.60 | % | | 3.12 | % | | 2.93 | % | | 2.98 | % | | 3.30 | % |
| Expected Return on Plan Assets | 5.20 | % | | 6.00 | % | | 6.40 | % | | 5.20 | % | | 5.40 | % | | 5.70 | % |
| Rate of Compensation Increase | 4.70 | % | | 4.70 | % | | 4.70 | % | | 4.70 | % | | 4.70 | % | | 4.70 | % |
(1)Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
The Net Periodic Benefit Cost (Income) in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.
In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees whose income level has exceeded certain IRS thresholds or who have been designated as participants by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were $8.9 million, $8.3
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
million and $8.9 million in 2022, 2021 and 2020, respectively. The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $64.9 million, $76.9 million and $78.7 million at September 30, 2022, 2021 and 2020, respectively. The projected benefit obligations for the plans were $77.2 million, $95.8 million and $98.1 million at September 30, 2022, 2021 and 2020, respectively. At September 30, 2022, $17.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $59.7 million is recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2021, $15.4 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $80.4 million was recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2020, $14.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $83.6 million was recorded in Other Liabilities on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 5.49%, 2.15% and 1.92% as of September 30, 2022, 2021 and 2020, respectively and the weighted average rate of compensation increase for these plans was 8.00% as of September 30, 2022, 2021 and 2020.
The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2022, as well as the changes in such amounts during 2022, are presented in the table below:
| | | | | | | | | | | | | | | | | |
| Retirement
Plan | | Other
Post-Retirement
Benefits | | Non-Qualified
Benefit Plans |
| | (Thousands) |
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) | | | | | |
| Net Actuarial Gain (Loss) | $ | (86,133) | | | $ | 14,569 | | | $ | (18,718) | |
| Prior Service (Cost) Credit | (2,472) | | | 1,543 | | | — | |
| Net Amount Recognized | $ | (88,605) | | | $ | 16,112 | | | $ | (18,718) | |
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2022(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 | |
| | | | | |
| Prior Service (Cost) Credit | 537 | | | (429) | | | — | |
| Net Change | $ | 19,936 | | | $ | (11,971) | | | $ | 14,523 | |
(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.
The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected benefit obligation of the Retirement Plan by $262.2 million. The mortality improvement projection scale was updated, which increased the projected benefit obligation of the Retirement Plan in 2022 by $1.8 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2022 by $9.2 million. The effect of the discount rate change for the Retirement Plan in 2021 was to decrease the projected benefit
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. The Company expects that the annual contribution to the Retirement Plan in 2023 will be in the range of zero to $8.0 million.
The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $67.6 million in 2023; $67.7 million in 2024; $67.3 million in 2025; $66.9 million in 2026; $66.2 million in 2027; and $316.1 million in the five years thereafter.
The effect of the discount rate change in 2022 was to decrease the other post-retirement benefit obligation by $98.9 million. The mortality improvement projection scale was updated, which increased the other post-retirement benefit obligation in 2022 by $1.1 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2022 by $22.5 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.
The effect of the discount rate change in 2021 was to decrease the other post-retirement benefit obligation by $2.5 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2021 by $2.0 million. The health care cost trend rates were updated, which decreased the other post-retirement benefit obligation in 2021 by $3.7 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2021 by $26.6 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.
The 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.
The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):
| | | | | | | | | | | |
| Benefit Payments | | Subsidy Receipts |
| 2023 | $ | 26,221 | | | $ | (1,829) | |
| 2024 | $ | 26,337 | | | $ | (1,929) | |
| 2025 | $ | 26,376 | | | $ | (2,014) | |
| 2026 | $ | 26,291 | | | $ | (2,096) | |
| 2027 | $ | 26,140 | | | $ | (2,162) | |
2028 through 2032 | $ | 125,765 | | | $ | (11,391) | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Assumed health care cost trend rates as of September 30 were:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2022 | | | 2021 | | | 2020 | |
| Rate of Medical Cost Increase for Pre Age 65 Participants | 5.30 | % | (1) | | 5.38 | % | (1) | | 5.42 | % | (2) |
| Rate of Medical Cost Increase for Post Age 65 Participants | 4.84 | % | (1) | | 4.84 | % | (1) | | 4.75 | % | (2) |
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | 6.29 | % | (1) | | 6.53 | % | (1) | | 6.80 | % | (2) |
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | 4.84 | % | (1) | | 4.84 | % | (1) | | 4.75 | % | (2) |
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy | 5.96 | % | (1) | | 6.15 | % | (1) | | 6.20 | % | (2) |
(1)It was assumed that this rate would gradually decline to 4% by 2046.
(2)It was assumed that this rate would gradually decline to 4.5% by 2039.
The Company made cash contributions totaling $2.8 million to its VEBA trusts during the year ended September 30, 2022. In addition, the Company made direct payments of $0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2022. The Company does not expect to make any contributions to its VEBA trusts in 2023.
Investment Valuation
The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note I — Fair Value Measurements for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.
The inputs or methodologies used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, 2022 and 2021, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall, based on the lowest level input that is significant to the fair value measurement in its entirety (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2022 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(7) |
| Retirement Plan Investments | | | | | | | | | |
| Domestic Equities(1) | $ | 41,633 | | | $ | 41,633 | | | $ | — | | | $ | — | | | $ | — | |
| International Equities(2) | 1,363 | | | — | | | — | | | — | | | 1,363 | |
| Global Equities(3) | 44,434 | | | — | | | — | | | — | | | 44,434 | |
| Domestic Fixed Income(4) | 658,833 | | | — | | | 579,606 | | | — | | | 79,227 | |
| International Fixed Income(5) | 7,782 | | | — | | | 7,782 | | | — | | | — | |
| | | | | | | | | |
| | | | | | | | | |
| Real Estate | 140,739 | | | — | | | — | | | — | | | 140,739 | |
| Cash Held in Collective Trust Funds | 17,388 | | | — | | | — | | | — | | | 17,388 | |
| Total Retirement Plan Investments | 912,172 | | | 41,633 | | | 587,388 | | | — | | | 283,151 | |
| 401(h) Investments | (73,044) | | | (3,310) | | | (46,694) | | | — | | | (23,040) | |
Total Retirement Plan Investments (excluding 401(h) Investments) | $ | 839,128 | | | $ | 38,323 | | | $ | 540,694 | | | $ | — | | | $ | 260,111 | |
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | 6,077 | | | | | | | | | |
| Total Retirement Plan Assets | $ | 845,205 | | | | | | | | | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2021 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(7) |
| Retirement Plan Investments | | | | | | | | | |
| Domestic Equities(1) | $ | 56,511 | | | $ | 146 | | | $ | — | | | $ | — | | | $ | 56,365 | |
| International Equities(2) | 28,917 | | | — | | | — | | | — | | | 28,917 | |
| Global Equities(3) | 95,865 | | | — | | | — | | | — | | | 95,865 | |
| Domestic Fixed Income(4) | 818,361 | | | 1,447 | | | 758,417 | | | — | | | 58,497 | |
| International Fixed Income(5) | 13,773 | | | — | | | 13,773 | | | — | | | — | |
| Global Fixed Income(6) | 42,454 | | | — | | | — | | | — | | | 42,454 | |
| | | | | | | | | |
| Real Estate | 119,451 | | | — | | | — | | | 319 | | | 119,132 | |
| Cash Held in Collective Trust Funds | 27,471 | | | — | | | — | | | — | | | 27,471 | |
| Total Retirement Plan Investments | 1,202,803 | | | 1,593 | | | 772,190 | | | 319 | | | 428,701 | |
| 401(h) Investments | (90,429) | | | (121) | | | (58,840) | | | (24) | | | (31,444) | |
Total Retirement Plan Investments (excluding 401(h) Investments) | $ | 1,112,374 | | | $ | 1,472 | | | $ | 713,350 | | | $ | 295 | | | $ | 397,257 | |
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | (16,645) | | | | | | | | | |
| Total Retirement Plan Assets | $ | 1,095,729 | | | | | | | | | |
(1)Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
(2)International Equities are comprised of collective trust funds.
(3)Global Equities are comprised of collective trust funds.
(4)Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
(5)International Fixed Income securities are comprised mostly of corporate/government bonds.
(6)Global Fixed Income securities are comprised of a collective trust fund.
(7)Reflects the authoritative guidance related to investments measured at net asset value (NAV).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2022 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(1) |
Other Post-Retirement Benefit Assets held in VEBA Trusts | | | | | | | | | |
Collective Trust Funds — Global Equities | $ | 104,554 | | | $ | — | | | $ | — | | | $ | — | | | $ | 104,554 | |
| | | | | | | | | |
| | | | | | | | | |
| Exchange Traded Funds — Fixed Income | 270,581 | | | 270,581 | | | — | | | — | | | — | |
| | | | | | | | | |
| Cash Held in Collective Trust Funds | 10,635 | | | — | | | — | | | — | | | 10,635 | |
| Total VEBA Trust Investments | 385,770 | | | 270,581 | | | — | | | — | | | 115,189 | |
| 401(h) Investments | 73,044 | | | 3,310 | | | 46,694 | | | — | | | 23,040 | |
Total Investments (including 401(h) Investments) | $ | 458,814 | | | $ | 273,891 | | | $ | 46,694 | | | $ | — | | | $ | 138,229 | |
| Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | 2,624 | | | | | | | | | |
Total Other Post-Retirement Benefit Assets | $ | 461,438 | | | | | | | | | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| At September 30, 2021 |
| Total
Fair Value | | Level 1 | | Level 2 | | Level 3 | | Measured
at NAV(1) |
Other Post-Retirement Benefit Assets held in VEBA Trusts | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Collective Trust Funds — Global Equities | $ | 165,226 | | | $ | — | | | $ | — | | | $ | — | | | $ | 165,226 | |
| Exchange Traded Funds — Fixed Income | 313,392 | | | 313,392 | | | — | | | — | | | — | |
| | | | | | | | | |
| Cash Held in Collective Trust Funds | 9,700 | | | — | | | — | | | — | | | 9,700 | |
| Total VEBA Trust Investments | 488,318 | | | 313,392 | | | — | | | — | | | 174,926 | |
| 401(h) Investments | 90,429 | | | 121 | | | 58,840 | | | 24 | | | 31,444 | |
Total Investments (including 401(h) Investments) | $ | 578,747 | | | $ | 313,513 | | | $ | 58,840 | | | $ | 24 | | | $ | 206,370 | |
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | (3,182) | | | | | | | | | |
Total Other Post-Retirement Benefit Assets | $ | 575,565 | | | | | | | | | |
(1)Reflects the authoritative guidance related to investments measured at net asset value (NAV).
The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.
The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3). For the years ended September 30, 2022 and September 30, 2021, there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.
| | | | | | | | | | | | | | | | | | | |
| | | | Retirement Plan Level 3 Assets
(Thousands) |
| | | | Real
Estate | | Excluding
401(h)
Investments | | Total |
|
|
Balance at September 30, 2020 | | | $ | 471 | | | $ | (35) | | | $ | 436 | |
| | | | | | | |
| Unrealized Gains/(Losses) | | | (152) | | | 11 | | | (141) | |
| | | | | | | |
| Sales | | | — | | | — | | | — | |
Balance at September 30, 2021 | | | 319 | | | (24) | | | 295 | |
| | | | | | | |
| Unrealized Gains/(Losses) | | | 234 | | | (18) | | | 216 | |
| | | | | | | |
| Sales | | | (553) | | | 42 | | | (511) | |
Balance at September 30, 2022 | | | $ | — | | | $ | — | | | $ | — | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | |
| | | | Other Post-Retirement Benefit Level 3 Assets
(Thousands) | | |
| | | | 401(h)
Investments | | |
| | | |
Balance at September 30, 2020 | | | $ | 35 | | | |
| | | | | |
| Unrealized Gains/(Losses) | | | (11) | | | |
| | | | | |
| Sales | | | — | | | |
Balance at September 30, 2021 | | | 24 | | | |
| | | | | |
| Unrealized Gains/(Losses) | | | 18 | | | |
| Sales | | | (42) | | | |
Balance at September 30, 2022 | | | $ | — | | | |
The Company’s assumption regarding the expected long-term rate of return on plan assets is 6.90% (Retirement Plan) and 5.70% (other post-retirement benefits), effective for fiscal 2023. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.
The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trust, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity. In fiscal 2021 and fiscal 2022, capital market conditions led to significant improvements in the funded status of the Retirement Plan. As a result, the Company reduced the return seeking portion of its assets during both years, particularly equity securities and return seeking fixed income securities, held in the Retirement Plan, and increased its allocation to hedging fixed income securities in conjunction with the Company’s liability driven investment strategy. The actual asset allocations as of September 30, 2022 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets. Given the level of the VEBA trust and 401(h) assets in relation to the Other Post-Retirement Benefits, the majority of those assets are and will remain in fixed income securities.
Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.
The Company determines the service and interest cost components of net periodic benefit cost using the spot rate approach, which uses individual spot rates along the yield curve that correspond to the timing of each benefit payment in order to determine the discount rate. The individual spot rates along the yield curve are determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile are excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note L — Commitments and Contingencies
Environmental Matters
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.
It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, 2022, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.6 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2022. 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. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.
Northern Access Project
On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. As of September 30, 2022, the Company has spent approximately $55.8 million on the project, all of which is recorded on the balance sheet.
Other
The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $458.2 million in 2023, $98.6 million in 2024, $135.6 million in 2025, $150.7 million in 2026, $142.1 million in 2027 and $1,001.0 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.
The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. As of September 30, 2022, the future contractual commitments related to the system modernization and expansion projects are $68.9 million in 2023, $8.5 million in 2024, $8.1 million in 2025, $6.9 million in 2026, $5.8 million in 2027 and $5.8 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. 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. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.
Note M — Business Segment Information
The Company reports financial results for four segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas reserves in the Appalachian region of the United States.
The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers, exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for natural gas marketers and exploration and production companies (including Seneca) from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points with access to additional markets in the northeastern United States and Canada.
The Gathering segment is comprised of Midstream Company’s operations. Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region and currently provides gathering services primarily to Seneca.
The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.
The data presented in the tables below reflects financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A — Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations (when applicable). When this is not applicable, the Company evaluates performance based on net income.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2022 |
| | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
| Revenue from External Customers(1)(2) | $ | 1,010,464 | | | $ | 265,415 | | | $ | 12,086 | | | $ | 897,916 | | | $ | 2,185,881 | | | $ | — | | | $ | 165 | | | $ | 2,186,046 | |
Intersegment Revenues | $ | — | | | $ | 111,629 | | | $ | 202,757 | | | $ | 305 | | | $ | 314,691 | | | $ | 6 | | | $ | (314,697) | | | $ | — | |
| Interest Income | $ | 1,929 | | | $ | 2,275 | | | $ | 198 | | | $ | 2,730 | | | $ | 7,132 | | | $ | 3 | | | $ | (1,024) | | | $ | 6,111 | |
| Interest Expense | $ | 53,401 | | | $ | 42,492 | | | $ | 16,488 | | | $ | 24,115 | | | $ | 136,496 | | | $ | 4 | | | $ | (6,143) | | | $ | 130,357 | |
| Depreciation, Depletion and Amortization | $ | 208,148 | | | $ | 67,701 | | | $ | 33,998 | | | $ | 59,760 | | | $ | 369,607 | | | $ | — | | | $ | 183 | | | $ | 369,790 | |
Income Tax Expense (Benefit) | $ | 43,898 | | | $ | 35,043 | | | $ | 24,949 | | | $ | 17,165 | | | $ | 121,055 | | | $ | 3 | | | $ | (4,429) | | | $ | 116,629 | |
| | | | | | | | | | | | | | | |
| Significant Item: Gain on Sale of Assets | $ | 12,736 | | | $ | — | | | $ | — | | | $ | — | | | $ | 12,736 | | | $ | — | | | $ | — | | | $ | 12,736 | |
Segment Profit: Net Income (Loss) | $ | 306,064 | | | $ | 102,557 | | | $ | 101,111 | | | $ | 68,948 | | | $ | 578,680 | | | $ | (9) | | | $ | (12,650) | | | $ | 566,021 | |
Expenditures for Additions to Long-Lived Assets | $ | 565,791 | | | $ | 95,806 | | | $ | 55,546 | | | $ | 111,033 | | | $ | 828,176 | | | $ | — | | | $ | 1,212 | | | $ | 829,388 | |
| | At September 30, 2022 |
| | (Thousands) |
| Segment Assets | $ | 2,507,541 | | | $ | 2,394,697 | | | $ | 878,796 | | | $ | 2,299,473 | | | $ | 8,080,507 | | | $ | 2,036 | | | $ | (186,281) | | | $ | 7,896,262 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2021 |
| | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Elimination | | Total
Consolidated |
| | (Thousands) |
Revenue from External Customers(1) | $ | 836,697 | | | $ | 234,397 | | | $ | 3,116 | | | $ | 666,920 | | | $ | 1,741,130 | | | $ | 1,173 | | | $ | 356 | | | $ | 1,742,659 | |
Intersegment Revenues | $ | — | | | $ | 109,160 | | | $ | 190,148 | | | $ | 331 | | | $ | 299,639 | | | $ | 49 | | | $ | (299,688) | | | $ | — | |
| Interest Income | $ | 211 | | | $ | 1,085 | | | $ | 259 | | | $ | 2,117 | | | $ | 3,672 | | | $ | 230 | | | $ | 486 | | | $ | 4,388 | |
| Interest Expense | $ | 69,662 | | | $ | 40,976 | | | $ | 17,493 | | | $ | 21,795 | | | $ | 149,926 | | | $ | — | | | $ | (3,569) | | | $ | 146,357 | |
Depreciation, Depletion and Amortization | $ | 182,492 | | | $ | 62,431 | | | $ | 32,350 | | | $ | 57,457 | | | $ | 334,730 | | | $ | 394 | | | $ | 179 | | | $ | 335,303 | |
Income Tax Expense (Benefit) | $ | 33,370 | | | $ | 28,812 | | | $ | 28,876 | | | $ | 14,007 | | | $ | 105,065 | | | $ | 11,438 | | | $ | (1,821) | | | $ | 114,682 | |
| Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | $ | 76,152 | | | $ | — | | | $ | — | | | $ | — | | | $ | 76,152 | | | $ | — | | | $ | — | | | $ | 76,152 | |
| Significant Item: Gain on Sale of Assets | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 51,066 | | | $ | — | | | $ | 51,066 | |
Segment Profit: Net Income (Loss) | $ | 101,916 | | | $ | 92,542 | | | $ | 80,274 | | | $ | 54,335 | | | $ | 329,067 | | | $ | 37,645 | | | $ | (3,065) | | | $ | 363,647 | |
Expenditures for Additions to Long-Lived Assets | $ | 381,408 | | | $ | 252,316 | | | $ | 34,669 | | | $ | 100,845 | | | $ | 769,238 | | | $ | — | | | $ | 673 | | | $ | 769,911 | |
| | At September 30, 2021 |
| | (Thousands) |
| Segment Assets | $ | 2,286,058 | | | $ | 2,296,030 | | | $ | 837,729 | | | $ | 2,148,267 | | | $ | 7,568,084 | | | $ | 4,146 | | | $ | (107,405) | | | $ | 7,464,825 | |
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended September 30, 2020 |
| | Exploration
and
Production | | Pipeline
and
Storage | | Gathering | | Utility | | Total
Reportable
Segments | | All
Other | | Corporate
and
Intersegment
Eliminations | | Total
Consolidated |
| | (Thousands) |
Revenue from External Customers(1) | $ | 607,453 | | | $ | 205,998 | | | $ | 72 | | | $ | 642,855 | | | $ | 1,456,378 | | | $ | 89,435 | | | $ | 478 | | | $ | 1,546,291 | |
Intersegment Revenues | $ | — | | | $ | 103,606 | | | $ | 142,821 | | | $ | 9,443 | | | $ | 255,870 | | | $ | 836 | | | $ | (256,706) | | | $ | — | |
| Interest Income | $ | 698 | | | $ | 1,475 | | | $ | 545 | | | $ | 2,262 | | | $ | 4,980 | | | $ | 860 | | | $ | (833) | | | $ | 5,007 | |
| Interest Expense | $ | 58,098 | | | $ | 32,731 | | | $ | 10,877 | | | $ | 22,150 | | | $ | 123,856 | | | $ | 66 | | | $ | (6,845) | | | $ | 117,077 | |
Depreciation, Depletion and Amortization | $ | 172,124 | | | $ | 53,951 | | | $ | 22,440 | | | $ | 55,248 | | | $ | 303,763 | | | $ | 1,716 | | | $ | 679 | | | $ | 306,158 | |
Income Tax Expense (Benefit) | $ | (41,472) | | | $ | 28,613 | | | $ | 18,191 | | | $ | 13,274 | | | $ | 18,606 | | | $ | 210 | | | $ | (77) | | | $ | 18,739 | |
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | $ | 449,438 | | | $ | — | | | $ | — | | | $ | — | | | $ | 449,438 | | | $ | — | | | $ | — | | | $ | 449,438 | |
Segment Profit: Net Income (Loss) | $ | (326,904) | | | $ | 78,860 | | | $ | 68,631 | | | $ | 57,366 | | | $ | (122,047) | | | $ | (269) | | | $ | (1,456) | | | $ | (123,772) | |
Expenditures for Additions to Long-Lived Assets | $ | 670,455 | | | $ | 166,652 | | | $ | 297,806 | | | $ | 94,273 | | | $ | 1,229,186 | | | $ | 39 | | | $ | (608) | | | $ | 1,228,617 | |
| | At September 30, 2020 |
| | (Thousands) |
| Segment Assets | $ | 1,979,028 | | | $ | 2,204,971 | | | $ | 945,199 | | | $ | 2,067,852 | | | $ | 7,197,050 | | | $ | 113,571 | | | $ | (345,686) | | | $ | 6,964,935 | |
(1)All Revenue from External Customers originated in the United States.
(2)Revenues from three customers of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $850 million of the Company's consolidated revenue for the year ended September 30, 2022. These three customers were also customers of the Company's Pipeline and Storage segment, accounting for an additional $15 million of the Company's consolidated revenue for the year ended September 30, 2022.
| | | | | | | | | | | | | | | | | |
| Geographic Information | At September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| Long-Lived Assets: | | | | | |
| United States | $ | 7,135,131 | | | $ | 6,942,376 | | | $ | 6,597,313 | |
Note N — Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)
The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period.
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. dollars. 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
| | | | | | | | | | | |
| | At September 30 |
| | 2022 | | 2021 |
| | (Thousands) |
| Proved Properties(1) | $ | 5,915,807 | | | $ | 6,652,341 | |
| Unproved Properties | 65,994 | | | 103,759 | |
| 5,981,801 | | | 6,756,100 | |
| Less — Accumulated Depreciation, Depletion and Amortization | 4,034,266 | | | 4,881,972 | |
| $ | 1,947,535 | | | $ | 1,874,128 | |
(1)Includes asset retirement costs of $120.8 million and $152.8 million at September 30, 2022 and 2021, respectively.
Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by 2027. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2025. Following is a summary of costs excluded from amortization at September 30, 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Total as of September 30, 2022 | | Year Costs Incurred |
| | 2022 | | 2021 | | 2020 | | Prior |
| | (Thousands) |
| Acquisition Costs | $ | 41,831 | | | $ | — | | | $ | — | | | $ | 29,698 | | | $ | 12,133 | |
| Development Costs | 24,163 | | | 17,590 | | | 4,085 | | | 2,488 | | | — | |
| Exploration Costs | — | | | — | | | — | | | — | | | — | |
| Capitalized Interest | — | | | — | | | — | | | — | | | — | |
| $ | 65,994 | | | $ | 17,590 | | | $ | 4,085 | | | $ | 32,186 | | | $ | 12,133 | |
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| United States | |
| Property Acquisition Costs: | | | | | |
| Proved | $ | 2,491 | | | $ | 1,801 | | | $ | 245,976 | |
| Unproved | 10,665 | | | 5,102 | | | 42,922 | |
| Exploration Costs(1) | 9,631 | | | 15,413 | | | 3,891 | |
| Development Costs(2) | 528,684 | | | 329,368 | | | 355,742 | |
| Asset Retirement Costs | 9,768 | | | 20,194 | | | 62,080 | |
| $ | 561,239 | | | $ | 371,878 | | | $ | 710,611 | |
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.
(2)Amounts for 2022, 2021 and 2020 include capitalized interest of $0.6 million, $0.4 million and $1.0 million, respectively.
For the years ended September 30, 2022, 2021 and 2020, the Company spent $154.3 million, $81.2 million and $219.9 million, respectively, developing proved undeveloped reserves.
Results of Operations for Producing Activities
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| United States | (Thousands, except per Mcfe amounts) |
| Operating Revenues: | | | | | |
Gas (includes transfers to operations of $5,696, $3,061 and $1,921, respectively)(1) | $ | 1,730,723 | | | $ | 780,477 | | | $ | 402,447 | |
| Oil, Condensate and Other Liquids | 150,957 | | | 135,191 | | | 107,844 | |
| Total Operating Revenues(2) | 1,881,680 | | | 915,668 | | | 510,291 | |
| Production/Lifting Costs | 283,914 | | | 267,316 | | | 203,670 | |
| Franchise/Ad Valorem Taxes | 25,112 | | | 22,128 | | | 15,582 | |
| Purchased Emission Allowance Expense | 1,305 | | | 2,940 | | | 2,930 | |
| Accretion Expense | 7,530 | | | 7,743 | | | 5,237 | |
Depreciation, Depletion and Amortization ($0.57, $0.54 and $0.69 per Mcfe of production, respectively) | 202,418 | | | 177,055 | | | 166,759 | |
| Impairment of Oil and Gas Producing Properties | — | | | 76,152 | | | 449,438 | |
| Income Tax Expense | 368,925 | | | 98,593 | | | (92,820) | |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | $ | 992,476 | | | $ | 263,741 | | | $ | (240,505) | |
(1)There were no revenues from sales to affiliates for all years presented.
(2)Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments.
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. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 13 years of Petroleum Engineering experience with independent oil and gas companies, licensure as a Professional Engineer and is a member of the Society of Petroleum Engineers.
The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Senior Manager 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.
All of the Company's reserve estimates are audited annually by Netherland, Sewell & Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2011 and with over 4 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2022 and did not identify any problems which would cause it to take exception to those estimates.
The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company's and competitors’ wells. Geophysical data includes data from the Company's wells, third-party wells, published documents and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | |
| | Gas MMcf |
| | U.S. | | |
| | Appalachian
Region | | West Coast
Region | | Total
Company |
| Proved Developed and Undeveloped Reserves: | | | | | |
| September 30, 2019 | 2,915,886 | | | 33,633 | | | 2,949,519 | |
| Extensions and Discoveries | 7,246 | | (1) | — | | | 7,246 | |
| Revisions of Previous Estimates | (85,647) | | | (2,772) | | | (88,419) | |
| Production | (225,513) | | (2) | (1,889) | | | (227,402) | |
| Purchases of Minerals in Place | 684,141 | | | — | | | 684,141 | |
| | | | | |
| September 30, 2020 | 3,296,113 | | | 28,972 | | | 3,325,085 | |
| Extensions and Discoveries | 689,395 | | (1) | — | | | 689,395 | |
| Revisions of Previous Estimates | 19,940 | | | 3,033 | | | 22,973 | |
| Production | (312,300) | | (2) | (1,720) | | | (314,020) | |
| | | | | |
| | | | | |
| September 30, 2021 | 3,693,148 | | | 30,285 | | | 3,723,433 | |
| Extensions and Discoveries | 837,510 | | (1) | — | | | 837,510 | |
| Revisions of Previous Estimates | 2,882 | | | 71 | | | 2,953 | |
| 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 | |
| Proved Developed Reserves: | | | | | |
| September 30, 2019 | 1,901,162 | | | 33,633 | | | 1,934,795 | |
| September 30, 2020 | 2,744,851 | | | 28,972 | | | 2,773,823 | |
| September 30, 2021 | 3,061,178 | | | 30,285 | | | 3,091,463 | |
| September 30, 2022 | 3,312,568 | | | — | | | 3,312,568 | |
| Proved Undeveloped Reserves: | | | | | |
| September 30, 2019 | 1,014,724 | | | — | | | 1,014,724 | |
| September 30, 2020 | 551,262 | | | — | | | 551,262 | |
| September 30, 2021 | 631,970 | | | — | | | 631,970 | |
| September 30, 2022 | 858,094 | | | — | | | 858,094 | |
(1)Extensions and discoveries include 7 Bcf (during 2020), 180 Bcf (during 2021) and 301 Bcf (during 2022), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 0 Bcf (during 2020), 497 Bcf (during 2021) and 537 Bcf (during 2022), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.
(2)Production includes 169,453 MMcf (during 2020), 218,016 MMcf (during 2021) and 209,463 MMcf (during 2022), from Marcellus Shale fields. Production includes 55,392 MMcf (during 2020), 93,253 MMcf (during 2021) and 130,240 MMcf (during 2022), from Utica Shale fields.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | |
| | Oil Mbbl |
| | U.S. | | |
| | Appalachian
Region | | West Coast
Region | | Total
Company |
| Proved Developed and Undeveloped Reserves: | | | | | |
| September 30, 2019 | 13 | | | 24,860 | | | 24,873 | |
| Extensions and Discoveries | — | | | 288 | | | 288 | |
| Revisions of Previous Estimates | 2 | | | (715) | | | (713) | |
| Production | (3) | | | (2,345) | | | (2,348) | |
| | | | | |
| | | | | |
| | | | | |
| September 30, 2020 | 12 | | | 22,088 | | | 22,100 | |
| Extensions and Discoveries | — | | | 1,041 | | | 1,041 | |
| Revisions of Previous Estimates | 1 | | | 630 | | | 631 | |
| Production | (2) | | | (2,233) | | | (2,235) | |
| | | | | |
| | | | | |
| September 30, 2021 | 11 | | | 21,526 | | | 21,537 | |
| Extensions and Discoveries | — | | | 296 | | | 296 | |
| Revisions of Previous Estimates | 255 | | | 532 | | | 787 | |
| Production | (16) | | | (1,588) | | | (1,604) | |
| | | | | |
| Sales of Minerals in Place | — | | | (20,766) | | | (20,766) | |
| September 30, 2022 | 250 | | | — | | | 250 | |
| Proved Developed Reserves: | | | | | |
| September 30, 2019 | 13 | | | 24,246 | | | 24,259 | |
| September 30, 2020 | 12 | | | 22,088 | | | 22,100 | |
| September 30, 2021 | 11 | | | 20,930 | | | 20,941 | |
| September 30, 2022 | 250 | | | — | | | 250 | |
| Proved Undeveloped Reserves: | | | | | |
| September 30, 2019 | — | | | 614 | | | 614 | |
| September 30, 2020 | — | | | — | | | — | |
| September 30, 2021 | — | | | 596 | | | 596 | |
| September 30, 2022 | — | | | — | | | — | |
The Company’s proved undeveloped (PUD) reserves increased from 636 Bcfe at September 30, 2021 to 858 Bcfe at September 30, 2022. 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 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 Company’s PUD reserves increased from 551 Bcfe at September 30, 2020 to 636 Bcfe at September 30, 2021. PUD reserves in the Utica Shale increased from 265 Bcfe at September 30, 2020 to 411 Bcfe at September 30, 2021. 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.
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 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, 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 invested $81 million during the year ended September 30, 2021 to convert 188 Bcfe (198 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 34% of the net PUD reserves recorded at September 30, 2020. In the Appalachian region, 18 of 53 PUD locations were developed. PUD expenditures in 2021 were lower than the 2020 estimate primarily due to changes in the development schedule.
In 2023, the Company estimates that it will invest approximately $308 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule was adopted, and over the last five years, the Company developed 51% of its beginning year PUD reserves in fiscal 2018, 39% of its beginning year PUD reserves in fiscal 2019, 36% of its beginning year PUD reserves in fiscal 2020, 34% of its beginning year PUD reserves in fiscal 2021 and 45% of its beginning year PUD reserves in fiscal 2022.
At September 30, 2022, the Company does not have any proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.
The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.
NATIONAL FUEL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| United States | | | | | |
| Future Cash Inflows | $ | 19,209,099 | | | $ | 10,175,182 | | | $ | 6,493,362 | |
| Less: | | | | | |
| Future Production Costs | 3,138,226 | | | 3,423,629 | | | 3,149,857 | |
| Future Development Costs | 781,847 | | | 597,662 | | | 501,678 | |
| Future Income Tax Expense at Applicable Statutory Rate | 3,876,272 | | | 1,397,175 | | | 454,553 | |
| Future Net Cash Flows | 11,412,754 | | | 4,756,716 | | | 2,387,274 | |
| Less: | | | | | |
| 10% Annual Discount for Estimated Timing of Cash Flows | 5,964,424 | | | 2,403,144 | | | 1,164,804 | |
| Standardized Measure of Discounted Future Net Cash Flows | $ | 5,448,330 | | | $ | 2,353,572 | | | $ | 1,222,470 | |
The principal sources of change in the standardized measure of discounted future net cash flows were as follows:
| | | | | | | | | | | | | | | | | |
| | Year Ended September 30 |
| | 2022 | | 2021 | | 2020 |
| | (Thousands) |
| United States | | | | | |
| Standardized Measure of Discounted Future | | | | | |
| Net Cash Flows at Beginning of Year | $ | 2,353,572 | | | $ | 1,222,470 | | | $ | 1,736,319 | |
| Sales, Net of Production Costs | (1,572,402) | | | (626,132) | | | (290,975) | |
| Net Changes in Prices, Net of Production Costs | 4,132,889 | | | 1,478,995 | | | (1,109,101) | |
| Extensions and Discoveries | 1,355,257 | | | 462,040 | | | 4,236 | |
| Changes in Estimated Future Development Costs | (32,160) | | | 48,247 | | | 99,884 | |
| Purchases of Minerals in Place | — | | | — | | | 170,363 | |
| Sales of Minerals in Place | (311,308) | | | — | | | — | |
| Previously Estimated Development Costs Incurred | 154,253 | | | 81,239 | | | 219,938 | |
| Net Change in Income Taxes at Applicable Statutory Rate | (1,180,349) | | | (415,993) | | | 248,182 | |
| Revisions of Previous Quantity Estimates | 3,316 | | | (52,383) | | | (28,337) | |
| Accretion of Discount and Other | 545,262 | | | 155,089 | | | 171,961 | |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | $ | 5,448,330 | | | $ | 2,353,572 | | | $ | 1,222,470 | |