Cover
Cover - USD ($) | 12 Months Ended | ||
Sep. 30, 2023 | Oct. 31, 2023 | Mar. 31, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Current Fiscal Year End Date | --09-30 | ||
Document Period End Date | Sep. 30, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 1-3880 | ||
Entity Registrant Name | National Fuel Gas Company | ||
Entity Incorporation, State or Country Code | NJ | ||
Entity Tax Identification Number | 13-1086010 | ||
Entity Address, Address Line One | 6363 Main Street | ||
Entity Address, Postal Zip Code | 14221 | ||
Entity Address, State or Province | NY | ||
Entity Address, City or Town | Williamsville, | ||
City Area Code | 716 | ||
Local Phone Number | 857-7000 | ||
Title of 12(b) Security | Common Stock, par value $1.00 per share | ||
Trading Symbol | NFG | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
ICFR Auditor Attestation Flag | true | ||
Document Financial Statement Error Correction [Flag] | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 5,187,493,000 | ||
Entity Listing, Par Value Per Share | $ 1 | ||
Entity Common Stock, Shares Outstanding | 91,829,588 | ||
Documents Incorporated by Reference | Portions of the registrant’s definitive Proxy Statement for its 2024 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2023, are incorporated by reference into Part III of this report. | ||
Entity Central Index Key | 0000070145 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Audit Information
Audit Information | 12 Months Ended |
Sep. 30, 2023 | |
Audit Information [Abstract] | |
Auditor Firm ID | 238 |
Auditor Name | PRICEWATERHOUSECOOPERS LLP |
Auditor Location | Buffalo, New York |
Consolidated Statements of Inco
Consolidated Statements of Income and Earnings Reinvested in the Business - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
INCOME | |||
Operating Revenues | $ 2,173,771 | $ 2,186,046 | $ 1,742,659 |
Operating Expenses: | |||
Purchased Gas | 437,595 | 392,093 | 171,827 |
Property, Franchise and Other Taxes | 92,700 | 101,182 | 94,713 |
Depreciation, Depletion and Amortization | 409,573 | 369,790 | 335,303 |
Impairment of Oil and Gas Producing Properties | 0 | 0 | 76,152 |
Total Operating Expenses | 1,418,624 | 1,384,266 | 1,153,801 |
Gain on Sale of Assets | 0 | 12,736 | 51,066 |
Operating Income | 755,147 | 814,516 | 639,924 |
Other Income (Expense): | |||
Other Income (Deductions) | 18,138 | (1,509) | (15,238) |
Interest Expense on Long-Term Debt | (111,948) | (120,507) | (141,457) |
Other Interest Expense | (19,938) | (9,850) | (4,900) |
Income Before Income Taxes | 641,399 | 682,650 | 478,329 |
Income Tax Expense | 164,533 | 116,629 | 114,682 |
Net Income Available for Common Stock | 476,866 | 566,021 | 363,647 |
EARNINGS REINVESTED IN THE BUSINESS | |||
Balance at Beginning of Year | 1,587,085 | 1,191,175 | 991,630 |
Beginning Retained Earnings Unappropriated and Current Period Net Income | 2,063,951 | 1,757,196 | 1,355,277 |
Dividends on Common Stock | (178,095) | (170,111) | (164,102) |
Balance at End of Year | $ 1,885,856 | $ 1,587,085 | $ 1,191,175 |
Basic: | |||
Net Income Available for Common Stock (in dollars per share) | $ 5.20 | $ 6.19 | $ 3.99 |
Diluted: | |||
Net Income Available for Common Stock (in dollars per share) | $ 5.17 | $ 6.15 | $ 3.97 |
Weighted Average Common Shares Outstanding: | |||
Used in Basic Calculation (in shares) | 91,748,890 | 91,410,625 | 91,130,941 |
Used in Diluted Calculation (in shares) | 92,285,918 | 92,107,066 | 91,684,583 |
Utility and Energy Marketing | |||
INCOME | |||
Operating Revenues | $ 941,779 | $ 897,916 | $ 667,549 |
Operating Expenses: | |||
Operation and Maintenance | 205,239 | 193,058 | 179,547 |
Exploration and Production and Other | |||
INCOME | |||
Operating Revenues | 958,455 | 1,010,629 | 837,597 |
Operating Expenses: | |||
Operation and Maintenance | 124,270 | 191,572 | 173,041 |
Pipeline and Storage and Gathering | |||
INCOME | |||
Operating Revenues | 273,537 | 277,501 | 237,513 |
Operating Expenses: | |||
Operation and Maintenance | $ 149,247 | $ 136,571 | $ 123,218 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income Available for Common Stock | $ 476,866 | $ 566,021 | $ 363,647 |
Other Comprehensive Income (Loss), Before Tax: | |||
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | (9,660) | 9,561 | 17,862 |
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | 1,674 | 11,054 | 16,229 |
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 708,206 | (1,050,831) | (665,371) |
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income | 88,656 | 882,581 | 83,711 |
Other Post-Retirement Adjustment for Regulatory Proceeding | 0 | (7,351) | 0 |
Other Comprehensive Income (Loss), Before Tax | 788,876 | (154,986) | (547,569) |
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans | (2,284) | 2,169 | 4,072 |
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | 411 | 2,574 | 3,762 |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 214,270 | (287,608) | (179,028) |
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income | 5,806 | 241,559 | 22,465 |
Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding | 0 | (1,544) | 0 |
Income Taxes — Net | 218,203 | (42,850) | (148,729) |
Other Comprehensive Income (Loss) | 570,673 | (112,136) | (398,840) |
Comprehensive Income (Loss) | $ 1,047,539 | $ 453,885 | $ (35,193) |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | ||
ASSETS | ||||
Property, Plant and Equipment | $ 13,635,303 | $ 12,551,909 | ||
Less — Accumulated Depreciation, Depletion and Amortization | 6,335,441 | 5,985,432 | ||
Property, Plant and Equipment, Net, Total | 7,299,862 | 6,566,477 | ||
Current Assets | ||||
Cash and Temporary Cash Investments | 55,447 | 46,048 | ||
Hedging Collateral Deposits | 0 | 91,670 | [1] | |
Receivables — Net of Allowance for Uncollectible Accounts of $36,295 and $40,228, Respectively | 160,601 | 361,626 | ||
Unbilled Revenue | 16,622 | 30,075 | ||
Gas Stored Underground | 32,509 | 32,364 | ||
Materials and Supplies - at average cost | 48,989 | 40,637 | ||
Unrecovered Purchased Gas Costs | 0 | 99,342 | ||
Other Current Assets | 100,260 | 59,369 | ||
Total Current Assets | 414,428 | 761,131 | ||
Other Assets | ||||
Recoverable Future Taxes | 69,045 | 106,247 | ||
Unamortized Debt Expense | 7,240 | 8,884 | ||
Other Regulatory Assets | 72,138 | 67,101 | ||
Deferred Charges | 82,416 | 77,472 | ||
Other Investments | 73,976 | 95,025 | ||
Goodwill | 5,476 | 5,476 | ||
Prepaid Pension and Post-Retirement Benefit Costs | 200,301 | 196,597 | ||
Fair Value of Derivative Financial Instruments | 50,487 | 9,175 | ||
Other | 4,891 | 2,677 | ||
Total Other Assets | 565,970 | 568,654 | ||
Total Assets | 8,280,260 | 7,896,262 | ||
Comprehensive Shareholders’ Equity | ||||
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 91,819,405 Shares and 91,478,064 Shares, Respectively | 91,819 | 91,478 | ||
Paid In Capital | 1,040,761 | 1,027,066 | ||
Earnings Reinvested in the Business | 1,885,856 | 1,587,085 | ||
Accumulated Other Comprehensive Loss | (55,060) | (625,733) | ||
Total Comprehensive Shareholders’ Equity | 2,963,376 | 2,079,896 | ||
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs | 2,384,485 | 2,083,409 | ||
Total Capitalization | 5,347,861 | 4,163,305 | ||
Current and Accrued Liabilities | ||||
Notes Payable to Banks and Commercial Paper | 287,500 | 60,000 | ||
Current Portion of Long-Term Debt | [2] | 0 | 549,000 | |
Accounts Payable | 152,193 | 178,945 | ||
Amounts Payable to Customers | 59,019 | 419 | ||
Dividends Payable | 45,451 | 43,452 | ||
Interest Payable on Long-Term Debt | 20,399 | 17,376 | ||
Customer Advances | 21,003 | 26,108 | ||
Customer Security Deposits | 28,764 | 24,283 | ||
Other Accruals and Current Liabilities | 160,974 | 257,327 | ||
Fair Value of Derivative Financial Instruments | 31,009 | 785,659 | ||
Total Current and Accrued Liabilities | 806,312 | 1,942,569 | ||
Other Liabilities | ||||
Deferred Income Taxes | 1,124,170 | 698,229 | ||
Taxes Refundable to Customers | 268,562 | 362,098 | ||
Cost of Removal Regulatory Liability | 277,694 | 259,947 | ||
Other Regulatory Liabilities | 165,441 | 188,803 | ||
Other Post-Retirement Liabilities | 2,915 | 3,065 | ||
Asset Retirement Obligations | 165,492 | 161,545 | ||
Other Liabilities | 121,813 | 116,701 | ||
Total Other Liabilities | 2,126,087 | 1,790,388 | ||
Commitments and Contingencies (Note L) | 0 | 0 | ||
Total Capitalization and Liabilities | $ 8,280,260 | $ 7,896,262 | ||
[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.[2]None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed $150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed below. In March 2023, the Company redeemed the remaining $350.0 million of the 3.75% notes as well as the $49.0 million of 7.395% notes |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Statement of Financial Position [Abstract] | ||
Allowance for Uncollectible Accounts | $ 36,295 | $ 40,228 |
Common Stock, Par Value (in dollars per share) | $ 1 | $ 1 |
Common Stock, Shares Authorized (in shares) | 200,000,000 | 200,000,000 |
Common Stock, Shares Issued (in shares) | 91,819,405 | 91,478,064 |
Common Stock, Shares Outstanding (in shares) | 91,819,405 | 91,478,064 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Operating Activities | |||
Net Income Available for Common Stock | $ 476,866 | $ 566,021 | $ 363,647 |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: | |||
Gain on Sale of Assets | 0 | (12,736) | (51,066) |
Impairment of Oil and Gas Producing Properties | 0 | 0 | 76,152 |
Depreciation, Depletion and Amortization | 409,573 | 369,790 | 335,303 |
Deferred Income Taxes | 151,403 | 104,415 | 105,993 |
Premium Paid on Early Redemption of Debt | 0 | 0 | 15,715 |
Stock-Based Compensation | 20,630 | 19,506 | 17,065 |
Reduction of Other Post-Retirement Regulatory Liability | 0 | (18,533) | 0 |
Other | 19,647 | 31,983 | 10,896 |
Change in: | |||
Receivables and Unbilled Revenue | 213,579 | (168,769) | (61,413) |
Gas Stored Underground and Materials, Supplies and Emission Allowances | (8,406) | 3,109 | (2,014) |
Unrecovered Purchased Gas Costs | 99,342 | (66,214) | (33,128) |
Other Current Assets | (41,077) | 291 | (11,972) |
Accounts Payable | (37,095) | 11,907 | 31,352 |
Amounts Payable to Customers | 58,600 | 398 | (10,767) |
Customer Advances | (5,105) | 8,885 | 1,904 |
Customer Security Deposits | 4,481 | 4,991 | 2,093 |
Other Accruals and Current Liabilities | (67,664) | 34,260 | 34,314 |
Other Assets | (26,564) | (58,924) | 1,250 |
Other Liabilities | (31,135) | (17,859) | (33,771) |
Net Cash Provided by Operating Activities | 1,237,075 | 812,521 | 791,553 |
Investing Activities | |||
Capital Expenditures | (1,009,868) | (811,826) | (751,734) |
Net Proceeds from Sale of Oil and Gas Producing Properties | 0 | 254,439 | 0 |
Net Proceeds from Sale of Timber Properties | 0 | 0 | 104,582 |
Sale of Fixed Income Mutual Fund Shares in Grantor Trust | 10,000 | 30,000 | 0 |
Acquisition of Upstream Assets | (124,758) | 0 | 0 |
Other | 12,279 | 8,683 | 13,935 |
Net Cash Used in Investing Activities | (1,112,347) | (518,704) | (633,217) |
Financing Activities | |||
Proceeds from Issuance of Short-Term Note Payable to Bank | 250,000 | 0 | 0 |
Repayment of Short-Term Note Payable to Bank | (250,000) | 0 | 0 |
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper | 227,500 | (98,500) | 128,500 |
Net Proceeds from Issuance of Long-Term Debt | 297,306 | 0 | 495,267 |
Reduction of Long-Term Debt | (549,000) | 0 | (515,715) |
Net Repurchases of Common Stock | (6,709) | (9,590) | (3,702) |
Dividends Paid on Common Stock | (176,096) | (168,147) | (163,089) |
Net Cash Used in Financing Activities | (206,999) | (276,237) | (58,739) |
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash | (82,271) | 17,580 | 99,597 |
Cash, Cash Equivalents and Restricted Cash At Beginning of Year | 137,718 | 120,138 | 20,541 |
Cash, Cash Equivalents and Restricted Cash At End of Year | 55,447 | 137,718 | 120,138 |
Cash Paid For: | |||
Interest | 124,441 | 124,312 | 135,136 |
Income Taxes | 38,098 | 16,680 | 6,374 |
Non-Cash Investing Activities: | |||
Non-Cash Capital Expenditures | 109,208 | 120,262 | 102,700 |
Non-Cash Contingent Consideration for Asset Sale | $ 0 | $ 12,571 | $ 0 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Sep. 30, 2023 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 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 have historically been written off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. During 2022 and 2021, final billings were suppressed in the Utility segment as a result of state shut-off moratoriums arising from the COVID-19 pandemic. Those moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby resulting in higher amounts being written off in 2023. Activity in the allowance for uncollectible accounts are as follows: Year Ended September 30 2023 2022 2021 (Thousands) Balance at Beginning of Year $ 40,228 $ 31,639 $ 22,810 Additions Charged to Costs and Expenses 14,482 13,209 14,940 Add: Discounts on Purchased Receivables 1,380 1,314 1,168 Deduct: Net Accounts Receivable Written-Off 19,795 5,934 7,279 Balance at End of Year $ 36,295 $ 40,228 $ 31,639 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 rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNC as a five-year pilot program. The program is effective October 2023 and covers the eight-month period from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNC, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues. 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 $2.4 billion and $1.9 billion at September 30, 2023 and 2022, respectively. For further discussion of capitalized costs, refer to Note N — Supplementary Information for Oil and Gas Producing Activities. 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, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $794.7 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2023, 2022 and 2021, estimated future net cash flows were increased by $38.8 million, decreased by $1.0 billion and decreased by $76.1 million, respectively. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2023. 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 $235.7 million, $202.4 million and $177.1 million for the years ended September 30, 2023, 2022 and 2021, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated useful lives of property in service. The following is a summary of depreciable plant by segment: As of September 30 2023 2022 (Thousands) Exploration and Production $ 6,741,095 $ 6,088,476 Pipeline and Storage 2,803,690 2,747,948 Gathering 1,032,969 971,665 Utility 2,507,465 2,411,707 All Other and Corporate 15,787 13,712 $ 13,101,006 $ 12,233,508 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2023 2022 2021 Exploration and Production, per Mcfe(1) $ 0.65 $ 0.59 $ 0.56 Pipeline and Storage 2.6 % 2.7 % 2.6 % Gathering 3.6 % 3.6 % 3.6 % Utility 2.7 % 2.7 % 2.7 % All Other and Corporate 2.9 % 1.4 % 3.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.57 and $0.54 per Mcfe of production in 2023, 2022 and 2021, respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2023 and 2022 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, 2023, 2022 and 2021, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance. Financial Instruments The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include natural gas price swap agreements and no cost collars and foreign currency forward contracts. The Company accounts for these instruments as cash flow hedges for which the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note I — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments. For cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues on the Consolidated Statements of Income. Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges. Accumulated Other Comprehensive Loss The components of Accumulated Other Comprehensive Loss and changes for the years ended September 30, 2023 and 2022, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Year Ended September 30, 2023 Balance at October 1, 2022 $ (572,163) $ (53,570) $ (625,733) Other Comprehensive Gains and Losses Before Reclassifications 493,936 (7,376) 486,560 Amounts Reclassified From Other Comprehensive Loss 82,850 1,263 84,113 Balance at September 30, 2023 $ 4,623 $ (59,683) $ (55,060) 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 Loss 641,022 8,480 649,502 Other Post-Retirement Adjustment for Regulatory Proceeding — (5,807) (5,807) Balance at September 30, 2022 $ (572,163) $ (53,570) $ (625,733) The amounts included in accumulated other comprehensive loss related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $0.4 million at both September 30, 2023 and 2022. The total amount for accumulated losses was $59.3 million and $53.2 million at September 30, 2023 and 2022, respectively. 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. Reclassifications Out of Accumulated Other Comprehensive Loss The details about the reclassification adjustments out of accumulated other comprehensive loss for the years ended September 30, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented 2023 2022 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $ (88,015) $ (882,594) Operating Revenues Foreign Currency Contracts (641) 13 Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (82) (103) (1) Net Actuarial Loss (1,592) (10,951) (1) (90,330) (893,635) Total Before Income Tax 6,217 244,133 Income Tax Expense $ (84,113) $ (649,502) 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 2023, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $3.7 million at September 30, 2023. Unamortized Debt Expense Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2023, the remaining weighted average amortization period for such costs was approximately 4 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 2023 2022 2021 2020 Cash and Temporary Cash Investments $ 55,447 $ 46,048 $ 31,528 $ 20,541 Hedging Collateral Deposits — 91,670 88,610 — Cash, Cash Equivalents, and Restricted Cash $ 55,447 $ 137,718 $ 120,138 $ 20,541 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 2023 2022 (Thousands) Prepayments $ 18,966 $ 17,757 Prepaid Property and Other Taxes 14,186 14,321 Federal Income Taxes Receivable 14,602 — State Income Taxes Receivable 16,133 5,933 Regulatory Assets 36,373 21,358 $ 100,260 $ 59,369 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2023 2022 (Thousands) Accrued Capital Expenditures $ 43,323 $ 64,720 Regulatory Liabilities 38,105 31,293 Liability for Royalty and Working Interests 17,679 86,206 Non-Qualified Benefit Plan Liability 13,052 17,474 Other 48,815 57,634 $ 160,974 $ 257,327 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, 2023 and 2022, customers in the balanced billing programs had advanced excess funds of $21.0 million and $26.1 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, 2023 and 2022, the Company had received customer security deposits amounting to $28.8 million and $24.3 million, respectively. Earnings Per Common Share Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding during fiscal 2023, 2022 and/or 2021 were SARs, restricted stock units and performance shares. For the years ended September 30, 2023 and September 30, 2022, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 3,888 securities, 2,858 securities and 320,222 securities excluded as being antidilutive for the years ended September 30, 2023, 2022 and 2021, respectively. Stock-Based Compensation 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 the date of each grant. The Company chose the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs. For all Company stock awards, forfeitures are recognized as they occur. Restricted stock units are subject to restrictions on vesting and transferability. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The restricted stock units do not entitle the participants to dividend and voting rights. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal and greenhouse gas emissions reductions goal, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant. Refer to Note H — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans. |
Asset Acquisitions and Divestit
Asset Acquisitions and Divestitures | 12 Months Ended |
Sep. 30, 2023 | |
Asset Acquisition [Abstract] | |
Asset Acquisitions and Divestitures | Asset Acquisitions and Divestitures On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC (“SWN”) for total consideration of $124.8 million. The purchase price, which reflects an effective date of January 1, 2023, was reduced for production revenues less expenses that were retained by SWN from the effective date to the closing date. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment. The following is a summary of the asset acquisition in thousands: Purchase Price $ 124,178 Transaction Costs 580 Total Consideration $ 124,758 On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. 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 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 |
Revenue from Contracts with Cus
Revenue from Contracts with Customers | 12 Months Ended |
Sep. 30, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contracts with Customers | Revenue from Contracts with Customers The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2023 and 2022, presented by type of service from each reportable segment. Year Ended September 30, 2023 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 1,036,499 $ — $ — $ — $ 1,036,499 $ — $ — $ 1,036,499 Production of Crude Oil 2,261 — — — 2,261 — — 2,261 Natural Gas Processing 1,203 — — — 1,203 — — 1,203 Natural Gas Gathering Service — — 230,317 — 230,317 — (216,426) 13,891 Natural Gas Transportation Service — 291,225 — 98,304 389,529 — (82,889) 306,640 Natural Gas Storage Service — 84,962 — — 84,962 — (36,283) 48,679 Natural Gas Residential Sales — — — 727,728 727,728 — — 727,728 Natural Gas Commercial Sales — — — 103,270 103,270 — — 103,270 Natural Gas Industrial Sales — — — 5,658 5,658 — (7) 5,651 Other 6,507 3,004 — 508 10,019 — (947) 9,072 Total Revenues from Contracts with Customers 1,046,470 379,191 230,317 935,468 2,591,446 — (336,552) 2,254,894 Alternative Revenue Programs — — — 6,892 6,892 — — 6,892 Derivative Financial Instruments (88,015) — — — (88,015) — — (88,015) Total Revenues $ 958,455 $ 379,191 $ 230,317 $ 942,360 $ 2,510,323 $ — $ (336,552) $ 2,173,771 Year Ended September 30, 2022 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (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 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 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: $210.7 million for fiscal 2024; $184.0 million for fiscal 2025; $148.3 million for fiscal 2026; $123.3 million for fiscal 2027; $107.5 million for fiscal 2028; and $581.0 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 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 |
Leases
Leases | 12 Months Ended |
Sep. 30, 2023 | |
Leases [Abstract] | |
Leases | Leases The Company follows authoritative guidance regarding lease accounting, which requires entities that lease the use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, including leases classified as operating leases. The Company has elected to apply the following practical expedients provided in the authoritative guidance: 1. An election not to apply the recognition requirements in the new authoritative guidance to short-term leases (a lease that at commencement date has a lease term of one year or less); 2. A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset-class). Nature of Leases The Company primarily leases building space and drilling rigs, and on a limited basis, compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the authoritative guidance. The Company did not have any material finance leases as of September 30, 2023 or September 30, 2022. Aside from a sublease of office space at the Company’s corporate headquarters, which terminated April 30, 2022, the Company does not have any material arrangements where the Company is the lessor. Buildings and Property 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 one month to sixteen years. Most building leases include one or more options to renew, generally at the Company’s sole discretion, with renewal terms that can extend the lease terms from one year to eighteen years. 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 of one year or less. Upon mutual agreement with the contractor, Seneca has the option to extend contracts with amended terms and conditions, including a renegotiated day rate fee. Drilling rig lease costs are capitalized as part of natural gas properties on the Consolidated Balance Sheet when incurred. 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 9 months to 5 years. Most compressor equipment leases include one or more options to renew or to continue past the primary term on a month-to-month basis, generally at the Company's sole discretion. Renewal options are included in the lease term if they are reasonably certain to be exercised. Significant Judgments Lease Identification The Company uses judgment when determining whether or not an arrangement is or contains a lease. A contract is or contains a lease if the contract conveys the right to use an explicitly or implicitly identified asset that is physically distinct and the Company has the right to control the use of the identified asset for a period of time. When determining right of control, the Company evaluates whether it directs the use of the asset and obtains substantially all of the economic benefits from the use of the asset. Discount Rate The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability. In the absence of a rate of interest that is readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each lease. The IBR reflects the rate of interest that the Company would pay on the lease commencement date to borrow an amount equal to the lease payments on a collateralized basis over a similar term in similar economic environments. Firm Transportation and Storage Contracts The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers. The Company’s firm capacity contracts with third party shippers do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance. Gas Leases The authoritative guidance does not apply to leases to explore for or use natural gas resources, including the right to explore for those resources and rights to use the land in which those resources are contained. As such, the Company has concluded that its gas exploration and production leases and gas storage leases are not leases under the authoritative guidance. Amounts Recognized in the Financial Statements Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of oil and natural gas properties under the full cost method of accounting as well as certain equipment leases related to construction projects, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the Company’s total operating lease costs (in thousands): Year Ended September 30 2023 2022 Operating Lease Expense $ 7,484 $ 4,909 Variable Lease Expense(1) 507 462 Short-Term Lease Expense(2) 1,694 461 Sublease Income — (166) Total Lease Expense $ 9,685 $ 5,666 Lease Costs Recorded to Property, Plant and Equipment(3) $ 24,018 $ 19,839 (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 6.1 years and 6.0 years as of September 30, 2023 and 2022, respectively. The weighted average discount rate was 5.48% and 3.92% as of September 30, 2023 and 2022, 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. The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands): Year Ended September 30 2023 2022 Assets: Deferred Charges $ 39,664 $ 37,120 Liabilities: Other Accruals and Current Liabilities $ 9,969 $ 14,239 Other Liabilities $ 29,510 $ 22,881 Cash paid for lease liabilities, reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $9.7 million and $5.7 million for the years ended September 30, 2023 and 2022, respectively. The Company did not record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2023 or 2022. The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2023 (in thousands): At September 30, 2023 2024 $ 10,187 2025 8,791 2026 6,557 2027 5,809 2028 5,195 Thereafter 9,971 Total Lease Payments 46,510 Less: Interest (7,031) Total Lease Liability $ 39,479 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Sep. 30, 2023 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | 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 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. The following is a reconciliation of the change in the Company’s asset retirement obligations: Year Ended September 30 2023 2022 2021 (Thousands) Balance at Beginning of Year $ 161,545 $ 209,639 $ 192,228 Liabilities Incurred 3,313 2,401 7,035 Revisions of Estimates 6,728 10,700 14,509 Liabilities Settled (14,448) (71,171) (14,270) Accretion Expense 8,354 9,976 10,137 Balance at End of Year $ 165,492 $ 161,545 $ 209,639 |
Regulatory Matters
Regulatory Matters | 12 Months Ended |
Sep. 30, 2023 | |
Regulatory Assets and Liabilities, Other Disclosure [Abstract] | |
Regulatory Matters | Regulatory Matters Regulatory Assets and Liabilities The Company has recorded the following regulatory assets and liabilities: At September 30 2023 2022 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note K) $ 20,459 $ 11,677 Post-Retirement Benefit Costs(2) (Note K) 2,536 6,814 Recoverable Future Taxes (Note G) 69,045 106,247 Environmental Site Remediation Costs(2) (Note L) — 3,646 Asset Retirement Obligations(2) (Note E) 19,384 18,517 Unamortized Debt Expense (Note A) 7,240 8,884 Other(3) 66,132 47,805 Total Regulatory Assets 184,796 203,590 Less: Amounts Included in Other Current Assets (36,373) (21,358) Total Long-Term Regulatory Assets $ 148,423 $ 182,232 At September 30 2023 2022 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 277,694 $ 259,947 Taxes Refundable to Customers (Note G) 268,562 362,098 Post-Retirement Benefit Costs(5) (Note K) 159,760 167,305 Pension Costs(4) (Note K) — 8,242 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 59,019 419 Environmental Site Remediation Costs(4) (Note L) 619 — Other(6) 43,167 44,549 Total Regulatory Liabilities 808,821 842,560 Less: Amounts included in Current and Accrued Liabilities (97,124) (31,712) Total Long-Term Regulatory Liabilities $ 711,697 $ 810,848 (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) $36,373 and $21,358 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $29,759 and $26,447 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2023 and 2022, since such amounts are expected to be passed back to ratepayers in the next 12 months. $153,960 and $161,505 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively. (6) $32,305 and $25,493 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,862 and $19,056 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, 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 ("2017 Rate Order"). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the Climate Leadership and Community Protection Act. The 2017 Rate Order authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company’s future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a temporary pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. With the implementation of this surcredit, Distribution Corporation ceased funding the Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new base delivery rates. On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024. The 2023 Rate Filing proposes to stop accruing and collecting revenues under its current system modernization and system improvement trackers and shift those revenues into the Company’s new base delivery rates. In the absence of a multi-year rate plan settlement, the Company is requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization tracker. Pennsylvania Jurisdiction Distribution Corporation’s delivery rates effective through July 31, 2023 in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023. Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction. FERC Jurisdiction Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023. Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025. |
Income Taxes
Income Taxes | 12 Months Ended |
Sep. 30, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The components of federal and state income taxes included in the Consolidated Statements of Income are as follows: Year Ended September 30 2023 2022 2021 (Thousands) Current Income Taxes — Federal $ 11,744 $ — $ (10) State 1,386 12,214 8,699 Deferred Income Taxes — Federal 106,801 137,025 90,970 State 44,602 (32,610) 15,023 Total Income Taxes $ 164,533 $ 116,629 $ 114,682 On July 8, 2022, House Bill 1342 was signed into law in Pennsylvania. The law reduces the corporate income tax rate to 8.99% for fiscal 2024. Starting with fiscal 2025, the rate is reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During fiscal 2022, the Company's deferred income taxes were initially re-measured based upon the new tax rates. For the Company's non-rate regulated activities, the change in deferred income taxes was $28.4 million as of the enactment date and was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $37.2 million was recorded as a decrease to Recoverable Future Taxes of $19.8 million and an increase to Taxes Refundable to Customers of $17.4 million during the quarter ended September 30, 2022. As the rate reduction occurs through fiscal 2032, an annual re-measurement will be made. This amount is reflected in State Income Taxes. On August 16, 2022, the "Inflation Reduction Act" (IRA) was signed into law. The IRA, among other things, includes provisions to expand energy incentives and impose a corporate minimum tax. The provisions of the IRA did not have a material impact on the accompanying financial statements, although some of the provisions may be applicable in future years. Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference: Year Ended September 30 2023 2022 2021 (Thousands) U.S. Income Before Income Taxes $ 641,399 $ 682,650 $ 478,329 Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21% $ 134,694 $ 143,357 $ 100,449 State Valuation Allowance (1) — (24,850) (5,560) State Income Taxes (2) 36,331 8,736 24,300 Amortization of Excess Deferred Federal Income Taxes (6,053) (5,184) (5,215) Plant Flow Through Items (2,856) (814) (1,503) Stock Compensation 957 820 2,239 Federal Tax Credits (6) (5,701) (310) Miscellaneous 1,466 265 282 Total Income Taxes $ 164,533 $ 116,629 $ 114,682 (1) During fiscal 2022, the valuation allowance recorded against certain state deferred tax assets was removed. See discussion below. (2) The state income tax expense shown above includes adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes, including the Pennsylvania rate change discussed above. Significant components of the Company’s deferred tax liabilities and assets were as follows: At September 30 2023 2022 (Thousands) Deferred Tax Liabilities: Unrealized Hedging Gains $ 3,385 $ — Property, Plant and Equipment 1,178,893 954,757 Pension and Other Post-Retirement Benefit Costs 44,358 30,132 Other 21,470 48,893 Total Deferred Tax Liabilities 1,248,106 1,033,782 Deferred Tax Assets: Unrealized Hedging Losses — (215,187) Tax Loss and Credit Carryforwards (33,744) (50,686) Pension and Other Post-Retirement Benefit Costs (41,843) (37,250) Other (48,349) (32,430) Total Deferred Tax Assets (123,936) (335,553) Total Net Deferred Income Taxes $ 1,124,170 $ 698,229 The following is a summary of changes in valuation allowances for deferred tax assets: Year Ended September 30 2023 2022 2021 (Thousands) Balance at Beginning of Year $ — $ 57,645 $ 63,205 Additions — — — Deductions — 57,645 5,560 Balance at End of Year $ — $ — $ 57,645 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. On June 30, 2022, the Company completed the sale of Seneca's California oil and gas assets to Sentinel Peak Resources California, LLC. As a result of the sale of the California oil and gas assets, the remaining deferred tax assets and valuation allowance of approximately $27.2 million related to the California net operating loss and tax credit carryforwards were written off, as the Company determined that there was a remote possibility for use as the Company no longer has California operations. During the quarter ended September 30, 2022, the valuation allowance was adjusted because of the Pennsylvania corporate income tax rate change remeasurement described above and for current activity, for a cumulative adjustment of $5.5 million. In addition, the Company determined there was sufficient positive evidence, despite a prior history of subsidiary tax losses, to conclude that it was more likely than not that the remaining state deferred tax assets would be realized. The conclusion was primarily related to the use of net operating losses in Pennsylvania in 2022 due to sustained strong operating results as well as the expectation for future forecasted earnings in Pennsylvania. The sale of California assets also resulted in higher apportionment of income to Pennsylvania on a prospective basis, which further supported realization of existing Pennsylvania net operating loss deferred tax assets. Accordingly, as of September 30, 2022, the Company reversed the remaining valuation allowance and recognized an income tax benefit of approximately $24.9 million. Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $268.6 million and $362.1 million at September 30, 2023 and 2022, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amounted to $69.0 million and $106.2 million at September 30, 2023 and 2022, respectively. The primary change in these was due to Distribution Corporation's rate settlement in Pennsylvania. For further discussion of Distribution Corporation rate matters, refer to Note F — Regulatory Matters. The Company is in the Compliance Maintenance Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2023. The CAP program is intended for taxpayers with a low risk of non-compliance who are cooperative and transparent with few, if any, material issues that require resolution. The federal statute of limitations remains open for fiscal 2020 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries have state statutes of limitations that generally expire between three to four years from the date of filing of the income tax return. Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which time the statute of limitation begins. The Company has no unrecognized tax benefits as of September 30, 2023, 2022, or 2021. During fiscal 2009, preliminary consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property, subject to final guidance. The IRS released guidance on April 14, 2023, providing a natural gas transmission and distribution property safe harbor method of accounting (“NGSH method”) that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized or be allowable as deductions for repairs. The Company is planning to elect this change in tax accounting method with its consolidated tax return filing in the upcoming year and has reflected an estimate in the September 30, 2023 financial statements of what is intended to be treated as a repair for tax purposes rather than being capitalized. That estimate, which amounted to $99.5 million, has been recorded in Income Tax Expense. Tax carryforwards available, prior to valuation allowance, at September 30, 2023, were as follows: Jurisdiction Tax Attribute Amount Expires Pennsylvania Net Operating Loss $ 404,403 2031-2043 Federal General Business Credits $ 1,819 2042 |
Capitalization and Short-Term B
Capitalization and Short-Term Borrowings | 12 Months Ended |
Sep. 30, 2023 | |
Capitalization, Long-Term Debt and Equity [Abstract] | |
Capitalization and Short-Term Borrowings | Capitalization and Short-Term Borrowings Summary of Changes in Common Stock Equity Common Stock Paid In Earnings Accumulated Shares Amount (Thousands, except per share amounts) 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 (625,733) Net Income Available for Common Stock 476,866 Dividends Declared on Common Stock ($1.94 Per Share) (178,095) Other Comprehensive Income, Net of Tax 570,673 Share-Based Payment Expense(1) 18,746 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 341 341 (5,051) Balance at September 30, 2023 91,819 $ 91,819 $ 1,040,761 $ 1,885,856 (2) $ (55,060) (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, 2023, $1.7 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 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 2023, 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 2023, the Company issued 12,055 original issue shares of common stock as a result of SARs exercises, 119,147 original issue shares of common stock for restricted stock units that vested and 278,687 original issue shares of common stock for performance shares that vested. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During 2023, 103,059 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers (the "DCP"), as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 31,715 original issue shares of common stock during 2023. In addition, the Company issued 2,796 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment features of the Company's DCP during 2023. Stock Award Plans 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, 2023, 2022 and 2021 was approximately $18.6 million, $17.6 million and $15.2 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, 2023, 2022 and 2021 was approximately $2.4 million, $2.5 million and $2.4 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million was capitalized under these rules during each of the years ended September 30, 2023, 2022 and 2021. The tax benefit related to stock-based compensation exercises and vestings was $1.2 million for the year ended September 30, 2023. Pursuant to registration statements for these plans, there were 1,510,900 shares available for future grant at September 30, 2023. These shares include shares available for future options, SARs, restricted stock and performance share grants. SARs Transactions for 2023 involving SARs for all plans are summarized as follows: Number of Weighted Aggregate Outstanding at September 30, 2022 72,008 $ 53.05 Granted in 2023 — $ — Exercised in 2023 (72,008) $ 53.05 Forfeited in 2023 — $ — Expired in 2023 — $ — Outstanding at September 30, 2023 — $ — $ — SARs exercisable at September 30, 2023 — $ — $ — The Company did not grant any SARs during the years ended September 30, 2022 and 2021. The Company’s SARs included both performance-based and nonperformance-based SARs, but the performance conditions associated with the performance-based SARs at the time of grant were all subsequently met. The SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for SARs is the same as the accounting for stock options. The total intrinsic value of SARs exercised during the years ended September 30, 2023 and 2022 totaled approximately $0.8 million and $2.0 million, respectively. During the year ended September 30, 2021, no SARs were exercised. There were no SARs that became fully vested during the years ended September 30, 2023, 2022 and 2021. The SARs that were outstanding at September 30, 2022 had been fully vested since fiscal 2017. Restricted Stock Units Transactions for 2023 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2022 347,427 $ 44.58 Granted in 2023 133,173 $ 58.10 Vested in 2023 (119,147) $ 44.82 Forfeited in 2023 (19,267) $ 46.88 Outstanding at September 30, 2023 342,186 $ 49.63 The Company also granted 128,950 and 172,513 nonperformance-based restricted stock units during the years ended September 30, 2022 and 2021, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2022 and 2021 was $54.10 per share and $37.98 per share, respectively. As of September 30, 2023, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $7.5 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, 2023 will lapse as follows: 2024 — 115,652 units; 2025 — 98,343 units; 2026 — 79,021 units; 2027 — 33,527 units; and 2028 — 15,643 units. Performance Shares Transactions for 2023 involving performance shares for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2022 607,179 $ 48.60 Granted in 2023 202,259 $ 64.28 Vested in 2023 (278,687) $ 42.58 Forfeited in 2023 (22,805) $ 57.20 Change in Units Based on Performance Achieved 78,845 $ 40.69 Outstanding at September 30, 2023 586,791 $ 55.46 The Company also granted 195,397 and 309,470 performance shares during the years ended September 30, 2022 and 2021, respectively. The weighted average grant date fair value of such performance shares granted in 2022 and 2021 was $65.39 per share and $39.19 per share, respectively. As of September 30, 2023, unrecognized compensation expense related to performance shares totaled approximately $12.8 million, which will be recognized over a weighted average period of 1.7 years. Vesting restrictions for the outstanding performance shares at September 30, 2023 will lapse as follows: 2024 — 214,158 shares; 2025 — 179,320 shares; and 2026 — 193,313 shares. The performance shares granted during the years ended September 30, 2023, 2022 and 2021 include awards that must meet a performance goal related to either relative return on capital over a three-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year performance cycle ("TSR performance shares"). The performance goal over the respective performance cycles for the ROC performance shares granted during 2023, 2022 and 2021 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of the ROC performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The performance goal over the respective performance cycles for the ESG performance shares granted during 2023 and 2022 consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards the Company's 2030 goals. The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these ESG performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. There were no ESG performance shares granted in 2021. The performance goal over the respective performance cycles for the TSR performance shares granted during 2023, 2022 and 2021 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The 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 2023 2022 2021 Risk-Free Interest Rate 4.03 % 0.85 % 0.19 % Remaining Term at Date of Grant (Years) 2.80 2.80 2.80 Expected Volatility 31.6 % 29.7 % 29.1 % Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2023, 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 2023 2022 (Thousands) Medium-Term Notes(1): 7.4% due June 2025 $ 50,000 $ 99,000 Notes(1)(2)(3): 2.95% to 5.50% due July 2025 to March 2031 2,350,000 2,550,000 Total Long-Term Debt 2,400,000 2,649,000 Less Unamortized Discount and Debt Issuance Costs 15,515 16,591 Less Current Portion(4) — 549,000 $ 2,384,485 $ 2,083,409 (1) The Medium-Term Notes and Notes are unsecured. (2) The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. (3) The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes, $500.0 million of 2.95% notes and $300.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes 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) None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed $150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed below. In March 2023, the Company redeemed the remaining $350.0 million of the 3.75% notes as well as the $49.0 million of 7.395% notes. On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement, discussed below. On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. 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. As of September 30, 2023, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2024, $500.0 million in 2025, $500.0 million in 2026, $600.0 million in 2027, $300.0 million in 2028, and $500.0 million thereafter. 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 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. 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, 2023, the Company had outstanding commercial paper of $287.5 million with a weighted average interest rate on the commercial paper of 6.13%. The Company did not have any outstanding short-term notes payable to banks at September 30, 2023. At September 30, 2022, the Company had outstanding short-term notes payable to banks of $60.0 million, all of which was issued under the Credit Agreement, with an interest rate of 4.02%. The Company did not have any outstanding commercial paper at September 30, 2022. Debt Restrictions The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $3.17 billion in short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65. 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 contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on 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, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.43 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term debt (as of September 30, 2023) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. 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. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Sep. 30, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 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, 2023 and 2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At Fair Value as of September 30, 2023 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 39,332 $ — $ — $ — $ 39,332 Derivative Financial Instruments: Over the Counter Swaps — Gas — 65,800 — (37,508) 28,292 Over the Counter No Cost Collars — Gas — 30,966 — (14,745) 16,221 Contingent Consideration for Asset Sale — 7,277 — — 7,277 Foreign Currency Contracts — 150 — (1,453) (1,303) Other Investments: Balanced Equity Mutual Fund 15,837 — — — 15,837 Fixed Income Mutual Fund 15,897 — — — 15,897 Total $ 71,066 $ 104,193 $ — $ (53,706) $ 121,553 Liabilities: Derivative Financial Instruments: Over the Counter Swaps — Gas $ — $ 68,311 $ — $ (37,508) $ 30,803 Over the Counter No Cost Collars — Gas — 14,950 — (14,745) 205 Foreign Currency Contracts — 1,454 — (1,453) 1 Total $ — $ 84,715 $ — $ (53,706) $ 31,009 Total Net Assets/(Liabilities) $ 71,066 $ 19,478 $ — $ — $ 90,544 At Fair Value as of September 30, 2022 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting 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) (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. Derivative Financial Instruments At September 30, 2023, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company's Exploration and Production segment. Hedging collateral deposits of $91.7 million at September 30, 2022, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2023, 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, 2023 and September 30, 2022 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note B — Asset Acquisitions and Divestitures and at Note J — Financial Instruments. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk. For the years ended September 30, 2023 and 2022, there were no assets or liabilities measured at fair value and classified as Level 3. |
Financial Instruments
Financial Instruments | 12 Months Ended |
Sep. 30, 2023 | |
Financial Instruments, Owned, at Fair Value, by Type, Alternative [Abstract] | |
Financial Instruments | 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 2023 Carrying Amount 2023 Fair Value 2022 Carrying Amount 2022 Fair Value (Thousands) Long-Term Debt $ 2,384,485 $ 2,210,478 $ 2,632,409 $ 2,453,209 The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated 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 2023 2022 (Thousands) Life Insurance Contracts $ 42,242 $ 42,171 Equity Mutual Fund 15,837 19,506 Fixed Income Mutual Fund 15,897 33,348 $ 73,976 $ 95,025 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 collar and swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 7 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 $7.3 million and $8.2 million at September 30, 2023 and September 30, 2022, respectively. A $0.9 million mark-to-market adjustment was recorded during the year ended September 30, 2023. The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2023 and September 30, 2022. 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, 2023, the Company had 411.3 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding. As of September 30, 2023, the Company was hedging a total of $56.9 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts. As of September 30, 2023, the Company had $4.6 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $11.5 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The remaining unrealized losses will be being reclassified into the Consolidated Statement of Income in subsequent periods. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2023 and 2022 (Dollar Amounts in Thousands) Derivatives in Cash Amount of Location of Amount of 2023 2022 2023 2022 Commodity Contracts $ 708,234 $ (1,048,200) Operating Revenue $ (88,015) $ (882,594) (1) Foreign Currency Contracts (28) (2,631) Operating Revenue (641) 13 Total $ 708,206 $ (1,050,831) $ (88,656) $ (882,581) (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 eleven are in a net gain position. On average, the Company had $3.9 million of credit exposure per counterparty in a gain position at September 30, 2023. The maximum credit exposure per counterparty in a gain position at September 30, 2023 was $16.1 million. As of September 30, 2023, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral. As of September 30, 2023, sixteen of the nineteen counterparties to the Company’s outstanding derivative financial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable 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, 2023, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $7.7 million according to the Company's internal model (discussed in Note I — Fair Value Measurements) and no hedging collateral deposits were required to be posted by the Company at September 30, 2023. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits. 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. |
Retirement Plan and Other Post-
Retirement Plan and Other Post-Retirement Benefits | 12 Months Ended |
Sep. 30, 2023 | |
Retirement Benefits [Abstract] | |
Retirement Plan and Other Post-Retirement Benefits | 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 $5.7 million, $5.3 million and $4.8 million for the years ended September 30, 2023, 2022 and 2021, 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 $8.2 million, $7.8 million and $7.2 million for the years ended September 30, 2023, 2022 and 2021, respectively. The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003. The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations. The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other post-retirement benefit assets (i.e. the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date. 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) Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2023 2022 2021 2023 2022 2021 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 813,828 $ 1,098,456 $ 1,139,105 $ 299,283 $ 431,213 $ 476,722 Service Cost 5,187 8,758 9,865 587 1,328 1,602 Interest Cost 42,516 22,827 21,686 15,648 9,066 9,303 Plan Participants’ Contributions — — — 3,297 3,271 3,216 Retiree Drug Subsidy Receipts — — — 2,969 312 1,244 Actuarial Gain (27,313) (251,173) (8,141) (20,789) (120,276) (34,729) Benefits Paid (65,468) (65,040) (64,059) (26,717) (25,631) (26,145) Benefit Obligation at End of Period $ 768,750 $ 813,828 $ 1,098,456 $ 274,278 $ 299,283 $ 431,213 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 845,205 $ 1,095,729 $ 1,016,796 $ 461,438 $ 575,565 $ 547,885 Actual Return on Plan Assets 4,975 (205,884) 122,992 17,449 (94,849) 47,541 Employer Contributions — 20,400 20,000 235 3,082 3,068 Plan Participants’ Contributions — — — 3,297 3,271 3,216 Benefits Paid (65,468) (65,040) (64,059) (26,717) (25,631) (26,145) Fair Value of Assets at End of Period $ 784,712 $ 845,205 $ 1,095,729 $ 455,702 $ 461,438 $ 575,565 Net Amount Recognized at End of Period (Funded Status) $ 15,962 $ 31,377 $ (2,727) $ 181,424 $ 162,155 $ 144,352 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ — $ — $ (2,727) $ (2,915) $ (3,065) $ (4,799) Non-Current Assets 15,962 31,377 — 184,339 165,220 149,151 Net Amount Recognized at End of Period $ 15,962 $ 31,377 $ (2,727) $ 181,424 $ 162,155 $ 144,352 Accumulated Benefit Obligation $ 751,912 $ 793,555 $ 1,060,659 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 5.99 % 5.57 % 2.75 % 5.99 % 5.56 % 2.76 % Rate of Compensation Increase 4.60 % 4.60 % 4.70 % 4.60 % 4.60 % 4.70 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2023 2022 2021 2023 2022 2021 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 5,187 $ 8,758 $ 9,865 $ 587 $ 1,328 $ 1,602 Interest Cost 42,516 22,827 21,686 15,648 9,066 9,303 Expected Return on Plan Assets (66,593) (52,294) (58,148) (25,612) (29,359) (28,964) Amortization of Prior Service Cost (Credit) 436 537 631 (429) (429) (429) Recognition of Actuarial (Gain) Loss(1) (7,680) 26,405 36,814 (8,755) (7,610) 849 Net Amortization and Deferral for Regulatory Purposes 21,512 16,854 14,063 15,157 21,340 28,010 Net Periodic Benefit Cost (Income) $ (4,622) $ 23,087 $ 24,911 $ (3,404) $ (5,664) $ 10,371 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 5.57 % 2.75 % 2.66 % 5.56 % 2.76 % 2.71 % Effective Rate for Interest on Benefit Obligations 5.45 % 2.14 % 1.96 % 5.45 % 2.17 % 2.01 % Effective Discount Rate for Service Cost 5.49 % 2.95 % 3.01 % 5.35 % 3.00 % 3.20 % Effective Rate for Interest on Service Cost 5.53 % 2.70 % 2.60 % 5.47 % 2.93 % 2.98 % Expected Return on Plan Assets 6.90 % 5.20 % 6.00 % 5.70 % 5.20 % 5.40 % Rate of Compensation Increase 4.60 % 4.70 % 4.70 % 4.60 % 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 million and $8.3 million in 2023, 2022 and 2021, 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 $58.5 million, $64.9 million and $76.9 million at September 30, 2023, 2022 and 2021, respectively. The projected benefit obligations for the plans were $69.5 million, $77.2 million and $95.8 million at September 30, 2023, 2022 and 2021, respectively. At September 30, 2023, $13.1 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $56.4 million is recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2022, $17.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $59.7 million was 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. The weighted average discount rates for these plans were 5.91%, 5.49% and 2.15% as of September 30, 2023, 2022 and 2021, respectively and the weighted average rate of compensation increase for these plans was 8.00% as of September 30, 2023, 2022 and 2021. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2023, as well as the changes in such amounts during 2023, are presented in the table below: Retirement Other Non-Qualified (Thousands) Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) Net Actuarial Gain (Loss) $ (128,118) $ 18,440 $ (17,286) Prior Service (Cost) Credit (2,036) 1,115 — Net Amount Recognized $ (130,154) $ 19,555 $ (17,286) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2023(1) Increase in Actuarial Gain (Loss), excluding amortization(2) $ (34,305) $ 12,626 $ (2,139) Change due to Amortization of Actuarial (Gain) Loss (7,680) (8,755) 3,572 Prior Service (Cost) Credit 436 (429) — Net Change $ (41,549) $ 3,442 $ 1,433 (1) Amounts presented are shown before recognizing deferred taxes. (2) Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial Loss amounts presented in the Change in Benefit Obligation. In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2023, the Company recorded a $28.7 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $8.0 million (pre-tax) decrease to Accumulated Other Comprehensive Income. The effect of the discount rate change for the Retirement Plan in 2023 was to decrease the projected benefit obligation of the Retirement Plan by $28.4 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2023 by $0.7 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2023 by $1.8 million. The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected benefit obligation of the Retirement Plan by $262.2 million. The effect of the discount rate change for the Retirement Plan in 2021 was to decrease the projected benefit obligation of the Retirement Plan by $11.2 million. The Company did not make any cash contributions to the Retirement Plan during the year ended September 30, 2023. The Company expects that the annual contribution to the Retirement Plan in 2024 will be in the range of zero to $5.0 million. 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: $67.9 million in 2024; $67.4 million in 2025; $66.9 million in 2026; $66.2 million in 2027; $65.5 million in 2028; and $310.4 million in the five years thereafter. The effect of the discount rate change in 2023 was to decrease the other post-retirement benefit obligation by $10.7 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2023 by $0.4 million. The health care cost trend rates were updated, which increased the other post-retirement benefit obligation in 2023 by $3.2 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2023 by $12.9 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience. The effect of the discount rate change in 2022 was to decrease the other post-retirement benefit obligation by $98.9 million. The mortality improvement projection scale was updated, which increased the other post-retirement benefit obligation in 2022 by $1.1 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2022 by $22.5 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience. The effect of the discount rate change in 2021 was to decrease the other post-retirement benefit obligation by $2.5 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2021 by $2.0 million. The health care cost trend rates were updated, which decreased the other post-retirement benefit obligation in 2021 by $3.7 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2021 by $26.6 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience. The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. 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 2024 $ 25,334 $ (1,787) 2025 $ 25,479 $ (1,881) 2026 $ 25,466 $ (1,969) 2027 $ 25,389 $ (2,039) 2028 $ 25,260 $ (2,091) 2029 through 2033 $ 120,390 $ (10,896) Assumed health care cost trend rates as of September 30 were: 2023 2022 2021 Rate of Medical Cost Increase for Pre Age 65 Participants 6.25 % (1) 5.30 % (2) 5.38 % (2) Rate of Medical Cost Increase for Post Age 65 Participants 5.00 % (1) 4.84 % (2) 4.84 % (2) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 6.85 % (1) 6.29 % (2) 6.53 % (2) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 5.00 % (1) 4.84 % (2) 4.84 % (2) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 6.60 % (1) 5.96 % (2) 6.15 % (2) (1) It was assumed that this rate would gradually decline to 4% by 2048. (2) It was assumed that this rate would gradually decline to 4% by 2046. The Company did not make any cash contributions to its VEBA trusts during the year ended September 30, 2023. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2023. The Company does not expect to make any contributions to its VEBA trusts in 2024. 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, 2023 and 2022, 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, 2023 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 37,611 $ 37,611 $ — $ — $ — International Equities(2) — — — — — Global Equities(3) 36,088 — — — 36,088 Domestic Fixed Income(4) 612,820 — 556,504 — 56,316 International Fixed Income(5) 7,778 — 7,778 — — Real Estate (6) 123,859 — — — 123,859 Cash Held in Collective Trust Funds 36,800 — — — 36,800 Total Retirement Plan Investments 854,956 37,611 564,282 — 253,063 401(h) Investments (73,319) (3,212) (48,184) — (21,923) Total Retirement Plan Investments (excluding 401(h) Investments) $ 781,637 $ 34,399 $ 516,098 $ — $ 231,140 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash 3,075 Total Retirement Plan Assets $ 784,712 At September 30, 2022 Total Level 1 Level 2 Level 3 Measured 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 (6) 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 (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) Real Estate consists of investments held in a collective trust fund and a real estate investment trust. (7) Reflects the authoritative guidance related to investments measured at net asset value (NAV). At September 30, 2023 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 72,285 $ — $ — $ — $ 72,285 Exchange Traded Funds — Fixed Income 289,666 289,666 — — — Cash Held in Collective Trust Funds 9,637 — — — 9,637 Total VEBA Trust Investments 371,588 289,666 — — 81,922 401(h) Investments 73,319 3,212 48,184 — 21,923 Total Investments (including 401(h) Investments) $ 444,907 $ 292,878 $ 48,184 $ — $ 103,845 Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 10,795 Total Other Post-Retirement Benefit Assets $ 455,702 At September 30, 2022 Total Level 1 Level 2 Level 3 Measured 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 (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, 2023 and September 30, 2022, 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 Real Excluding Total Balance at September 30, 2021 $ 319 $ (24) $ 295 Unrealized Gains/(Losses) 234 (18) 216 Sales (553) 42 (511) Balance at September 30, 2022 — — — Unrealized Gains/(Losses) — — — Sales — — — Balance at September 30, 2023 $ — $ — $ — Other Post-Retirement Benefit Level 3 Assets 401(h) Balance at September 30, 2021 $ 24 Unrealized Gains/(Losses) 18 Sales (42) Balance at September 30, 2022 — Unrealized Gains/(Losses) — Sales — Balance at September 30, 2023 $ — The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.40% (Retirement Plan) and 6.00% (other post-retirement benefits), effective for fiscal 2024. 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, 2023 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets. 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. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Sep. 30, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 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, 2023, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.7 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2023. The Company has recovered its environmental clean-up costs through rate recovery and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company. Northern Access Project On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project, which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. As of September 30, 2023, the Company has spent approximately $55.9 million on the project, all of which is recorded on the balance sheet. 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: $201.7 million in 2024, $91.1 million in 2025, $113.8 million in 2026, $118.3 million in 2027, $121.7 million in 2028 and $768.9 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, 2023, the future contractual commitments related to the system modernization and expansion projects are $74.9 million in 2024, $8.4 million in 2025, $7.2 million in 2026, $5.9 million in 2027, $3.3 million in 2028 and $4.7 million thereafter. 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 $279.5 million in 2024, $185.1 million in 2025, and $47.3 million in 2026. There are no contractual commitments extending beyond 2026. In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved in other regulatory and litigation matters arising in the normal course of business. These other regulatory and litigation matters may include, for example, tax, regulatory or other governmental audits, inspections, investigations, negligence claims and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on 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. |
Business Segment Information
Business Segment Information | 12 Months Ended |
Sep. 30, 2023 | |
Segment Reporting [Abstract] | |
Business Segment Information | 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. Year Ended September 30, 2023 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1)(2) $ 958,455 $ 259,646 $ 13,891 $ 941,779 $ 2,173,771 $ — $ — $ 2,173,771 Intersegment Revenues $ — $ 119,545 $ 216,426 $ 581 $ 336,552 $ — $ (336,552) $ — Interest Income $ 3,259 $ 7,052 $ 534 $ 6,296 $ 17,141 $ — $ (5,662) $ 11,479 Interest Expense $ 54,317 $ 43,499 $ 14,989 $ 34,233 $ 147,038 $ 157 $ (15,309) $ 131,886 Depreciation, Depletion and Amortization $ 241,142 $ 70,827 $ 35,725 $ 61,450 $ 409,144 $ — $ 429 $ 409,573 Income Tax Expense (Benefit) $ 87,796 $ 34,489 $ 36,128 $ 7,267 $ 165,680 $ (164) $ (983) $ 164,533 Segment Profit: Net Income (Loss) $ 232,275 $ 100,501 $ 99,724 $ 48,395 $ 480,895 $ (531) $ (3,498) $ 476,866 Expenditures for Additions to Long-Lived Assets $ 737,725 $ 141,877 $ 103,295 $ 139,922 $ 1,122,819 $ — $ 754 $ 1,123,573 At September 30, 2023 (Thousands) Segment Assets $ 2,814,218 $ 2,427,214 $ 912,923 $ 2,247,743 $ 8,402,098 $ 4,795 $ (126,633) $ 8,280,260 Year Ended September 30, 2022 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1)(3) $ 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 Pipeline Gathering Utility Total All Corporate Total (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 (1) All Revenue from External Customers originated in the United States. (2) Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million of the Company's consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $14 million of the Company's consolidated revenue for the year ended September 30, 2023. (3) Revenues from three customers of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $850 million of the Company's consolidated revenue for the year ended September 30, 2022. 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 2023 2022 2021 (Thousands) Long-Lived Assets: United States $ 7,865,832 $ 7,135,131 $ 6,942,376 |
Supplementary Information for O
Supplementary Information for Oil and Gas Producing Activities | 12 Months Ended |
Sep. 30, 2023 | |
Supplementary Information for Oil and Gas Producing Activities Unaudited [Abstract] | |
Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities) | 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. 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. Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 2023 2022 (Thousands) Proved Properties(1) $ 6,555,088 $ 5,915,807 Unproved Properties 161,097 65,994 6,716,185 5,981,801 Less — Accumulated Depreciation, Depletion and Amortization 4,269,959 4,034,266 $ 2,446,226 $ 1,947,535 (1) Includes asset retirement costs of $129.2 million and $120.8 million at September 30, 2023 and 2022, 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 2028. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2026. Following is a summary of costs excluded from amortization at September 30, 2023: Total as of September 30, 2023 Year Costs Incurred 2023 2022 2021 Prior (Thousands) Acquisition Costs $ 143,860 $ 120,349 $ — $ — $ 23,511 Development Costs 17,207 8,034 3,001 3,704 2,468 Exploration Costs — — — — — Capitalized Interest 30 30 — — — $ 161,097 $ 128,413 $ 3,001 $ 3,704 $ 25,979 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2023 2022 2021 (Thousands) United States Property Acquisition Costs: Proved $ 33,190 $ 2,491 $ 1,801 Unproved 129,061 10,665 5,102 Exploration Costs(1) 10,055 9,631 15,413 Development Costs(2) 553,469 528,684 329,368 Asset Retirement Costs 8,363 9,768 20,194 $ 734,138 $ 561,239 $ 371,878 (1) Amounts for 2023, 2022 and 2021 include capitalized interest of zero, zero and $0.1 million respectively. (2) Amounts for 2023, 2022 and 2021 include capitalized interest of $0.1 million, $0.6 million and $0.4 million, respectively. For the years ended September 30, 2023, 2022 and 2021, the Company spent $342.0 million, $154.3 million and $81.2 million, respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2023 2022 2021 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of $1,957, $5,696 and $3,061, respectively)(1) $ 1,036,499 $ 1,730,723 $ 780,477 Oil, Condensate and Other Liquids 2,261 150,957 135,191 Total Operating Revenues(2) 1,038,760 1,881,680 915,668 Production/Lifting Costs 253,555 283,914 267,316 Franchise/Ad Valorem Taxes 17,532 25,112 22,128 Purchased Emission Allowance Expense — 1,305 2,940 Accretion Expense 5,673 7,530 7,743 Depreciation, Depletion and Amortization ($0.63, $0.57 and $0.54 per Mcfe of production, respectively) 235,694 202,418 177,055 Impairment of Oil and Gas Producing Properties — — 76,152 Income Tax Expense 145,574 368,925 98,593 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 380,732 $ 992,476 $ 263,741 (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 June 25, 2019. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance. The Company's Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 14 years of Petroleum Engineering experience with independent oil and gas companies, licensure as a Professional Engineer and is a member of the Society of Petroleum Engineers. The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls. All of the Company's reserve estimates are audited annually by Netherland, Sewell & Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2019 and with over 6 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2023 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. Gas MMcf U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Extensions and Discoveries 670,438 (1) — 670,438 Revisions of Previous Estimates 32,379 — 32,379 Production (372,271) (2) — (372,271) Purchases of Minerals in Place 33,876 — 33,876 September 30, 2023 4,535,084 — 4,535,084 Proved Developed Reserves: 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 September 30, 2023 3,550,034 — 3,550,034 Proved Undeveloped Reserves: September 30, 2020 551,262 — 551,262 September 30, 2021 631,970 — 631,970 September 30, 2022 858,094 — 858,094 September 30, 2023 985,050 — 985,050 (1) Extensions and discoveries include 180 Bcf (during 2021), 301 Bcf (during 2022) and 163 Bcf (during 2023), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 497 Bcf (during 2021), 537 Bcf (during 2022) and 507 Bcf (during 2023), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 218,016 MMcf (during 2021), 209,463 MMcf (during 2022) and 190,290 MMcf (during 2023), from Marcellus Shale fields. Production includes 93,253 MMcf (during 2021), 130,240 MMcf (during 2022) and 180,750 MMcf (during 2023), from Utica Shale fields. Oil Mbbl U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Revisions of Previous Estimates (4) — (4) Production (30) — (30) September 30, 2023 216 — 216 Proved Developed Reserves: September 30, 2020 12 22,088 22,100 September 30, 2021 11 20,930 20,941 September 30, 2022 250 — 250 September 30, 2023 216 — 216 Proved Undeveloped Reserves: September 30, 2020 — — — September 30, 2021 — 596 596 September 30, 2022 — — — September 30, 2023 — — — The Company’s proved undeveloped (PUD) reserves increased from 858 Bcfe at September 30, 2022 to 985 Bcfe at September 30, 2023. PUD reserves in the Utica Shale increased from 503 Bcfe at September 30, 2022 to 873 Bcfe at September 30, 2023. PUD reserves in the Marcellus Shale decreased from 355 Bcfe at September 30, 2022 to 112 Bcfe at September 30, 2023. The Company’s total PUD reserves were 21.7% of total proved reserves at September 30, 2023, up from 20.6% of total proved reserves at September 30, 2022. The Company’s 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 increase in PUD reserves in 2023 of 127 Bcfe is a result of 554 Bcfe in new PUD reserve additions, 14 Bcfe for one PUD well added back into the schedule and 23 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 402 Bcfe in PUD conversions to developed reserves (275 Bcfe from the Marcellus Shale and 127 Bcfe from the Utica Shale), and 62 Bcfe in PUD reserves removed for seven PUD locations due to schedule and pad layout changes. 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. The Company invested $342 million during the year ended September 30, 2023 to convert 402 Bcfe (440 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 47% of the net PUD reserves recorded at September 30, 2022. The Company developed 39 of 77 PUD locations in 2023. PUD expenditures in 2023 were higher than the 2022 estimate due to schedule changes and changes in service costs. The Company invested $154 million during the year ended September 30, 2022 to convert 287 Bcfe (333 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 45% of the net PUD reserves recorded at September 30, 2021. In the Appalachian region, 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. In 2024, the Company estimates that it will invest approximately $315 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 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, 45% of its beginning year PUD reserves in fiscal 2022 and 47% of its beginning year PUD reserves in fiscal 2023. At September 30, 2023, 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. Year Ended September 30 2023 2022 2021 (Thousands) United States Future Cash Inflows $ 11,947,345 $ 19,209,099 $ 10,175,182 Less: Future Production Costs 3,538,389 3,138,226 3,423,629 Future Development Costs 1,095,096 781,847 597,662 Future Income Tax Expense at Applicable Statutory Rate 1,867,457 3,876,272 1,397,175 Future Net Cash Flows 5,446,403 11,412,754 4,756,716 Less: 10% Annual Discount for Estimated Timing of Cash Flows 2,874,295 5,964,424 2,403,144 Standardized Measure of Discounted Future Net Cash Flows $ 2,572,108 $ 5,448,330 $ 2,353,572 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2023 2022 2021 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 5,448,330 $ 2,353,572 $ 1,222,470 Sales, Net of Production Costs (767,487) (1,572,402) (626,132) Net Changes in Prices, Net of Production Costs (3,918,392) 4,132,889 1,478,995 Extensions and Discoveries 237,057 1,355,257 462,040 Changes in Estimated Future Development Costs (222,233) (32,160) 48,247 Purchases of Minerals in Place 34,346 — — Sales of Minerals in Place — (311,308) — Previously Estimated Development Costs Incurred 342,024 154,253 81,239 Net Change in Income Taxes at Applicable Statutory Rate 959,728 (1,180,349) (415,993) Revisions of Previous Quantity Estimates 33,192 3,316 (52,383) Accretion of Discount and Other 425,543 545,262 155,089 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 2,572,108 $ 5,448,330 $ 2,353,572 |
Pay vs Performance Disclosure
Pay vs Performance Disclosure - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Pay vs Performance Disclosure | |||
Net Income Available for Common Stock | $ 476,866 | $ 566,021 | $ 363,647 |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Sep. 30, 2023 | |
Trading Arrangements, by Individual | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Sep. 30, 2023 | |
Accounting Policies [Abstract] | |
Principles of Consolidation | 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 | RegulationThe 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. |
Allowance for Uncollectible Accounts | Allowance for Uncollectible AccountsThe allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances have historically been written off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. During 2022 and 2021, final billings were suppressed in the Utility segment as a result of state shut-off moratoriums arising from the COVID-19 pandemic. Those moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby resulting in higher amounts being written off in 2023. |
Regulatory Mechanisms | 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 rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNC as a five-year pilot program. The program is effective October 2023 and covers the eight-month period from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNC, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues. 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 | 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. |
Property, Plant and Equipment | 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 $2.4 billion and $1.9 billion at September 30, 2023 and 2022, respectively. For further discussion of capitalized costs, refer to Note N — Supplementary Information for Oil and Gas Producing Activities. 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, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $794.7 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2023, 2022 and 2021, estimated future net cash flows were increased by $38.8 million, decreased by $1.0 billion and decreased by $76.1 million, respectively. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2023. 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 | Depreciation, Depletion and AmortizationFor oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. Depreciation, depletion and amortization expense for oil and gas properties was $235.7 million, $202.4 million and $177.1 million for the years ended September 30, 2023, 2022 and 2021, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated useful lives of property in service. |
Goodwill | Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2023 and 2022 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, 2023, 2022 and 2021, 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 | 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. |
Gas Stored Underground | 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 2023, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $3.7 million at September 30, 2023. |
Unamortized Debt Expense | Unamortized Debt Expense Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. At September 30, 2023, the remaining weighted average amortization period for such costs was approximately 4 years. |
Income Taxes | 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. |
Consolidated Statement of Cash Flows | 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. |
Customer Advances | Customer AdvancesThe 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. |
Customer Security Deposits | Customer Security DepositsThe 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. |
Earnings Per Common Share | Earnings Per Common ShareBasic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding during fiscal 2023, 2022 and/or 2021 were SARs, restricted stock units and performance shares. For the years ended September 30, 2023 and September 30, 2022, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. |
Stock-Based Compensation | 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 the date of each grant. The Company chose the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs. For all Company stock awards, forfeitures are recognized as they occur. 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 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Accounting Policies [Abstract] | |
Schedule of Allowance for Uncollectible Accounts | Activity in the allowance for uncollectible accounts are as follows: Year Ended September 30 2023 2022 2021 (Thousands) Balance at Beginning of Year $ 40,228 $ 31,639 $ 22,810 Additions Charged to Costs and Expenses 14,482 13,209 14,940 Add: Discounts on Purchased Receivables 1,380 1,314 1,168 Deduct: Net Accounts Receivable Written-Off 19,795 5,934 7,279 Balance at End of Year $ 36,295 $ 40,228 $ 31,639 |
Schedule of Depreciable Plant By Segment | The following is a summary of depreciable plant by segment: As of September 30 2023 2022 (Thousands) Exploration and Production $ 6,741,095 $ 6,088,476 Pipeline and Storage 2,803,690 2,747,948 Gathering 1,032,969 971,665 Utility 2,507,465 2,411,707 All Other and Corporate 15,787 13,712 $ 13,101,006 $ 12,233,508 |
Average Depreciation, Depletion and Amortization Rates | Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2023 2022 2021 Exploration and Production, per Mcfe(1) $ 0.65 $ 0.59 $ 0.56 Pipeline and Storage 2.6 % 2.7 % 2.6 % Gathering 3.6 % 3.6 % 3.6 % Utility 2.7 % 2.7 % 2.7 % All Other and Corporate 2.9 % 1.4 % 3.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.57 and $0.54 per Mcfe of production in 2023, 2022 and 2021, respectively. |
Components of Accumulated Other Comprehensive Income (Loss) | The components of Accumulated Other Comprehensive Loss and changes for the years ended September 30, 2023 and 2022, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Year Ended September 30, 2023 Balance at October 1, 2022 $ (572,163) $ (53,570) $ (625,733) Other Comprehensive Gains and Losses Before Reclassifications 493,936 (7,376) 486,560 Amounts Reclassified From Other Comprehensive Loss 82,850 1,263 84,113 Balance at September 30, 2023 $ 4,623 $ (59,683) $ (55,060) 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 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) |
Schedule of Reclassifications Out of Accumulated Other Comprehensive Income (Loss) | The details about the reclassification adjustments out of accumulated other comprehensive loss for the years ended September 30, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented 2023 2022 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $ (88,015) $ (882,594) Operating Revenues Foreign Currency Contracts (641) 13 Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (82) (103) (1) Net Actuarial Loss (1,592) (10,951) (1) (90,330) (893,635) Total Before Income Tax 6,217 244,133 Income Tax Expense $ (84,113) $ (649,502) 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. |
Schedule of Cash, Cash Equivalents and Restricted Cash | 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 2023 2022 2021 2020 Cash and Temporary Cash Investments $ 55,447 $ 46,048 $ 31,528 $ 20,541 Hedging Collateral Deposits — 91,670 88,610 — Cash, Cash Equivalents, and Restricted Cash $ 55,447 $ 137,718 $ 120,138 $ 20,541 |
Schedule of Other Current Assets | The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2023 2022 (Thousands) Prepayments $ 18,966 $ 17,757 Prepaid Property and Other Taxes 14,186 14,321 Federal Income Taxes Receivable 14,602 — State Income Taxes Receivable 16,133 5,933 Regulatory Assets 36,373 21,358 $ 100,260 $ 59,369 |
Schedule of Other Accruals And Current Liabilities | The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2023 2022 (Thousands) Accrued Capital Expenditures $ 43,323 $ 64,720 Regulatory Liabilities 38,105 31,293 Liability for Royalty and Working Interests 17,679 86,206 Non-Qualified Benefit Plan Liability 13,052 17,474 Other 48,815 57,634 $ 160,974 $ 257,327 |
Asset Acquisitions and Divest_2
Asset Acquisitions and Divestitures (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Asset Acquisition [Abstract] | |
Schedule of Asset Acquisition | The following is a summary of the asset acquisition in thousands: Purchase Price $ 124,178 Transaction Costs 580 Total Consideration $ 124,758 |
Revenue from Contracts with C_2
Revenue from Contracts with Customers (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2023 and 2022, presented by type of service from each reportable segment. Year Ended September 30, 2023 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 1,036,499 $ — $ — $ — $ 1,036,499 $ — $ — $ 1,036,499 Production of Crude Oil 2,261 — — — 2,261 — — 2,261 Natural Gas Processing 1,203 — — — 1,203 — — 1,203 Natural Gas Gathering Service — — 230,317 — 230,317 — (216,426) 13,891 Natural Gas Transportation Service — 291,225 — 98,304 389,529 — (82,889) 306,640 Natural Gas Storage Service — 84,962 — — 84,962 — (36,283) 48,679 Natural Gas Residential Sales — — — 727,728 727,728 — — 727,728 Natural Gas Commercial Sales — — — 103,270 103,270 — — 103,270 Natural Gas Industrial Sales — — — 5,658 5,658 — (7) 5,651 Other 6,507 3,004 — 508 10,019 — (947) 9,072 Total Revenues from Contracts with Customers 1,046,470 379,191 230,317 935,468 2,591,446 — (336,552) 2,254,894 Alternative Revenue Programs — — — 6,892 6,892 — — 6,892 Derivative Financial Instruments (88,015) — — — (88,015) — — (88,015) Total Revenues $ 958,455 $ 379,191 $ 230,317 $ 942,360 $ 2,510,323 $ — $ (336,552) $ 2,173,771 Year Ended September 30, 2022 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (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 |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Leases [Abstract] | |
Components of Operating Lease Costs | The following table summarizes the components of the Company’s total operating lease costs (in thousands): Year Ended September 30 2023 2022 Operating Lease Expense $ 7,484 $ 4,909 Variable Lease Expense(1) 507 462 Short-Term Lease Expense(2) 1,694 461 Sublease Income — (166) Total Lease Expense $ 9,685 $ 5,666 Lease Costs Recorded to Property, Plant and Equipment(3) $ 24,018 $ 19,839 (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. |
Balance Sheet Information Related to Operating Leases | The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands): Year Ended September 30 2023 2022 Assets: Deferred Charges $ 39,664 $ 37,120 Liabilities: Other Accruals and Current Liabilities $ 9,969 $ 14,239 Other Liabilities $ 29,510 $ 22,881 |
Schedule of Operating Lease Liability Maturities | The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2023 (in thousands): At September 30, 2023 2024 $ 10,187 2025 8,791 2026 6,557 2027 5,809 2028 5,195 Thereafter 9,971 Total Lease Payments 46,510 Less: Interest (7,031) Total Lease Liability $ 39,479 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in Asset Retirement Obligation | The following is a reconciliation of the change in the Company’s asset retirement obligations: Year Ended September 30 2023 2022 2021 (Thousands) Balance at Beginning of Year $ 161,545 $ 209,639 $ 192,228 Liabilities Incurred 3,313 2,401 7,035 Revisions of Estimates 6,728 10,700 14,509 Liabilities Settled (14,448) (71,171) (14,270) Accretion Expense 8,354 9,976 10,137 Balance at End of Year $ 165,492 $ 161,545 $ 209,639 |
Regulatory Matters (Tables)
Regulatory Matters (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Regulatory Assets and Liabilities, Other Disclosure [Abstract] | |
Schedule of Regulatory Assets and Liabilities | The Company has recorded the following regulatory assets and liabilities: At September 30 2023 2022 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note K) $ 20,459 $ 11,677 Post-Retirement Benefit Costs(2) (Note K) 2,536 6,814 Recoverable Future Taxes (Note G) 69,045 106,247 Environmental Site Remediation Costs(2) (Note L) — 3,646 Asset Retirement Obligations(2) (Note E) 19,384 18,517 Unamortized Debt Expense (Note A) 7,240 8,884 Other(3) 66,132 47,805 Total Regulatory Assets 184,796 203,590 Less: Amounts Included in Other Current Assets (36,373) (21,358) Total Long-Term Regulatory Assets $ 148,423 $ 182,232 At September 30 2023 2022 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 277,694 $ 259,947 Taxes Refundable to Customers (Note G) 268,562 362,098 Post-Retirement Benefit Costs(5) (Note K) 159,760 167,305 Pension Costs(4) (Note K) — 8,242 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 59,019 419 Environmental Site Remediation Costs(4) (Note L) 619 — Other(6) 43,167 44,549 Total Regulatory Liabilities 808,821 842,560 Less: Amounts included in Current and Accrued Liabilities (97,124) (31,712) Total Long-Term Regulatory Liabilities $ 711,697 $ 810,848 (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) $36,373 and $21,358 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $29,759 and $26,447 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2023 and 2022, since such amounts are expected to be passed back to ratepayers in the next 12 months. $153,960 and $161,505 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively. (6) $32,305 and $25,493 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,862 and $19,056 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Income Tax Disclosure [Abstract] | |
Components of Federal and State Income Taxes Included in the Consolidated Statements of Income | The components of federal and state income taxes included in the Consolidated Statements of Income are as follows: Year Ended September 30 2023 2022 2021 (Thousands) Current Income Taxes — Federal $ 11,744 $ — $ (10) State 1,386 12,214 8,699 Deferred Income Taxes — Federal 106,801 137,025 90,970 State 44,602 (32,610) 15,023 Total Income Taxes $ 164,533 $ 116,629 $ 114,682 |
Schedule of Income Tax Reconciliation by Applying Federal Income Tax Rate | The following is a reconciliation of this difference: Year Ended September 30 2023 2022 2021 (Thousands) U.S. Income Before Income Taxes $ 641,399 $ 682,650 $ 478,329 Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21% $ 134,694 $ 143,357 $ 100,449 State Valuation Allowance (1) — (24,850) (5,560) State Income Taxes (2) 36,331 8,736 24,300 Amortization of Excess Deferred Federal Income Taxes (6,053) (5,184) (5,215) Plant Flow Through Items (2,856) (814) (1,503) Stock Compensation 957 820 2,239 Federal Tax Credits (6) (5,701) (310) Miscellaneous 1,466 265 282 Total Income Taxes $ 164,533 $ 116,629 $ 114,682 (1) During fiscal 2022, the valuation allowance recorded against certain state deferred tax assets was removed. See discussion below. (2) The state income tax expense shown above includes adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes, including the Pennsylvania rate change discussed above. |
Significant Components of Deferred Tax Liabilities and Assets | Significant components of the Company’s deferred tax liabilities and assets were as follows: At September 30 2023 2022 (Thousands) Deferred Tax Liabilities: Unrealized Hedging Gains $ 3,385 $ — Property, Plant and Equipment 1,178,893 954,757 Pension and Other Post-Retirement Benefit Costs 44,358 30,132 Other 21,470 48,893 Total Deferred Tax Liabilities 1,248,106 1,033,782 Deferred Tax Assets: Unrealized Hedging Losses — (215,187) Tax Loss and Credit Carryforwards (33,744) (50,686) Pension and Other Post-Retirement Benefit Costs (41,843) (37,250) Other (48,349) (32,430) Total Deferred Tax Assets (123,936) (335,553) Total Net Deferred Income Taxes $ 1,124,170 $ 698,229 |
Summary of Changes in Valuation Allowances for Deferred Tax Assets | The following is a summary of changes in valuation allowances for deferred tax assets: Year Ended September 30 2023 2022 2021 (Thousands) Balance at Beginning of Year $ — $ 57,645 $ 63,205 Additions — — — Deductions — 57,645 5,560 Balance at End of Year $ — $ — $ 57,645 |
Summary of Operating Loss and Tax Credit Carryforwards | Tax carryforwards available, prior to valuation allowance, at September 30, 2023, were as follows: Jurisdiction Tax Attribute Amount Expires Pennsylvania Net Operating Loss $ 404,403 2031-2043 Federal General Business Credits $ 1,819 2042 |
Capitalization and Short-Term_2
Capitalization and Short-Term Borrowings (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Capitalization, Long-Term Debt and Equity [Abstract] | |
Summary of Changes in Common Stock Equity | Summary of Changes in Common Stock Equity Common Stock Paid In Earnings Accumulated Shares Amount (Thousands, except per share amounts) 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 (625,733) Net Income Available for Common Stock 476,866 Dividends Declared on Common Stock ($1.94 Per Share) (178,095) Other Comprehensive Income, Net of Tax 570,673 Share-Based Payment Expense(1) 18,746 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 341 341 (5,051) Balance at September 30, 2023 91,819 $ 91,819 $ 1,040,761 $ 1,885,856 (2) $ (55,060) (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, 2023, $1.7 billion of accumulated earnings was free of such limitations. |
Schedule of Share-Based Compensation for SARs | Transactions for 2023 involving SARs for all plans are summarized as follows: Number of Weighted Aggregate Outstanding at September 30, 2022 72,008 $ 53.05 Granted in 2023 — $ — Exercised in 2023 (72,008) $ 53.05 Forfeited in 2023 — $ — Expired in 2023 — $ — Outstanding at September 30, 2023 — $ — $ — SARs exercisable at September 30, 2023 — $ — $ — |
Schedule of Share-Based Compensation for Non-Performance Based Restricted Stock Units | Transactions for 2023 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2022 347,427 $ 44.58 Granted in 2023 133,173 $ 58.10 Vested in 2023 (119,147) $ 44.82 Forfeited in 2023 (19,267) $ 46.88 Outstanding at September 30, 2023 342,186 $ 49.63 |
Schedule of Share-Based Compensation for Performance Shares | Transactions for 2023 involving performance shares for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2022 607,179 $ 48.60 Granted in 2023 202,259 $ 64.28 Vested in 2023 (278,687) $ 42.58 Forfeited in 2023 (22,805) $ 57.20 Change in Units Based on Performance Achieved 78,845 $ 40.69 Outstanding at September 30, 2023 586,791 $ 55.46 |
Schedule of Weighted Average Assumptions Used in Estimating Fair Value | The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant: Year Ended September 30 2023 2022 2021 Risk-Free Interest Rate 4.03 % 0.85 % 0.19 % Remaining Term at Date of Grant (Years) 2.80 2.80 2.80 Expected Volatility 31.6 % 29.7 % 29.1 % Expected Dividend Yield (Quarterly) N/A N/A N/A |
Schedule of Long-Term Debt | The outstanding long-term debt is as follows: At September 30 2023 2022 (Thousands) Medium-Term Notes(1): 7.4% due June 2025 $ 50,000 $ 99,000 Notes(1)(2)(3): 2.95% to 5.50% due July 2025 to March 2031 2,350,000 2,550,000 Total Long-Term Debt 2,400,000 2,649,000 Less Unamortized Discount and Debt Issuance Costs 15,515 16,591 Less Current Portion(4) — 549,000 $ 2,384,485 $ 2,083,409 (1) The Medium-Term Notes and Notes are unsecured. (2) The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. (3) The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes, $500.0 million of 2.95% notes and $300.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes 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) None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed $150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed below. In March 2023, the Company redeemed the remaining $350.0 million of the 3.75% notes as well as the $49.0 million of 7.395% notes. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | 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, 2023 and 2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. At Fair Value as of September 30, 2023 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 39,332 $ — $ — $ — $ 39,332 Derivative Financial Instruments: Over the Counter Swaps — Gas — 65,800 — (37,508) 28,292 Over the Counter No Cost Collars — Gas — 30,966 — (14,745) 16,221 Contingent Consideration for Asset Sale — 7,277 — — 7,277 Foreign Currency Contracts — 150 — (1,453) (1,303) Other Investments: Balanced Equity Mutual Fund 15,837 — — — 15,837 Fixed Income Mutual Fund 15,897 — — — 15,897 Total $ 71,066 $ 104,193 $ — $ (53,706) $ 121,553 Liabilities: Derivative Financial Instruments: Over the Counter Swaps — Gas $ — $ 68,311 $ — $ (37,508) $ 30,803 Over the Counter No Cost Collars — Gas — 14,950 — (14,745) 205 Foreign Currency Contracts — 1,454 — (1,453) 1 Total $ — $ 84,715 $ — $ (53,706) $ 31,009 Total Net Assets/(Liabilities) $ 71,066 $ 19,478 $ — $ — $ 90,544 At Fair Value as of September 30, 2022 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting 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) |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Financial Instruments, Owned, at Fair Value, by Type, Alternative [Abstract] | |
Schedule of Long-Term Debt | Based on these criteria, the fair market value of long-term debt, including current portion, was as follows: At September 30 2023 Carrying Amount 2023 Fair Value 2022 Carrying Amount 2022 Fair Value (Thousands) Long-Term Debt $ 2,384,485 $ 2,210,478 $ 2,632,409 $ 2,453,209 |
Schedule of Other Investments | The components of the Company's Other Investments are as follows (in thousands): At September 30 2023 2022 (Thousands) Life Insurance Contracts $ 42,242 $ 42,171 Equity Mutual Fund 15,837 19,506 Fixed Income Mutual Fund 15,897 33,348 $ 73,976 $ 95,025 |
Schedule of Derivative Financial Instruments Designated and Qualifying as Cash Flow Hedges on the Statements of Financial Performance | The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2023 and 2022 (Dollar Amounts in Thousands) Derivatives in Cash Amount of Location of Amount of 2023 2022 2023 2022 Commodity Contracts $ 708,234 $ (1,048,200) Operating Revenue $ (88,015) $ (882,594) (1) Foreign Currency Contracts (28) (2,631) Operating Revenue (641) 13 Total $ 708,206 $ (1,050,831) $ (88,656) $ (882,581) (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. |
Retirement Plan and Other Pos_2
Retirement Plan and Other Post-Retirement Benefits (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Retirement Benefits [Abstract] | |
Schedule of Benefit Obligations, Plan Assets and Funded Status | 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) Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2023 2022 2021 2023 2022 2021 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 813,828 $ 1,098,456 $ 1,139,105 $ 299,283 $ 431,213 $ 476,722 Service Cost 5,187 8,758 9,865 587 1,328 1,602 Interest Cost 42,516 22,827 21,686 15,648 9,066 9,303 Plan Participants’ Contributions — — — 3,297 3,271 3,216 Retiree Drug Subsidy Receipts — — — 2,969 312 1,244 Actuarial Gain (27,313) (251,173) (8,141) (20,789) (120,276) (34,729) Benefits Paid (65,468) (65,040) (64,059) (26,717) (25,631) (26,145) Benefit Obligation at End of Period $ 768,750 $ 813,828 $ 1,098,456 $ 274,278 $ 299,283 $ 431,213 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 845,205 $ 1,095,729 $ 1,016,796 $ 461,438 $ 575,565 $ 547,885 Actual Return on Plan Assets 4,975 (205,884) 122,992 17,449 (94,849) 47,541 Employer Contributions — 20,400 20,000 235 3,082 3,068 Plan Participants’ Contributions — — — 3,297 3,271 3,216 Benefits Paid (65,468) (65,040) (64,059) (26,717) (25,631) (26,145) Fair Value of Assets at End of Period $ 784,712 $ 845,205 $ 1,095,729 $ 455,702 $ 461,438 $ 575,565 Net Amount Recognized at End of Period (Funded Status) $ 15,962 $ 31,377 $ (2,727) $ 181,424 $ 162,155 $ 144,352 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ — $ — $ (2,727) $ (2,915) $ (3,065) $ (4,799) Non-Current Assets 15,962 31,377 — 184,339 165,220 149,151 Net Amount Recognized at End of Period $ 15,962 $ 31,377 $ (2,727) $ 181,424 $ 162,155 $ 144,352 Accumulated Benefit Obligation $ 751,912 $ 793,555 $ 1,060,659 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 5.99 % 5.57 % 2.75 % 5.99 % 5.56 % 2.76 % Rate of Compensation Increase 4.60 % 4.60 % 4.70 % 4.60 % 4.60 % 4.70 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2023 2022 2021 2023 2022 2021 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 5,187 $ 8,758 $ 9,865 $ 587 $ 1,328 $ 1,602 Interest Cost 42,516 22,827 21,686 15,648 9,066 9,303 Expected Return on Plan Assets (66,593) (52,294) (58,148) (25,612) (29,359) (28,964) Amortization of Prior Service Cost (Credit) 436 537 631 (429) (429) (429) Recognition of Actuarial (Gain) Loss(1) (7,680) 26,405 36,814 (8,755) (7,610) 849 Net Amortization and Deferral for Regulatory Purposes 21,512 16,854 14,063 15,157 21,340 28,010 Net Periodic Benefit Cost (Income) $ (4,622) $ 23,087 $ 24,911 $ (3,404) $ (5,664) $ 10,371 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 5.57 % 2.75 % 2.66 % 5.56 % 2.76 % 2.71 % Effective Rate for Interest on Benefit Obligations 5.45 % 2.14 % 1.96 % 5.45 % 2.17 % 2.01 % Effective Discount Rate for Service Cost 5.49 % 2.95 % 3.01 % 5.35 % 3.00 % 3.20 % Effective Rate for Interest on Service Cost 5.53 % 2.70 % 2.60 % 5.47 % 2.93 % 2.98 % Expected Return on Plan Assets 6.90 % 5.20 % 6.00 % 5.70 % 5.20 % 5.40 % Rate of Compensation Increase 4.60 % 4.70 % 4.70 % 4.60 % 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. |
Schedule of Cumulative Amounts Recognized in Accumulated Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities | The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2023, as well as the changes in such amounts during 2023, are presented in the table below: Retirement Other Non-Qualified (Thousands) Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) Net Actuarial Gain (Loss) $ (128,118) $ 18,440 $ (17,286) Prior Service (Cost) Credit (2,036) 1,115 — Net Amount Recognized $ (130,154) $ 19,555 $ (17,286) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2023(1) Increase in Actuarial Gain (Loss), excluding amortization(2) $ (34,305) $ 12,626 $ (2,139) Change due to Amortization of Actuarial (Gain) Loss (7,680) (8,755) 3,572 Prior Service (Cost) Credit 436 (429) — Net Change $ (41,549) $ 3,442 $ 1,433 (1) Amounts presented are shown before recognizing deferred taxes. (2) Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial Loss amounts presented in the Change in Benefit Obligation. |
Schedule of Expected Benefit Payments | 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 2024 $ 25,334 $ (1,787) 2025 $ 25,479 $ (1,881) 2026 $ 25,466 $ (1,969) 2027 $ 25,389 $ (2,039) 2028 $ 25,260 $ (2,091) 2029 through 2033 $ 120,390 $ (10,896) |
Schedule of Health Care Cost Trend Rates | Assumed health care cost trend rates as of September 30 were: 2023 2022 2021 Rate of Medical Cost Increase for Pre Age 65 Participants 6.25 % (1) 5.30 % (2) 5.38 % (2) Rate of Medical Cost Increase for Post Age 65 Participants 5.00 % (1) 4.84 % (2) 4.84 % (2) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 6.85 % (1) 6.29 % (2) 6.53 % (2) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 5.00 % (1) 4.84 % (2) 4.84 % (2) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 6.60 % (1) 5.96 % (2) 6.15 % (2) (1) It was assumed that this rate would gradually decline to 4% by 2048. (2) It was assumed that this rate would gradually decline to 4% by 2046. |
Schedule of Fair Value of Plan Assets | Below is a listing of the major categories of plan assets held as of September 30, 2023 and 2022, 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, 2023 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 37,611 $ 37,611 $ — $ — $ — International Equities(2) — — — — — Global Equities(3) 36,088 — — — 36,088 Domestic Fixed Income(4) 612,820 — 556,504 — 56,316 International Fixed Income(5) 7,778 — 7,778 — — Real Estate (6) 123,859 — — — 123,859 Cash Held in Collective Trust Funds 36,800 — — — 36,800 Total Retirement Plan Investments 854,956 37,611 564,282 — 253,063 401(h) Investments (73,319) (3,212) (48,184) — (21,923) Total Retirement Plan Investments (excluding 401(h) Investments) $ 781,637 $ 34,399 $ 516,098 $ — $ 231,140 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash 3,075 Total Retirement Plan Assets $ 784,712 At September 30, 2022 Total Level 1 Level 2 Level 3 Measured 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 (6) 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 (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) Real Estate consists of investments held in a collective trust fund and a real estate investment trust. (7) Reflects the authoritative guidance related to investments measured at net asset value (NAV). At September 30, 2023 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 72,285 $ — $ — $ — $ 72,285 Exchange Traded Funds — Fixed Income 289,666 289,666 — — — Cash Held in Collective Trust Funds 9,637 — — — 9,637 Total VEBA Trust Investments 371,588 289,666 — — 81,922 401(h) Investments 73,319 3,212 48,184 — 21,923 Total Investments (including 401(h) Investments) $ 444,907 $ 292,878 $ 48,184 $ — $ 103,845 Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 10,795 Total Other Post-Retirement Benefit Assets $ 455,702 At September 30, 2022 Total Level 1 Level 2 Level 3 Measured 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 (1) Reflects the authoritative guidance related to investments measured at net asset value (NAV). |
Schedule of Significant Unobservable Input Changes in Plan Assets | Retirement Plan Level 3 Assets Real Excluding Total Balance at September 30, 2021 $ 319 $ (24) $ 295 Unrealized Gains/(Losses) 234 (18) 216 Sales (553) 42 (511) Balance at September 30, 2022 — — — Unrealized Gains/(Losses) — — — Sales — — — Balance at September 30, 2023 $ — $ — $ — Other Post-Retirement Benefit Level 3 Assets 401(h) Balance at September 30, 2021 $ 24 Unrealized Gains/(Losses) 18 Sales (42) Balance at September 30, 2022 — Unrealized Gains/(Losses) — Sales — Balance at September 30, 2023 $ — |
Business Segment Information (T
Business Segment Information (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Segment Reporting [Abstract] | |
Schedule of Information by Segment | Year Ended September 30, 2023 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1)(2) $ 958,455 $ 259,646 $ 13,891 $ 941,779 $ 2,173,771 $ — $ — $ 2,173,771 Intersegment Revenues $ — $ 119,545 $ 216,426 $ 581 $ 336,552 $ — $ (336,552) $ — Interest Income $ 3,259 $ 7,052 $ 534 $ 6,296 $ 17,141 $ — $ (5,662) $ 11,479 Interest Expense $ 54,317 $ 43,499 $ 14,989 $ 34,233 $ 147,038 $ 157 $ (15,309) $ 131,886 Depreciation, Depletion and Amortization $ 241,142 $ 70,827 $ 35,725 $ 61,450 $ 409,144 $ — $ 429 $ 409,573 Income Tax Expense (Benefit) $ 87,796 $ 34,489 $ 36,128 $ 7,267 $ 165,680 $ (164) $ (983) $ 164,533 Segment Profit: Net Income (Loss) $ 232,275 $ 100,501 $ 99,724 $ 48,395 $ 480,895 $ (531) $ (3,498) $ 476,866 Expenditures for Additions to Long-Lived Assets $ 737,725 $ 141,877 $ 103,295 $ 139,922 $ 1,122,819 $ — $ 754 $ 1,123,573 At September 30, 2023 (Thousands) Segment Assets $ 2,814,218 $ 2,427,214 $ 912,923 $ 2,247,743 $ 8,402,098 $ 4,795 $ (126,633) $ 8,280,260 Year Ended September 30, 2022 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1)(3) $ 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 Pipeline Gathering Utility Total All Corporate Total (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 (1) All Revenue from External Customers originated in the United States. (2) Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million of the Company's consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $14 million of the Company's consolidated revenue for the year ended September 30, 2023. (3) Revenues from three customers of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $850 million of the Company's consolidated revenue for the year ended September 30, 2022. 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. |
Schedule of Long-Lived Assets by Geographical Areas | Geographic Information At September 30 2023 2022 2021 (Thousands) Long-Lived Assets: United States $ 7,865,832 $ 7,135,131 $ 6,942,376 |
Supplementary Information for_2
Supplementary Information for Oil and Gas Producing Activities (Tables) | 12 Months Ended |
Sep. 30, 2023 | |
Supplementary Information for Oil and Gas Producing Activities Unaudited [Abstract] | |
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities | Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 2023 2022 (Thousands) Proved Properties(1) $ 6,555,088 $ 5,915,807 Unproved Properties 161,097 65,994 6,716,185 5,981,801 Less — Accumulated Depreciation, Depletion and Amortization 4,269,959 4,034,266 $ 2,446,226 $ 1,947,535 (1) Includes asset retirement costs of $129.2 million and $120.8 million at September 30, 2023 and 2022, respectively. |
Summary of Capitalized Costs of Unproved Properties Excluded from Amortization | Following is a summary of costs excluded from amortization at September 30, 2023: Total as of September 30, 2023 Year Costs Incurred 2023 2022 2021 Prior (Thousands) Acquisition Costs $ 143,860 $ 120,349 $ — $ — $ 23,511 Development Costs 17,207 8,034 3,001 3,704 2,468 Exploration Costs — — — — — Capitalized Interest 30 30 — — — $ 161,097 $ 128,413 $ 3,001 $ 3,704 $ 25,979 |
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities | Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2023 2022 2021 (Thousands) United States Property Acquisition Costs: Proved $ 33,190 $ 2,491 $ 1,801 Unproved 129,061 10,665 5,102 Exploration Costs(1) 10,055 9,631 15,413 Development Costs(2) 553,469 528,684 329,368 Asset Retirement Costs 8,363 9,768 20,194 $ 734,138 $ 561,239 $ 371,878 (1) Amounts for 2023, 2022 and 2021 include capitalized interest of zero, zero and $0.1 million respectively. (2) Amounts for 2023, 2022 and 2021 include capitalized interest of $0.1 million, $0.6 million and $0.4 million, respectively. |
Schedule of Results of Operations for Producing Activities | Results of Operations for Producing Activities Year Ended September 30 2023 2022 2021 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of $1,957, $5,696 and $3,061, respectively)(1) $ 1,036,499 $ 1,730,723 $ 780,477 Oil, Condensate and Other Liquids 2,261 150,957 135,191 Total Operating Revenues(2) 1,038,760 1,881,680 915,668 Production/Lifting Costs 253,555 283,914 267,316 Franchise/Ad Valorem Taxes 17,532 25,112 22,128 Purchased Emission Allowance Expense — 1,305 2,940 Accretion Expense 5,673 7,530 7,743 Depreciation, Depletion and Amortization ($0.63, $0.57 and $0.54 per Mcfe of production, respectively) 235,694 202,418 177,055 Impairment of Oil and Gas Producing Properties — — 76,152 Income Tax Expense 145,574 368,925 98,593 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 380,732 $ 992,476 $ 263,741 (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. |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | Gas MMcf U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Extensions and Discoveries 670,438 (1) — 670,438 Revisions of Previous Estimates 32,379 — 32,379 Production (372,271) (2) — (372,271) Purchases of Minerals in Place 33,876 — 33,876 September 30, 2023 4,535,084 — 4,535,084 Proved Developed Reserves: 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 September 30, 2023 3,550,034 — 3,550,034 Proved Undeveloped Reserves: September 30, 2020 551,262 — 551,262 September 30, 2021 631,970 — 631,970 September 30, 2022 858,094 — 858,094 September 30, 2023 985,050 — 985,050 (1) Extensions and discoveries include 180 Bcf (during 2021), 301 Bcf (during 2022) and 163 Bcf (during 2023), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 497 Bcf (during 2021), 537 Bcf (during 2022) and 507 Bcf (during 2023), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 218,016 MMcf (during 2021), 209,463 MMcf (during 2022) and 190,290 MMcf (during 2023), from Marcellus Shale fields. Production includes 93,253 MMcf (during 2021), 130,240 MMcf (during 2022) and 180,750 MMcf (during 2023), from Utica Shale fields. Oil Mbbl U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Revisions of Previous Estimates (4) — (4) Production (30) — (30) September 30, 2023 216 — 216 Proved Developed Reserves: September 30, 2020 12 22,088 22,100 September 30, 2021 11 20,930 20,941 September 30, 2022 250 — 250 September 30, 2023 216 — 216 Proved Undeveloped Reserves: September 30, 2020 — — — September 30, 2021 — 596 596 September 30, 2022 — — — September 30, 2023 — — — |
Schedule of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves | Year Ended September 30 2023 2022 2021 (Thousands) United States Future Cash Inflows $ 11,947,345 $ 19,209,099 $ 10,175,182 Less: Future Production Costs 3,538,389 3,138,226 3,423,629 Future Development Costs 1,095,096 781,847 597,662 Future Income Tax Expense at Applicable Statutory Rate 1,867,457 3,876,272 1,397,175 Future Net Cash Flows 5,446,403 11,412,754 4,756,716 Less: 10% Annual Discount for Estimated Timing of Cash Flows 2,874,295 5,964,424 2,403,144 Standardized Measure of Discounted Future Net Cash Flows $ 2,572,108 $ 5,448,330 $ 2,353,572 |
Schedule of Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows | The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2023 2022 2021 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 5,448,330 $ 2,353,572 $ 1,222,470 Sales, Net of Production Costs (767,487) (1,572,402) (626,132) Net Changes in Prices, Net of Production Costs (3,918,392) 4,132,889 1,478,995 Extensions and Discoveries 237,057 1,355,257 462,040 Changes in Estimated Future Development Costs (222,233) (32,160) 48,247 Purchases of Minerals in Place 34,346 — — Sales of Minerals in Place — (311,308) — Previously Estimated Development Costs Incurred 342,024 154,253 81,239 Net Change in Income Taxes at Applicable Statutory Rate 959,728 (1,180,349) (415,993) Revisions of Previous Quantity Estimates 33,192 3,316 (52,383) Accretion of Discount and Other 425,543 545,262 155,089 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 2,572,108 $ 5,448,330 $ 2,353,572 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Allowance of Uncollectible Amounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Allowance for Uncollectible Accounts [Roll Forward] | |||
Balance at Beginning of Year | $ 40,228 | $ 31,639 | $ 22,810 |
Additions Charged to Costs and Expenses | 14,482 | 13,209 | 14,940 |
Add: Discounts on Purchased Receivables | 1,380 | 1,314 | 1,168 |
Deduct: Net Accounts Receivable Written-Off | 19,795 | 5,934 | 7,279 |
Balance at End of Year | $ 36,295 | $ 40,228 | $ 31,639 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Summary of Significant Accounting Policies [Line Items] | ||||
Weather impact on revenues tempered by WNC, period | 8 months | |||
Above/below average weather normalized usage, surcharge calculation period | 12 months | |||
Capitalized costs relating to oil and gas producing activities, net | $ 2,446,226 | $ 1,947,535 | ||
Full cost ceiling test discount factor (as a percent) | 10% | |||
Amount full cost ceiling exceeds book value of oil and gas properties | $ 794,700 | |||
Increase (decrease) estimated future net cash flows | 38,800 | (1,000,000) | $ (76,100) | |
Depreciation, depletion and amortization for oil and gas properties | 235,694 | 202,418 | 177,055 | |
Goodwill | 5,476 | 5,476 | ||
Prior service cost | 400 | 400 | ||
Accumulated losses | 59,300 | 53,200 | ||
Other post-retirement adjustment for regulatory proceeding, before tax | $ (7,400) | 0 | (7,351) | $ 0 |
Other post-retirement adjustment for regulatory proceeding, after tax | $ (5,800) | (5,807) | ||
Gas stored underground | $ 32,509 | 32,364 | ||
Rate recovery period | 4 years | |||
Balanced billing, estimated annual usage, payment period | 12 months | |||
Customer advances | $ 21,003 | 26,108 | ||
Customer security deposits | $ 28,764 | $ 24,283 | ||
Antidilutive securities (in shares) | 3,888 | 2,858 | 320,222 | |
Minimum | Stock Appreciation Rights (SARs) | ||||
Summary of Significant Accounting Policies [Line Items] | ||||
SARs exercisable, period | 1 year | |||
Maximum | Stock Appreciation Rights (SARs) | ||||
Summary of Significant Accounting Policies [Line Items] | ||||
SARs exercisable, period | 10 years | |||
Amount Exceeds LIFO Basis | ||||
Summary of Significant Accounting Policies [Line Items] | ||||
Gas stored underground | $ 3,700 | |||
LIFO Method | ||||
Summary of Significant Accounting Policies [Line Items] | ||||
Gas stored underground | $ 32,400 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Schedule of Depreciable Plant by Segment (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Segment Reporting Information [Line Items] | ||
Depreciable plant | $ 13,101,006 | $ 12,233,508 |
Exploration and Production | ||
Segment Reporting Information [Line Items] | ||
Depreciable plant | 6,741,095 | 6,088,476 |
Pipeline and Storage | ||
Segment Reporting Information [Line Items] | ||
Depreciable plant | 2,803,690 | 2,747,948 |
Gathering | ||
Segment Reporting Information [Line Items] | ||
Depreciable plant | 1,032,969 | 971,665 |
Utility | ||
Segment Reporting Information [Line Items] | ||
Depreciable plant | 2,507,465 | 2,411,707 |
All Other and Corporate | ||
Segment Reporting Information [Line Items] | ||
Depreciable plant | $ 15,787 | $ 13,712 |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Average Depreciation, Depletion and Amortization Rates (Details) - USD ($) | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Exploration and Production | ||||
Segment Reporting Information [Line Items] | ||||
Depreciation, depletion and amortization rate (in dollars per Mcfe of production) | [1] | $ 0.65 | $ 0.59 | $ 0.56 |
Pipeline and Storage | ||||
Segment Reporting Information [Line Items] | ||||
Average depreciation, depletion and amortization rates | 2.60% | 2.70% | 2.60% | |
Gathering | ||||
Segment Reporting Information [Line Items] | ||||
Average depreciation, depletion and amortization rates | 3.60% | 3.60% | 3.60% | |
Utility | ||||
Segment Reporting Information [Line Items] | ||||
Average depreciation, depletion and amortization rates | 2.70% | 2.70% | 2.70% | |
All Other and Corporate | ||||
Segment Reporting Information [Line Items] | ||||
Average depreciation, depletion and amortization rates | 2.90% | 1.40% | 3.40% | |
Oil and Gas Producing Properties | ||||
Segment Reporting Information [Line Items] | ||||
Depreciation, depletion and amortization rate (in dollars per Mcfe of production) | $ 0.63 | $ 0.57 | $ 0.54 | |
[1]Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.57 and $0.54 per Mcfe of production in 2023, 2022 and 2021, respectively. |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies - Components of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | |
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning balance | $ (625,733) | $ (513,597) | |
Other Comprehensive Gains and Losses Before Reclassifications | 486,560 | (755,831) | |
Amounts Reclassified From Other Comprehensive Loss | 84,113 | 649,502 | |
Other Post-Retirement Adjustment for Regulatory Proceeding | $ (5,800) | (5,807) | |
Ending balance | (55,060) | (625,733) | |
Gains and Losses on Derivative Financial Instruments | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning balance | (572,163) | (449,962) | |
Other Comprehensive Gains and Losses Before Reclassifications | 493,936 | (763,223) | |
Amounts Reclassified From Other Comprehensive Loss | 82,850 | 641,022 | |
Other Post-Retirement Adjustment for Regulatory Proceeding | 0 | ||
Ending balance | 4,623 | (572,163) | |
Funded Status of the Pension and Other Post-Retirement Benefit Plans | |||
Accumulated Other Comprehensive Income (Loss) [Roll Forward] | |||
Beginning balance | (53,570) | (63,635) | |
Other Comprehensive Gains and Losses Before Reclassifications | (7,376) | 7,392 | |
Amounts Reclassified From Other Comprehensive Loss | 1,263 | 8,480 | |
Other Post-Retirement Adjustment for Regulatory Proceeding | (5,807) | ||
Ending balance | $ (59,683) | $ (53,570) |
Summary of Significant Accoun_9
Summary of Significant Accounting Policies - Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Operating Revenues | $ 2,173,771 | $ 2,186,046 | $ 1,742,659 | |
Total Before Income Tax | 641,399 | 682,650 | 478,329 | |
Income Tax Expense | (164,533) | (116,629) | (114,682) | |
Net of Tax | 476,866 | 566,021 | $ 363,647 | |
Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Loss | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Total Before Income Tax | (90,330) | (893,635) | ||
Income Tax Expense | 6,217 | 244,133 | ||
Net of Tax | (84,113) | (649,502) | ||
Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Loss | Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Prior Service Cost | [1] | (82) | (103) | |
Net Actuarial Loss | [1] | (1,592) | (10,951) | |
Commodity Contracts | Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Loss | Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Operating Revenues | (88,015) | (882,594) | ||
Foreign Currency Contracts | Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Loss | Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges | ||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items] | ||||
Operating Revenues | $ (641) | $ 13 | ||
[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. |
Summary of Significant Accou_10
Summary of Significant Accounting Policies - Consolidated Statement of Cash Flows (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 | |
Accounting Policies [Abstract] | |||||
Cash and Temporary Cash Investments | $ 55,447 | $ 46,048 | $ 31,528 | $ 20,541 | |
Hedging Collateral Deposits | 0 | 91,670 | [1] | 88,610 | 0 |
Cash, Cash Equivalents, and Restricted Cash | $ 55,447 | $ 137,718 | $ 120,138 | $ 20,541 | |
[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. |
Summary of Significant Accou_11
Summary of Significant Accounting Policies - Components of Other Current Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | |
Other Current Assets [Line Items] | |||
Prepayments | $ 18,966 | $ 17,757 | |
Prepaid Property and Other Taxes | 14,186 | 14,321 | |
Regulatory Assets | [1] | 36,373 | 21,358 |
Other Current Assets | 100,260 | 59,369 | |
Federal | |||
Other Current Assets [Line Items] | |||
Income Taxes Receivable | 14,602 | 0 | |
State | |||
Other Current Assets [Line Items] | |||
Income Taxes Receivable | $ 16,133 | $ 5,933 | |
[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. |
Summary of Significant Accou_12
Summary of Significant Accounting Policies - Schedule of Other Accruals and Current Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Accounting Policies [Abstract] | ||
Accrued Capital Expenditures | $ 43,323 | $ 64,720 |
Regulatory Liabilities | 38,105 | 31,293 |
Liability for Royalty and Working Interests | 17,679 | 86,206 |
Non-Qualified Benefit Plan Liability | 13,052 | 17,474 |
Other | 48,815 | 57,634 |
Other Accruals and Current Liabilities | $ 160,974 | $ 257,327 |
Asset Acquisitions and Divest_3
Asset Acquisitions and Divestitures - Narrative (Details) | 12 Months Ended | 36 Months Ended | |||||
Jun. 01, 2023 USD ($) a | Jun. 30, 2022 USD ($) | Dec. 10, 2020 USD ($) | Sep. 30, 2023 USD ($) | Sep. 30, 2022 USD ($) | Sep. 30, 2021 USD ($) | Dec. 31, 2025 USD ($) payment | |
Asset Acquisition [Line Items] | |||||||
Net Proceeds from Sale of Oil and Gas Producing Properties | $ 0 | $ 254,439,000 | $ 0 | ||||
Gain on Sale of Assets | 0 | 12,736,000 | 51,066,000 | ||||
Reduction in asset retirement obligation | 14,448,000 | 71,171,000 | 14,270,000 | ||||
Net proceeds from sale of timber properties | $ 104,600,000 | 0 | 0 | $ 104,582,000 | |||
Gain on sale of timber properties | $ 51,100,000 | ||||||
California Asset Sale | |||||||
Asset Acquisition [Line Items] | |||||||
Total sale price | $ 253,500,000 | ||||||
Net Proceeds from Sale of Oil and Gas Producing Properties | 240,900,000 | ||||||
Gain on Sale of Assets | 12,700,000 | ||||||
Reduction in asset retirement obligation | 50,100,000 | ||||||
California Asset Sale | Forecast | |||||||
Asset Acquisition [Line Items] | |||||||
Maximum annual contingent payment | $ 10,000,000 | ||||||
Amount of each incremental contingency payment | 1,000,000 | ||||||
Incremental price, exceeding ICE Brent Average Price (in dollars per barrel) | 1 | ||||||
California Asset Sale | Full Cost Method of Accounting Assets | |||||||
Asset Acquisition [Line Items] | |||||||
Disposal of assets | 220,700,000 | ||||||
California Asset Sale | Assets Not Subject to Full Cost Method of Accounting | |||||||
Asset Acquisition [Line Items] | |||||||
Disposal of assets | 32,800,000 | ||||||
California Asset Sale | Minimum | Forecast | |||||||
Asset Acquisition [Line Items] | |||||||
ICE Brent Average (in dollars per barrel) | $ 95 | ||||||
California Asset Sale | Maximum | Forecast | |||||||
Asset Acquisition [Line Items] | |||||||
Number of annual contingent payments | payment | 3 | ||||||
ICE Brent Average (in dollars per barrel) | $ 105 | ||||||
California Asset Sale | Present Value of Contingent Consideration | |||||||
Asset Acquisition [Line Items] | |||||||
Value of contingent consideration received from sale of assets | $ 12,600,000 | $ 7,300,000 | $ 8,200,000 | ||||
SWN Upstream Asset Acquisition | |||||||
Asset Acquisition [Line Items] | |||||||
Total consideration | $ 124,758,000 | ||||||
Net acres acquired in Appalachia | a | 34,000 |
Asset Acquisition and Divestitu
Asset Acquisition and Divestitures - Summary of Asset Acquisition (Details) - SWN Upstream Asset Acquisition $ in Thousands | Jun. 01, 2023 USD ($) |
Asset Acquisition [Line Items] | |
Purchase Price | $ 124,178 |
Transaction Costs | 580 |
Total Consideration | $ 124,758 |
Revenue from Contracts with C_3
Revenue from Contracts with Customers - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | $ 2,254,894 | $ 3,061,283 | |
Alternative Revenue Programs | 6,892 | 7,357 | |
Derivative Financial Instruments | (88,015) | (882,594) | |
Total Revenues | 2,173,771 | 2,186,046 | $ 1,742,659 |
Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 2,591,446 | 3,375,809 | |
Alternative Revenue Programs | 6,892 | 7,357 | |
Derivative Financial Instruments | (88,015) | (882,594) | |
Total Revenues | 2,510,323 | 2,500,572 | |
All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 6 | |
Alternative Revenue Programs | 0 | 0 | |
Derivative Financial Instruments | 0 | 0 | |
Total Revenues | 0 | 6 | |
Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | (336,552) | (314,532) | |
Alternative Revenue Programs | 0 | 0 | |
Derivative Financial Instruments | 0 | 0 | |
Total Revenues | (336,552) | (314,532) | |
Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,046,470 | 1,893,058 | |
Alternative Revenue Programs | 0 | 0 | |
Derivative Financial Instruments | (88,015) | (882,594) | |
Total Revenues | 958,455 | 1,010,464 | |
Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 379,191 | 377,044 | |
Alternative Revenue Programs | 0 | 0 | |
Derivative Financial Instruments | 0 | 0 | |
Total Revenues | 379,191 | 377,044 | |
Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 230,317 | 214,843 | |
Alternative Revenue Programs | 0 | 0 | |
Derivative Financial Instruments | 0 | 0 | |
Total Revenues | 230,317 | 214,843 | |
Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 935,468 | 890,864 | |
Alternative Revenue Programs | 6,892 | 7,357 | |
Derivative Financial Instruments | 0 | 0 | |
Total Revenues | 942,360 | 898,221 | |
Production of Natural Gas | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,036,499 | 1,730,723 | |
Production of Natural Gas | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,036,499 | 1,730,723 | |
Production of Natural Gas | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Natural Gas | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Natural Gas | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,036,499 | 1,730,723 | |
Production of Natural Gas | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Natural Gas | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Natural Gas | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Crude Oil | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 2,261 | 150,957 | |
Production of Crude Oil | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 2,261 | 150,957 | |
Production of Crude Oil | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Crude Oil | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Crude Oil | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 2,261 | 150,957 | |
Production of Crude Oil | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Crude Oil | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Production of Crude Oil | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Processing | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,203 | 3,511 | |
Natural Gas Processing | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,203 | 3,511 | |
Natural Gas Processing | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Processing | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Processing | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 1,203 | 3,511 | |
Natural Gas Processing | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Processing | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Processing | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Gathering Service | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 13,891 | 12,086 | |
Natural Gas Gathering Service | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 230,317 | 214,843 | |
Natural Gas Gathering Service | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Gathering Service | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | (216,426) | (202,757) | |
Natural Gas Gathering Service | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Gathering Service | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Gathering Service | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 230,317 | 214,843 | |
Natural Gas Gathering Service | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Transportation Service | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 306,640 | 321,713 | |
Natural Gas Transportation Service | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 389,529 | 396,462 | |
Natural Gas Transportation Service | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Transportation Service | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | (82,889) | (74,749) | |
Natural Gas Transportation Service | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Transportation Service | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 291,225 | 289,967 | |
Natural Gas Transportation Service | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Transportation Service | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 98,304 | 106,495 | |
Natural Gas Storage Service | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 48,679 | 48,183 | |
Natural Gas Storage Service | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 84,962 | 84,565 | |
Natural Gas Storage Service | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Storage Service | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | (36,283) | (36,382) | |
Natural Gas Storage Service | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Storage Service | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 84,962 | 84,565 | |
Natural Gas Storage Service | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Storage Service | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Residential Sales | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 727,728 | 688,271 | |
Natural Gas Residential Sales | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 727,728 | 688,271 | |
Natural Gas Residential Sales | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Residential Sales | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Residential Sales | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Residential Sales | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Residential Sales | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Residential Sales | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 727,728 | 688,271 | |
Natural Gas Commercial Sales | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 103,270 | 95,114 | |
Natural Gas Commercial Sales | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 103,270 | 95,114 | |
Natural Gas Commercial Sales | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Commercial Sales | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Commercial Sales | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Commercial Sales | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Commercial Sales | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Commercial Sales | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 103,270 | 95,114 | |
Natural Gas Industrial Sales | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 5,651 | 4,902 | |
Natural Gas Industrial Sales | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 5,658 | 4,902 | |
Natural Gas Industrial Sales | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Industrial Sales | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | (7) | 0 | |
Natural Gas Industrial Sales | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Industrial Sales | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Industrial Sales | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Natural Gas Industrial Sales | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 5,658 | 4,902 | |
Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 9,072 | 5,823 | |
Other | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 10,019 | 6,461 | |
Other | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 6 | |
Other | Corporate and Intersegment Eliminations | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | (947) | (644) | |
Other | Exploration and Production | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 6,507 | 7,867 | |
Other | Pipeline and Storage | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 3,004 | 2,512 | |
Other | Gathering | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | 0 | 0 | |
Other | Utility | Total Reportable Segments | |||
Disaggregation of Revenue [Line Items] | |||
Total Revenues from Contracts with Customers | $ 508 | $ (3,918) |
Revenue from Contracts with C_4
Revenue from Contracts with Customers - Narrative (Details) $ in Millions | 12 Months Ended |
Sep. 30, 2023 USD ($) | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Payment period for Exploration and Production segment invoices | 30 days |
Settlement period for receivables or customer advances related to Utility segment budget billing | 1 year |
Annual reconciliation period for Utility segment alternative revenue programs | 24 months |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligations | $ 210.7 |
Remaining performance obligations, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligations | $ 184 |
Remaining performance obligations, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligations | $ 148.3 |
Remaining performance obligations, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligations | $ 123.3 |
Remaining performance obligations, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligations | $ 107.5 |
Remaining performance obligations, period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Remaining performance obligations | $ 581 |
Remaining performance obligations, period |
Leases - Narrative (Details)
Leases - Narrative (Details) - USD ($) | 12 Months Ended | |
Sep. 30, 2023 | Sep. 30, 2022 | |
Lessee, Lease, Description [Line Items] | ||
Weighted average remaining lease term | 6 years 1 month 6 days | 6 years |
Weighted average discount rate | 5.48% | 3.92% |
Cash paid for operating liabilities | $ 9,700,000 | $ 5,700,000 |
Right of use asset in exchange for new lease liability | $ 0 | $ 0 |
Buildings and Property | Minimum | ||
Lessee, Lease, Description [Line Items] | ||
Non-cancelable lease term | 1 month | |
Operating lease renewal term | 1 year | |
Buildings and Property | Maximum | ||
Lessee, Lease, Description [Line Items] | ||
Non-cancelable lease term | 16 years | |
Operating lease renewal term | 18 years | |
Drilling Rigs | Maximum | ||
Lessee, Lease, Description [Line Items] | ||
Non-cancelable lease term | 1 year | |
Compressor Equipment | Minimum | ||
Lessee, Lease, Description [Line Items] | ||
Non-cancelable lease term | 9 months | |
Compressor Equipment | Maximum | ||
Lessee, Lease, Description [Line Items] | ||
Non-cancelable lease term | 5 years |
Leases - Components of Operatin
Leases - Components of Operating Lease Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | ||
Lessee, Lease, Description [Line Items] | |||
Operating Lease Expense | $ 7,484 | $ 4,909 | |
Variable Lease Expense | [1] | 507 | 462 |
Short-Term Lease Expense/Costs | [2] | 1,694 | 461 |
Sublease Income | 0 | (166) | |
Total Lease Expense | 9,685 | 5,666 | |
Oil and Natural Gas Properties | |||
Lessee, Lease, Description [Line Items] | |||
Lease Costs Recorded to Property, Plant and Equipment | [3] | $ 24,018 | $ 19,839 |
[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. |
Leases - Balance Sheet Informat
Leases - Balance Sheet Information Related to Operating Leases (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Assets: | ||
Deferred Charges | $ 39,664 | $ 37,120 |
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration] | Deferred Charges | Deferred Charges |
Liabilities: | ||
Other Accruals and Current Liabilities | $ 9,969 | $ 14,239 |
Other Liabilities | $ 29,510 | $ 22,881 |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration] | Other Accruals and Current Liabilities | Other Accruals and Current Liabilities |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration] | Other Liabilities | Other Liabilities |
Leases - Schedule of Operating
Leases - Schedule of Operating Lease Liability Maturities (Details) $ in Thousands | Sep. 30, 2023 USD ($) |
Leases [Abstract] | |
2024 | $ 10,187 |
2025 | 8,791 |
2026 | 6,557 |
2027 | 5,809 |
2028 | 5,195 |
Thereafter | 9,971 |
Total Lease Payments | 46,510 |
Less: Interest | (7,031) |
Total Lease Liability | $ 39,479 |
Asset Retirement Obligation - N
Asset Retirement Obligation - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Jun. 30, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Asset Retirement Obligation [Line Items] | ||||
Liabilities Settled | $ 14,448 | $ 71,171 | $ 14,270 | |
California Asset Sale | ||||
Asset Retirement Obligation [Line Items] | ||||
Liabilities Settled | $ 50,100 |
Asset Retirement Obligations -
Asset Retirement Obligations - Schedule of Change in Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Balance at Beginning of Year | $ 161,545 | $ 209,639 | $ 192,228 |
Liabilities Incurred | 3,313 | 2,401 | 7,035 |
Revisions of Estimates | 6,728 | 10,700 | 14,509 |
Liabilities Settled | (14,448) | (71,171) | (14,270) |
Accretion Expense | 8,354 | 9,976 | 10,137 |
Balance at End of Year | $ 165,492 | $ 161,545 | $ 209,639 |
Regulatory Matters - Schedule o
Regulatory Matters - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | |
Regulatory Assets: | |||
Total Regulatory Assets | [1] | $ 184,796 | $ 203,590 |
Less: Amounts Included in Other Current Assets | [1] | (36,373) | (21,358) |
Regulatory Liabilities: | |||
Total Regulatory Liabilities | 808,821 | 842,560 | |
Less: Amounts included in Current and Accrued Liabilities | 97,124 | 31,712 | |
Total Long-Term Regulatory Liabilities | 711,697 | 810,848 | |
Cost of Removal Regulatory Liability | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | 277,694 | 259,947 | |
Taxes Refundable to Customers | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | 268,562 | 362,098 | |
Post-Retirement Benefit Costs | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | [2] | 159,760 | 167,305 |
Less: Amounts included in Current and Accrued Liabilities | 5,800 | 5,800 | |
Total Long-Term Regulatory Liabilities | 153,960 | 161,505 | |
Pension Costs | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | [3] | 0 | 8,242 |
Amounts Payable to Customers | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | 59,019 | 419 | |
Environmental Site Remediation Costs | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | [3] | 619 | 0 |
Other | |||
Regulatory Liabilities: | |||
Total Regulatory Liabilities | [4] | 43,167 | 44,549 |
Total Long-Term Regulatory Liabilities | 10,862 | 19,056 | |
Other Accruals and Current Liabilities | |||
Regulatory Liabilities: | |||
Less: Amounts included in Current and Accrued Liabilities | 32,305 | 25,493 | |
Pension Costs | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1],[5] | 20,459 | 11,677 |
Post-Retirement Benefit Costs | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1],[5] | 2,536 | 6,814 |
Recoverable Future Taxes | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1] | 69,045 | 106,247 |
Environmental Site Remediation Costs | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1],[5] | 0 | 3,646 |
Asset Retirement Obligations | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1],[5] | 19,384 | 18,517 |
Unamortized Debt Expense | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1] | 7,240 | 8,884 |
Other | |||
Regulatory Assets: | |||
Total Regulatory Assets | [1],[6] | 66,132 | 47,805 |
Total Long-Term Regulatory Assets | 29,759 | 26,447 | |
Long-Term Regulatory Assets | |||
Regulatory Assets: | |||
Total Long-Term Regulatory Assets | [1] | 148,423 | 182,232 |
Other Current Assets | |||
Regulatory Assets: | |||
Less: Amounts Included in Other Current Assets | $ (36,373) | $ (21,358) | |
[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]$5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2023 and 2022, since such amounts are expected to be passed back to ratepayers in the next 12 months. $153,960 and $161,505 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively.[3]Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.[4]$32,305 and $25,493 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,862 and $19,056 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively.[5]Included in Other Regulatory Assets on the Consolidated Balance Sheets.[6]$36,373 and $21,358 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $29,759 and $26,447 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively. |
Regulatory Matters - Narrative
Regulatory Matters - Narrative (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | 77 Months Ended | |||||||
Oct. 31, 2023 | Aug. 01, 2023 | Jul. 31, 2023 | Oct. 28, 2022 | Oct. 01, 2021 | Mar. 31, 2022 | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2023 | |
Regulatory Matters [Line Items] | ||||||||||
Reduction of other post-retirement regulatory liability | $ 0 | $ 18,533 | $ 0 | |||||||
Supply Corporation | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Public utilities proposed annual cost of service | $ 385,400 | |||||||||
Public utilities proposed rate base | $ 1,320,000 | |||||||||
Proposed return on equity (as a percent) | 15.12% | |||||||||
New York | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Approved return on equity (as a percent) | 8.70% | |||||||||
Authorized annual recovery from customers for pension and OPEB expense | $ 15,000 | |||||||||
New York | Subsequent Event [Member] | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Proposed base rate increase | $ 88,800 | |||||||||
Proposed rate recovery of pension and OPEB costs | 0 | |||||||||
Savings reflected in new base delivery rates | $ 15,000 | |||||||||
Pennsylvania | ||||||||||
Regulatory Matters [Line Items] | ||||||||||
Proposed base rate increase | $ 28,100 | |||||||||
Public utilities authorized rate increase, amount | $ 23,000 | |||||||||
Approved base rate reduction for OPEB expenses | $ 7,700 | |||||||||
Proposed refund to customers from over-collection of OPEB expenses | $ 50,000 | |||||||||
Reduction of other post-retirement regulatory liability | $ 18,500 | |||||||||
Approved refund to customers from over-collection of OPEB expenses | $ 54,000 |
Income Taxes - Components of Fe
Income Taxes - Components of Federal and State Income Taxes Included in the Consolidated Statements of Income (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Current Income Taxes — | |||
Federal | $ 11,744 | $ 0 | $ (10) |
State | 1,386 | 12,214 | 8,699 |
Deferred Income Taxes — | |||
Federal | 106,801 | 137,025 | 90,970 |
State | 44,602 | (32,610) | 15,023 |
Total Income Taxes | $ 164,533 | $ 116,629 | $ 114,682 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2022 | Jun. 30, 2022 | Sep. 30, 2022 | Sep. 30, 2032 | Sep. 30, 2024 | Sep. 30, 2023 | Sep. 30, 2022 | Oct. 01, 2024 | Sep. 30, 2021 | |
Income Taxes [Line Items] | |||||||||
Change in deferred income taxes | $ (99,500,000) | ||||||||
Taxes refundable to customers | $ 362,098,000 | $ 362,098,000 | 268,562,000 | $ 362,098,000 | |||||
Recoverable future taxes | 106,247,000 | 106,247,000 | 69,045,000 | 106,247,000 | |||||
Unrecognized tax benefits | 0 | 0 | 0 | 0 | $ 0 | ||||
Sale of California Assets | |||||||||
Income Taxes [Line Items] | |||||||||
Adjustments to valuation allowance | $ (27,200,000) | ||||||||
Pennsylvania Tax Rate Change | |||||||||
Income Taxes [Line Items] | |||||||||
Adjustments to valuation allowance | (5,500,000) | ||||||||
Remaining State Deferred Tax Assets | |||||||||
Income Taxes [Line Items] | |||||||||
Adjustments to valuation allowance | (24,900,000) | ||||||||
Deferred Income Taxes | |||||||||
Income Taxes [Line Items] | |||||||||
Taxes refundable to customers | 362,100,000 | 362,100,000 | 268,600,000 | 362,100,000 | |||||
Recoverable future taxes | $ 106,200,000 | 106,200,000 | $ 69,000,000 | 106,200,000 | |||||
Pennsylvania | |||||||||
Income Taxes [Line Items] | |||||||||
Change in deferred income taxes | $ (28,400,000) | ||||||||
Reduction in deferred taxes for rate regulated activities due to remeasurement of deferred income tax assets and liabilities | 37,200,000 | ||||||||
Pennsylvania | Taxes Refundable to Customers | |||||||||
Income Taxes [Line Items] | |||||||||
Increase to taxes refundable to customers, impact of changes in corporate tax rate | 17,400,000 | ||||||||
Pennsylvania | Recoverable Future Taxes | |||||||||
Income Taxes [Line Items] | |||||||||
Decrease to recoverable future taxes, impact of change in corporate tax rate | $ 19,800,000 | ||||||||
Pennsylvania | Forecast | |||||||||
Income Taxes [Line Items] | |||||||||
Corporate income tax rate | 4.99% | 8.99% | |||||||
Annual reduction in corporate income tax Rate from fiscal 2025 to fiscal 2032 (as a percent) | 0.50% |
Income Taxes - Schedule of Inco
Income Taxes - Schedule of Income Tax Reconciliation by Applying Federal Income Tax Rate (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Income Tax Disclosure [Abstract] | ||||
U.S. Income Before Income Taxes | $ 641,399 | $ 682,650 | $ 478,329 | |
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21% | 134,694 | 143,357 | 100,449 | |
State Valuation Allowance | [1] | 0 | (24,850) | (5,560) |
State Income Taxes | [2] | 36,331 | 8,736 | 24,300 |
Amortization of Excess Deferred Federal Income Taxes | (6,053) | (5,184) | (5,215) | |
Plant Flow Through Items | (2,856) | (814) | (1,503) | |
Stock Compensation | 957 | 820 | 2,239 | |
Federal Tax Credits | (6) | (5,701) | (310) | |
Miscellaneous | 1,466 | 265 | 282 | |
Total Income Taxes | $ 164,533 | $ 116,629 | $ 114,682 | |
Federal Statutory Rate | 21% | 21% | 21% | |
[1]During fiscal 2022, the valuation allowance recorded against certain state deferred tax assets was removed. See discussion below.[2]The state income tax expense shown above includes adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes, including the Pennsylvania rate change discussed above. |
Income Taxes - Significant Comp
Income Taxes - Significant Components of Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Deferred Tax Liabilities: | ||
Unrealized Hedging Gains | $ 3,385 | $ 0 |
Property, Plant and Equipment | 1,178,893 | 954,757 |
Pension and Other Post-Retirement Benefit Costs | 44,358 | 30,132 |
Other | 21,470 | 48,893 |
Total Deferred Tax Liabilities | 1,248,106 | 1,033,782 |
Deferred Tax Assets: | ||
Unrealized Hedging Losses | 0 | (215,187) |
Tax Loss and Credit Carryforwards | (33,744) | (50,686) |
Pension and Other Post-Retirement Benefit Costs | (41,843) | (37,250) |
Other | (48,349) | (32,430) |
Total Deferred Tax Assets | (123,936) | (335,553) |
Total Net Deferred Income Taxes | $ 1,124,170 | $ 698,229 |
Income Taxes - Summary of Chang
Income Taxes - Summary of Changes in Valuation Allowances for Deferred Tax Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Valuation Allowance [Roll Forward] | |||
Balance at Beginning of Year | $ 0 | $ 57,645 | $ 63,205 |
Additions | 0 | 0 | 0 |
Deductions | 0 | 57,645 | 5,560 |
Balance at End of Year | $ 0 | $ 0 | $ 57,645 |
Income Taxes Income Taxes - Sum
Income Taxes Income Taxes - Summary of Operating Loss and Tax Credit Carryforwards (Details) $ in Thousands | Sep. 30, 2023 USD ($) |
Pennsylvania | |
Operating Loss Carryforwards [Line Items] | |
Net Operating Loss | $ 404,403 |
General Business Credits | Federal | |
Operating Loss Carryforwards [Line Items] | |
Tax Credit Carryforwards | $ 1,819 |
Capitalization and Short-Term_3
Capitalization and Short-Term Borrowings - Summary of Changes in Common Stock Equity (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Beginning balance (in shares) | 91,478,064 | ||||
Beginning balance | $ 2,079,896 | ||||
Net Income Available for Common Stock | 476,866 | $ 566,021 | $ 363,647 | ||
Dividends Declared on Common Stock | (178,095) | (170,111) | (164,102) | ||
Other Comprehensive Loss, Net of Tax | $ 570,673 | $ (112,136) | $ (398,840) | ||
Ending balance (in shares) | 91,819,405 | 91,478,064 | |||
Ending balance | $ 2,963,376 | $ 2,079,896 | |||
Dividend per share (in dollars per share) | $ 1.94 | $ 1.86 | $ 1.80 | ||
Accumulated earnings free from limitations | $ 1,700,000 | ||||
Common Stock | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Beginning balance (in shares) | 91,478,000 | 91,182,000 | 90,955,000 | ||
Beginning balance | $ 91,478 | $ 91,182 | $ 90,955 | ||
Common Stock Issued (Repurchased) Under Stock and Benefit Plans (in shares) | 341,000 | 296,000 | 227,000 | ||
Common Stock Issued (Repurchased) Under Stock and Benefit Plans | $ 341 | $ 296 | $ 227 | ||
Ending balance (in shares) | 91,819,000 | 91,478,000 | 91,182,000 | ||
Ending balance | $ 91,819 | $ 91,478 | $ 91,182 | ||
Paid In Capital | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Beginning balance | 1,027,066 | 1,017,446 | 1,004,158 | ||
Share-Based Payment Expense | [1] | 18,746 | 17,699 | 15,297 | |
Common Stock Issued (Repurchased) Under Stock and Benefit Plans | (5,051) | (8,079) | (2,009) | ||
Ending balance | 1,040,761 | 1,027,066 | 1,017,446 | ||
Earnings Reinvested in the Business | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Beginning balance | 1,587,085 | 1,191,175 | 991,630 | ||
Net Income Available for Common Stock | 476,866 | 566,021 | 363,647 | ||
Dividends Declared on Common Stock | (178,095) | (170,111) | (164,102) | ||
Ending balance | 1,885,856 | [2] | 1,587,085 | 1,191,175 | |
Accumulated Other Comprehensive Income (Loss) | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Beginning balance | (625,733) | (513,597) | (114,757) | ||
Other Comprehensive Loss, Net of Tax | 570,673 | (112,136) | (398,840) | ||
Ending balance | $ (55,060) | $ (625,733) | $ (513,597) | ||
[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, 2023, $1.7 billion of accumulated earnings was free of such limitations. |
Capitalization and Short-Term_4
Capitalization and Short-Term Borrowings - Narrative (Details) | 3 Months Ended | 12 Months Ended | |||||||||||
May 18, 2023 USD ($) | Feb. 24, 2021 USD ($) | Mar. 31, 2021 USD ($) | Sep. 30, 2023 USD ($) $ / shares shares | Sep. 30, 2022 USD ($) $ / shares shares | Sep. 30, 2021 USD ($) $ / shares shares | Mar. 31, 2023 USD ($) | Nov. 25, 2022 USD ($) | Oct. 27, 2022 USD ($) | Jun. 30, 2022 USD ($) bank | May 03, 2022 bank | Feb. 28, 2022 USD ($) bank | Mar. 11, 2021 USD ($) | |
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Common stock issued for 401(k) plans (in shares) | shares | 0 | ||||||||||||
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan (in shares) | shares | 0 | ||||||||||||
Common stock issued as a result of SARs exercises (in shares) | shares | 12,055 | ||||||||||||
Shares tendered (in shares) | shares | 103,059 | ||||||||||||
Stock-based compensation expense | $ 18,600,000 | $ 17,600,000 | $ 15,200,000 | ||||||||||
Tax benefit related to stock-based compensation expense | 2,400,000 | 2,500,000 | 2,400,000 | ||||||||||
Capitalized stock-based compensation costs | 100,000 | 100,000 | 100,000 | ||||||||||
Tax benefit related to stock-based compensation exercises and vestings | $ 1,200,000 | ||||||||||||
Number of shares available for future grant (in shares) | shares | 1,510,900 | ||||||||||||
Preferred stock shares authorized (in shares) | shares | 10,000,000 | ||||||||||||
Preferred stock par value (in dollars per share) | $ / shares | $ 1 | ||||||||||||
Net proceeds from issuance of long-term debt | $ 297,306,000 | 0 | 495,267,000 | ||||||||||
Repayments of short-term borrowings | 250,000,000 | 0 | 0 | ||||||||||
Early redemption premium paid | 0 | 0 | $ 15,715,000 | ||||||||||
Principal amounts of long-term debt maturing in 2024 | 0 | ||||||||||||
Principal amounts of long-term debt maturing in 2025 | 500,000,000 | ||||||||||||
Principal amounts of long-term debt maturing in 2026 | 500,000,000 | ||||||||||||
Principal amounts of long-term debt maturing in 2027 | 600,000,000 | ||||||||||||
Principal amounts of long-term debt maturing in 2028 | 300,000,000 | ||||||||||||
Principal amounts of long-term debt maturing after 2028 | 500,000,000 | ||||||||||||
Commercial paper, outstanding | 287,500,000 | 0 | |||||||||||
Short-term notes payable outstanding to banks | $ 0 | $ 60,000,000 | |||||||||||
Committed debt to capitalization ratio | 0.65 | ||||||||||||
Ceiling test impairment adjustment (as a percent) | 50% | ||||||||||||
Ceiling test impairment maximum adjustment | $ 400,000,000 | ||||||||||||
Cumulative after-tax ceiling test impairments since July 1, 2018 | 381,400,000 | ||||||||||||
Committed credit facility debt to capitalization ratio ceiling test impairment adjustment | 190,700,000 | ||||||||||||
Debt to capitalization ratio maximum excluded unrealized gains or losses on other derivative financial instruments in AOCI | $ 10,000,000 | ||||||||||||
Debt to capitalization ratio | 0.46 | ||||||||||||
Permitted additional short-term and/or long-term debt to be outstanding under the Credit Agreement | $ 3,170,000,000 | ||||||||||||
Aggregated indebtedness | $ 40,000,000 | ||||||||||||
Indenture Test Period | 12 months | ||||||||||||
Indenture period before debt issuance | 15 months | ||||||||||||
Maximum long-term debt to consolidated asset ratio under indenture (as a percent) | 60% | ||||||||||||
Maximum debt increase under existing indenture covenants | $ 3,430,000,000 | ||||||||||||
Long-Term debt issued under 1974 Indenture as a percent of total long-term debt | 2.10% | ||||||||||||
Commercial Paper | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Weighted average interest rate | 6.13% | ||||||||||||
364-Day Credit Agreement | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Repayments of short-term borrowings | $ 250,000,000 | ||||||||||||
Number of banks in syndicate | bank | 5 | ||||||||||||
Maximum borrowing capacity | $ 250,000,000 | ||||||||||||
Committed credit facility amount drawn | $ 250,000,000 | ||||||||||||
Credit Agreement | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Number of banks in syndicate | bank | 12 | 12 | |||||||||||
Maximum borrowing capacity | $ 1,000,000,000 | ||||||||||||
5.50% Notes Due October 1, 2026 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Long-term debt, face value | $ 300,000,000 | $ 300,000,000 | |||||||||||
Long-term debt, interest rate | 5.50% | 5.50% | |||||||||||
Net proceeds from issuance of long-term debt | $ 297,300,000 | ||||||||||||
2.95% Notes Due March 1, 2031 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Long-term debt, face value | $ 500,000,000 | $ 500,000,000 | |||||||||||
Long-term debt, interest rate | 2.95% | 2.95% | |||||||||||
Net proceeds from issuance of long-term debt | $ 495,300,000 | ||||||||||||
4.90% Notes Due December 1, 2021 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Long-term debt, face value | $ 500,000,000 | ||||||||||||
Long-term debt, interest rate | 4.90% | ||||||||||||
Debt instrument redeemed | $ 515,700,000 | ||||||||||||
Early redemption premium paid | $ 15,700,000 | ||||||||||||
3.75% Notes Due March 2023 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Long-term debt, interest rate | 3.75% | 3.75% | 3.75% | ||||||||||
Debt instrument redeemed | $ 350,000,000 | $ 150,000,000 | |||||||||||
Commercial Paper | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Amount available to be issued under commercial paper program | $ 500,000,000 | ||||||||||||
Notes Payable to Banks | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Weighted average interest rate | 4.02% | ||||||||||||
Indenture From 1974 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Carrying amount of long-term debt under 1974 indenture | $ 50,000,000 | ||||||||||||
Board Of Directors | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Common stock issued (in shares) | shares | 31,715 | ||||||||||||
Officers | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Common stock issued (in shares) | shares | 2,796 | ||||||||||||
Restricted Stock Units (RSUs) | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Common stock issued (in shares) | shares | 119,147 | ||||||||||||
Performance Shares | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Common stock issued (in shares) | shares | 278,687 | ||||||||||||
SARs vested in period (in shares) | shares | 278,687 | ||||||||||||
Number of shares granted (in shares) | shares | 202,259 | 195,397 | 309,470 | ||||||||||
Weighted average fair value of award (in dollars per share) | $ / shares | $ 64.28 | $ 65.39 | $ 39.19 | ||||||||||
Unrecognized compensation expense | $ 12,800,000 | ||||||||||||
Unrecognized compensation expense recognized weighted average period | 1 year 8 months 12 days | ||||||||||||
Performance Shares | 2024 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 214,158 | ||||||||||||
Performance Shares | 2025 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 179,320 | ||||||||||||
Performance Shares | 2026 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 193,313 | ||||||||||||
Stock Appreciation Rights (SARs) | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Number of shares granted (in shares) | shares | 0 | 0 | 0 | ||||||||||
Intrinsic value of SARs exercised | $ 800,000 | $ 2,000,000 | |||||||||||
Number of SARs exercised (in shares) | shares | 72,008 | 0 | |||||||||||
SARs vested in period (in shares) | shares | 0 | 0 | 0 | ||||||||||
Non-Performance Based Restricted Stock Units (RSUs) | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
SARs vested in period (in shares) | shares | 119,147 | ||||||||||||
Number of shares granted (in shares) | shares | 133,173 | 128,950 | 172,513 | ||||||||||
Weighted average fair value of award (in dollars per share) | $ / shares | $ 58.10 | $ 54.10 | $ 37.98 | ||||||||||
Unrecognized compensation expense | $ 7,500,000 | ||||||||||||
Unrecognized compensation expense recognized weighted average period | 2 years 2 months 12 days | ||||||||||||
Non-Performance Based Restricted Stock Units (RSUs) | 2024 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 115,652 | ||||||||||||
Non-Performance Based Restricted Stock Units (RSUs) | 2025 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 98,343 | ||||||||||||
Non-Performance Based Restricted Stock Units (RSUs) | 2026 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 79,021 | ||||||||||||
Non-Performance Based Restricted Stock Units (RSUs) | 2027 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 33,527 | ||||||||||||
Non-Performance Based Restricted Stock Units (RSUs) | 2028 | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Non-vested stock-based compensation lapse (in shares) | shares | 15,643 | ||||||||||||
ROC Performance Shares | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Performance shares calculation period | 3 years | 3 years | 3 years | ||||||||||
ESG Performance Shares | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Number of shares granted (in shares) | shares | 0 | ||||||||||||
Performance shares calculation period | 3 years | 3 years | 3 years | ||||||||||
TSR Performance Shares | |||||||||||||
Schedule of Capitalization, Long-Term Debt and Equity [Line Items] | |||||||||||||
Performance shares calculation period | 3 years | 3 years | 3 years |
Capitalization and Short-Term_5
Capitalization and Short-Term Borrowings - Schedule of Share-Based Compensation for Stock Appreciation Rights (Details) - Stock Appreciation Rights (SARs) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Number of Shares Subject To Option | |||
Outstanding, beginning of year (in shares) | 72,008 | ||
Granted (in shares) | 0 | 0 | 0 |
Exercised (in shares) | (72,008) | 0 | |
Forfeited (in shares) | 0 | ||
Expired (in shares) | 0 | ||
Outstanding, end of year (in shares) | 0 | 72,008 | |
SARs exercisable (in shares) | 0 | ||
Weighted Average Exercise Price | |||
Outstanding, beginning of year (in dollars per share) | $ 53.05 | ||
Granted (in dollars per share) | 0 | ||
Exercised (in dollars per share) | 53.05 | ||
Forfeited (in dollars per share) | 0 | ||
Expired (in dollars per share) | 0 | ||
Outstanding, end of year (in dollars per share) | 0 | $ 53.05 | |
SARs exercisable (in dollars per share) | $ 0 | ||
Aggregate Intrinsic Value | |||
Outstanding, end of year | $ 0 | ||
SARs exercisable | $ 0 |
Capitalization and Short-Term_6
Capitalization and Short-Term Borrowings - Schedule of Share-Based Compensation for Restricted Stock Units and Performance Shares (Details) - $ / shares | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Non-Performance Based Restricted Stock Units (RSUs) | |||
Number of Restricted Stock Units | |||
Outstanding, beginning of year (in shares) | 347,427 | ||
Granted (in shares) | 133,173 | 128,950 | 172,513 |
Vested (in shares) | (119,147) | ||
Forfeited (in shares) | (19,267) | ||
Outstanding, end of year (in shares) | 342,186 | 347,427 | |
Weighted Average Fair Value per Award | |||
Outstanding, beginning of year (in dollars per share) | $ 44.58 | ||
Granted (in dollars per share) | 58.10 | $ 54.10 | $ 37.98 |
Vested (in dollars per share) | 44.82 | ||
Forfeited (in dollars per share) | 46.88 | ||
Outstanding, end of year (in dollars per share) | $ 49.63 | $ 44.58 | |
Performance Shares | |||
Number of Restricted Stock Units | |||
Outstanding, beginning of year (in shares) | 607,179 | ||
Granted (in shares) | 202,259 | 195,397 | 309,470 |
Vested (in shares) | (278,687) | ||
Forfeited (in shares) | (22,805) | ||
Change in Units Based on Performance Achieved (in shares) | 78,845 | ||
Outstanding, end of year (in shares) | 586,791 | 607,179 | |
Weighted Average Fair Value per Award | |||
Outstanding, beginning of year (in dollars per share) | $ 48.60 | ||
Granted (in dollars per share) | 64.28 | $ 65.39 | $ 39.19 |
Vested (in dollars per share) | 42.58 | ||
Forfeited (in dollars per share) | 57.20 | ||
Change in Units Based on Performance Achieved (in dollars per share) | 40.69 | ||
Outstanding, end of year (in dollars per share) | $ 55.46 | $ 48.60 |
Capitalization and Short-Term_7
Capitalization and Short-Term Borrowings - Weighted Average Assumptions Used in Estimating Fair Value (Details) - Performance Shares | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Risk-Free Interest Rate | 4.03% | 0.85% | 0.19% |
Remaining Term at Date of Grant (Years) | 2 years 9 months 18 days | 2 years 9 months 18 days | 2 years 9 months 18 days |
Expected Volatility | 31.60% | 29.70% | 29.10% |
Capitalization and Short-Term_8
Capitalization and Short-Term Borrowings - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||||
Sep. 30, 2023 | Sep. 30, 2022 | May 18, 2023 | Mar. 31, 2023 | Nov. 25, 2022 | Feb. 24, 2021 | ||
Debt Instrument [Line Items] | |||||||
Total Long-Term Debt | $ 2,400,000 | $ 2,649,000 | |||||
Less Unamortized Discount and Debt Issuance Costs | 15,515 | 16,591 | |||||
Less Current Portion | [1] | 0 | 549,000 | ||||
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs | 2,384,485 | 2,083,409 | |||||
7.4% due June 2025 | |||||||
Debt Instrument [Line Items] | |||||||
Medium-Term Notes | [2] | $ 50,000 | $ 99,000 | ||||
Long-term debt, interest rate | 7.40% | 7.40% | |||||
2.95% to 5.50% due July 2025 to March 2031 | |||||||
Debt Instrument [Line Items] | |||||||
Notes | [2],[3],[4] | $ 2,350,000 | $ 2,550,000 | ||||
Percentage of principal amount | 101% | 101% | |||||
4.75% Notes Due September 1, 2028 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 4.75% | ||||||
Long-term debt, face value | $ 300,000 | ||||||
Maximum interest rate adjustment | 2% | ||||||
3.95% Notes Due September 15, 2027 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 3.95% | ||||||
Long-term debt, face value | $ 300,000 | ||||||
Maximum interest rate adjustment | 2% | ||||||
2.95% Notes Due March 1, 2031 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 2.95% | 2.95% | |||||
Long-term debt, face value | $ 500,000 | $ 500,000 | |||||
Maximum interest rate adjustment | 2% | ||||||
5.50% Notes Due January 15, 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 5.50% | ||||||
Long-term debt, face value | $ 500,000 | ||||||
Maximum interest rate adjustment | 2% | ||||||
5.50% Notes Due October 1, 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 5.50% | 5.50% | |||||
Long-term debt, face value | $ 300,000 | $ 300,000 | |||||
3.75% Notes Due March 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Less Current Portion | $ 500,000 | ||||||
Long-term debt, interest rate | 3.75% | 3.75% | 3.75% | ||||
Debt instrument redeemed | $ 350,000 | $ 150,000 | |||||
7.395% Notes Due March 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Less Current Portion | $ 49,000 | ||||||
Long-term debt, interest rate | 7.395% | 7.395% | |||||
Debt instrument redeemed | $ 49,000 | ||||||
Minimum | 2.95% to 5.50% due July 2025 to March 2031 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 2.95% | 2.95% | |||||
Maximum | 2.95% to 5.50% due July 2025 to March 2031 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 5.50% | 5.50% | |||||
Maximum | 5.50% Notes Due January 15, 2026 | |||||||
Debt Instrument [Line Items] | |||||||
Long-term debt, interest rate | 7.50% | ||||||
[1]None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed $150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed below. In March 2023, the Company redeemed the remaining $350.0 million of the 3.75% notes as well as the $49.0 million of 7.395% notes[2]The Medium-Term Notes and Notes are unsecured.[3]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.[4]The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes, $500.0 million of 2.95% notes and $300.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. |
Fair Value Measurements - Recur
Fair Value Measurements - Recurring Fair Value Measures of Assets and Liabilities (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 | ||
Assets: | ||||||
Cash Equivalents — Money Market Mutual Funds | [1] | $ 39,332 | $ 35,015 | |||
Hedging Collateral Deposits | $ 0 | $ 91,670 | [1] | $ 88,610 | $ 0 | |
Derivative Financial Instruments: | ||||||
Derivative Asset, Statement of Financial Position [Extensible Enumeration] | Fair Value of Derivative Financial Instruments | Fair Value of Derivative Financial Instruments | ||||
Total Assets | [1] | $ 121,553 | $ 188,714 | |||
Derivative Financial Instruments: | ||||||
Derivative Liability, Statement of Financial Position [Extensible Enumeration] | Fair Value of Derivative Financial Instruments | Fair Value of Derivative Financial Instruments | ||||
Total Liabilities | [1] | $ 31,009 | $ 785,659 | |||
Total Net Assets/(Liabilities) | [1] | 90,544 | (596,945) | |||
Over the Counter Swaps — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | 28,292 | 999 | |||
Derivative Financial Instruments: | ||||||
Derivative Liability | [1] | 30,803 | 513,286 | |||
Over the Counter No Cost Collars — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | 16,221 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | [1] | 205 | 270,453 | |||
Contingent Consideration for Asset Sale | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | 7,277 | 8,176 | |||
Foreign Currency Contracts | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | (1,303) | 0 | |||
Derivative Financial Instruments: | ||||||
Derivative Liability | [1] | 1 | 1,920 | |||
Balanced Equity Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | [1] | 15,837 | 19,506 | |||
Fixed Income Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | [1] | 15,897 | 33,348 | |||
Level 1 | ||||||
Assets: | ||||||
Cash Equivalents — Money Market Mutual Funds | 39,332 | 35,015 | ||||
Hedging Collateral Deposits | 91,670 | |||||
Derivative Financial Instruments: | ||||||
Total Assets | 71,066 | 179,539 | ||||
Derivative Financial Instruments: | ||||||
Total Liabilities | 0 | 0 | ||||
Total Net Assets/(Liabilities) | 71,066 | 179,539 | ||||
Level 1 | Over the Counter Swaps — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | 0 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 0 | 0 | ||||
Level 1 | Over the Counter No Cost Collars — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | |||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 0 | 0 | ||||
Level 1 | Contingent Consideration for Asset Sale | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | 0 | ||||
Level 1 | Foreign Currency Contracts | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | 0 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 0 | 0 | ||||
Level 1 | Balanced Equity Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | 15,837 | 19,506 | ||||
Level 1 | Fixed Income Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | 15,897 | 33,348 | ||||
Level 2 | ||||||
Assets: | ||||||
Cash Equivalents — Money Market Mutual Funds | 0 | 0 | ||||
Hedging Collateral Deposits | 0 | |||||
Derivative Financial Instruments: | ||||||
Total Assets | 104,193 | 13,481 | ||||
Derivative Financial Instruments: | ||||||
Total Liabilities | 84,715 | 789,965 | ||||
Total Net Assets/(Liabilities) | 19,478 | (776,484) | ||||
Level 2 | Over the Counter Swaps — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 65,800 | 5,177 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 68,311 | 517,464 | ||||
Level 2 | Over the Counter No Cost Collars — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 30,966 | |||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 14,950 | 270,453 | ||||
Level 2 | Contingent Consideration for Asset Sale | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 7,277 | 8,176 | ||||
Level 2 | Foreign Currency Contracts | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 150 | 128 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 1,454 | 2,048 | ||||
Level 2 | Balanced Equity Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | 0 | 0 | ||||
Level 2 | Fixed Income Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | 0 | 0 | ||||
Level 3 | ||||||
Assets: | ||||||
Cash Equivalents — Money Market Mutual Funds | 0 | 0 | ||||
Hedging Collateral Deposits | 0 | |||||
Derivative Financial Instruments: | ||||||
Total Assets | 0 | 0 | ||||
Derivative Financial Instruments: | ||||||
Total Liabilities | 0 | 0 | ||||
Total Net Assets/(Liabilities) | 0 | 0 | ||||
Level 3 | Over the Counter Swaps — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | 0 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 0 | 0 | ||||
Level 3 | Over the Counter No Cost Collars — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | |||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 0 | 0 | ||||
Level 3 | Contingent Consideration for Asset Sale | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | 0 | ||||
Level 3 | Foreign Currency Contracts | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | 0 | 0 | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | 0 | 0 | ||||
Level 3 | Balanced Equity Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | 0 | 0 | ||||
Level 3 | Fixed Income Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | 0 | 0 | ||||
Netting Adjustments | ||||||
Assets: | ||||||
Cash Equivalents — Money Market Mutual Funds | [1] | 0 | 0 | |||
Hedging Collateral Deposits | [1] | 0 | ||||
Derivative Financial Instruments: | ||||||
Total Assets | [1] | (53,706) | (4,306) | |||
Derivative Financial Instruments: | ||||||
Total Liabilities | [1] | (53,706) | (4,306) | |||
Total Net Assets/(Liabilities) | [1] | 0 | 0 | |||
Netting Adjustments | Over the Counter Swaps — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | (37,508) | (4,178) | |||
Derivative Financial Instruments: | ||||||
Derivative Liability | [1] | (37,508) | (4,178) | |||
Netting Adjustments | Over the Counter No Cost Collars — Gas | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | (14,745) | ||||
Derivative Financial Instruments: | ||||||
Derivative Liability | [1] | (14,745) | 0 | |||
Netting Adjustments | Contingent Consideration for Asset Sale | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | 0 | 0 | |||
Netting Adjustments | Foreign Currency Contracts | ||||||
Derivative Financial Instruments: | ||||||
Derivative Asset | [1] | (1,453) | (128) | |||
Derivative Financial Instruments: | ||||||
Derivative Liability | [1] | (1,453) | (128) | |||
Netting Adjustments | Balanced Equity Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | [1] | 0 | 0 | |||
Netting Adjustments | Fixed Income Mutual Fund | ||||||
Derivative Financial Instruments: | ||||||
Other Investments | [1] | $ 0 | $ 0 | |||
[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. |
Fair Value Measurements - Narra
Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 | |
Fair Value Disclosures [Abstract] | |||||
Hedging collateral deposits | $ 0 | $ 91,670 | [1] | $ 88,610 | $ 0 |
[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. |
Financial Instruments - Long-Te
Financial Instruments - Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Financial Instruments, Owned, at Fair Value, by Type, Alternative [Abstract] | ||
Carrying Amount | $ 2,384,485 | $ 2,632,409 |
Fair Value | $ 2,210,478 | $ 2,453,209 |
Financial Instruments - Other I
Financial Instruments - Other Investments (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 |
Summary of Investment Holdings [Line Items] | ||
Life Insurance Contracts | $ 42,242 | $ 42,171 |
Total other investments | 73,976 | 95,025 |
Equity Mutual Fund | ||
Summary of Investment Holdings [Line Items] | ||
Mutual Funds | 15,837 | 19,506 |
Fixed Income Mutual Fund | ||
Summary of Investment Holdings [Line Items] | ||
Mutual Funds | $ 15,897 | $ 33,348 |
Financial Instruments - Narrati
Financial Instruments - Narrative (Details) Bcf in Billions | 12 Months Ended | 36 Months Ended | |||||
Sep. 30, 2023 USD ($) counterparty Bcf | Dec. 31, 2025 USD ($) payment | Sep. 30, 2022 USD ($) | Jun. 30, 2022 USD ($) | Sep. 30, 2021 USD ($) | Sep. 30, 2020 USD ($) | ||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Foreign currency forward contracts duration maximum | 7 years | ||||||
After tax net hedging gains in accumulated other comprehensive income (loss) | $ 4,600,000 | ||||||
After tax net hedging gains reclassified within twelve months | 11,500,000 | ||||||
Fair market value of derivative liability with a credit-risk related contingency | 7,700,000 | ||||||
Hedging collateral deposits | 0 | $ 91,670,000 | [1] | $ 88,610,000 | $ 0 | ||
Foreign Currency Contracts | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Hedging notional amount of forecasted transportation costs | $ 56,900,000 | ||||||
Over the Counter Swaps, No Cost Collars and Foreign Currency Forward Contracts | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Number of counterparties in which the company holds over-the-counter swap positions | counterparty | 19 | ||||||
Number of counterparties in net gain position | counterparty | 11 | ||||||
Credit risk exposure per counterparty | $ 3,900,000 | ||||||
Maximum credit risk exposure per counterparty | 16,100,000 | ||||||
Collateral received by company | $ 0 | ||||||
Number of counterparties with a common credit-risk related contingency | counterparty | 16 | ||||||
Hedging collateral deposits | $ 0 | ||||||
California Asset Sale | Forecast | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Maximum annual contingent payment | $ 10,000,000 | ||||||
Amount of each incremental contingency payment | 1,000,000 | ||||||
Incremental price, exceeding ICE Brent Average Price (in dollars per barrel) | 1 | ||||||
California Asset Sale | Present Value of Contingent Consideration | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Value of contingent consideration received from sale of assets | 7,300,000 | $ 8,200,000 | $ 12,600,000 | ||||
California Asset Sale | Mark to Market of Contingent Consideration | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Mark-to-market adjustment for contingent consideration | $ 900,000 | ||||||
California Asset Sale | Minimum | Forecast | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
ICE Brent Average (in dollars per barrel) | $ 95 | ||||||
California Asset Sale | Maximum | Forecast | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Number of annual contingent payments | payment | 3 | ||||||
ICE Brent Average (in dollars per barrel) | $ 105 | ||||||
Cash Flow Hedges | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Hedge duration | 5 years | ||||||
Cash Flow Hedges | Natural Gas Bcf | |||||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||||
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas (in Bcf) | Bcf | 411.3 | ||||||
[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. |
Financial Instruments - Schedul
Financial Instruments - Schedule of Derivatives Financial Instruments Designated and Qualifying as Cash Flow Hedges on the Statements of Financial Performance (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) | $ 708,206 | $ (1,050,831) | $ (665,371) | |
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income | (88,656) | (882,581) | $ (83,711) | |
Commodity Contracts | California Asset Sale | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Derivative Loss Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for Discontinuance of Cash Flow Hedges | 44,600 | |||
Operating Revenue | Commodity Contracts | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) | 708,234 | (1,048,200) | ||
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income | (88,015) | (882,594) | [1] | |
Operating Revenue | Foreign Currency Contracts | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) | (28) | (2,631) | ||
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income | $ (641) | $ 13 | ||
[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 $44.6 million was reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet to Operating Revenues on the Consolidated Statement of Income for the year ended September 30, 2022. This loss is included in the reported reclassification amounts. |
Retirement Plan and Other Pos_3
Retirement Plan and Other Post-Retirement Benefits - Narrative (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Net Periodic Benefit Cost (Income) | $ 8,300 | $ 8,900 | $ 8,300 | |
Accumulated Benefit Obligation | 58,500 | 64,900 | 76,900 | |
Projected benefit obligation | $ 69,500 | $ 77,200 | $ 95,800 | |
Discount rate (as a percent) | 5.91% | 5.49% | 2.15% | |
Rate of compensation increase (as a percent) | 8% | 8% | 8% | |
Pre-tax decrease to accumulated other comprehensive income | $ 788,876 | $ (154,986) | $ (547,569) | |
Defined Benefit Plan, Tax Status [Extensible Enumeration] | Non-Qualified Benefit Plans | Non-Qualified Benefit Plans | Non-Qualified Benefit Plans | |
Other Accruals and Current Liabilities | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligation | $ 13,100 | $ 17,500 | $ 15,400 | |
Other Liabilities | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Projected benefit obligation | 56,400 | 59,700 | 80,400 | |
Retirement Savings Account | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Costs recognized | 5,700 | 5,300 | 4,800 | |
Tax-Deferred Savings Plans | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Costs recognized | 8,200 | 7,800 | 7,200 | |
Retirement Plan | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Net Periodic Benefit Cost (Income) | (4,622) | 23,087 | 24,911 | |
Accumulated Benefit Obligation | 751,912 | 793,555 | 1,060,659 | |
Projected benefit obligation | $ 768,750 | $ 813,828 | $ 1,098,456 | $ 1,139,105 |
Discount rate (as a percent) | 5.99% | 5.57% | 2.75% | |
Rate of compensation increase (as a percent) | 4.60% | 4.60% | 4.70% | |
Expected future benefit payments in 2024 | $ 67,900 | |||
Expected future benefit payments in 2025 | 67,400 | |||
Expected future benefit payments in 2026 | 66,900 | |||
Expected future benefit payments in 2027 | 66,200 | |||
Expected future benefit payments 2028 | 65,500 | |||
Expected future benefit payments 2029 through 2033 | 310,400 | |||
Employer contributions | $ 0 | $ 20,400 | $ 20,000 | |
Expected long term rate of return on plan assets (as a percent) | 6.90% | 5.20% | 6% | |
Retirement Plan | Effective Fiscal 2024 | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected long term rate of return on plan assets (as a percent) | 7.40% | |||
Retirement Plan | Minimum | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Annual contribution expected for next fiscal year | $ 0 | |||
Retirement Plan | Maximum | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Annual contribution expected for next fiscal year | 5,000 | |||
Retirement Plan | Other Actuarial Experience | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | 1,800 | |||
Retirement Plan | Discount Rate Change | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | (28,400) | $ (262,200) | $ (11,200) | |
Retirement Plan | Mortality Improvement Projection Scale | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | (700) | |||
Non-Qualified Benefit Plans, Other Post-Retirement Benefit Plan and Retirement Plan | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase to other regulatory assets | 28,700 | |||
Pre-tax decrease to accumulated other comprehensive income | 8,000 | |||
Other Post-Retirement Benefits | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Net Periodic Benefit Cost (Income) | (3,404) | (5,664) | 10,371 | |
Projected benefit obligation | $ 274,278 | $ 299,283 | $ 431,213 | $ 476,722 |
Discount rate (as a percent) | 5.99% | 5.56% | 2.76% | |
Rate of compensation increase (as a percent) | 4.60% | 4.60% | 4.70% | |
Expected future benefit payments in 2024 | $ 25,334 | |||
Expected future benefit payments in 2025 | 25,479 | |||
Expected future benefit payments in 2026 | 25,466 | |||
Expected future benefit payments in 2027 | 25,389 | |||
Expected future benefit payments 2028 | 25,260 | |||
Expected future benefit payments 2029 through 2033 | 120,390 | |||
Employer contributions | $ 235 | $ 3,082 | $ 3,068 | |
Expected long term rate of return on plan assets (as a percent) | 5.70% | 5.20% | 5.40% | |
Other Post-Retirement Benefits | Effective Fiscal 2024 | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Expected long term rate of return on plan assets (as a percent) | 6% | |||
Other Post-Retirement Benefits | Other Actuarial Experience | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | $ (12,900) | $ (22,500) | $ (26,600) | |
Other Post-Retirement Benefits | Discount Rate Change | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | (10,700) | (98,900) | (2,500) | |
Other Post-Retirement Benefits | Mortality Improvement Projection Scale | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | (400) | $ 1,100 | (2,000) | |
Other Post-Retirement Benefits | Health Care Cost Trend Rates | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Increase (decrease) in benefit obligation | 3,200 | $ (3,700) | ||
Other Than VEBA Trust And 401(h) Accounts | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Employer contributions | $ 200 |
Retirement Plan and Other Pos_4
Retirement Plan and Other Post-Retirement Benefits - Schedule of Benefit Obligations, Plan Assets and Funded Status (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Change in Benefit Obligation | ||||
Benefit Obligation at Beginning of Period | $ 77,200 | $ 95,800 | ||
Benefit Obligation at End of Period | 69,500 | 77,200 | $ 95,800 | |
Amounts Recognized in the Balance Sheets Consist of: | ||||
Non-Current Assets | 200,301 | 196,597 | ||
Accumulated Benefit Obligation | $ 58,500 | $ 64,900 | $ 76,900 | |
Weighted Average Assumptions Used to Determine Benefit Obligation | ||||
Discount rate (as a percent) | 5.91% | 5.49% | 2.15% | |
Rate of compensation increase (as a percent) | 8% | 8% | 8% | |
Components of Net Periodic Benefit Cost | ||||
Net Periodic Benefit Cost (Income) | $ 8,300 | $ 8,900 | $ 8,300 | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost | ||||
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration] | Other Income (Deductions) | Other Income (Deductions) | Other Income (Deductions) | |
Amortization period | 10 years | |||
Retirement Plan | ||||
Change in Benefit Obligation | ||||
Benefit Obligation at Beginning of Period | $ 813,828 | $ 1,098,456 | $ 1,139,105 | |
Service Cost | 5,187 | 8,758 | 9,865 | |
Interest Cost | 42,516 | 22,827 | 21,686 | |
Plan Participants’ Contributions | 0 | 0 | 0 | |
Retiree Drug Subsidy Receipts | 0 | 0 | 0 | |
Actuarial Gain | (27,313) | (251,173) | (8,141) | |
Benefits Paid | (65,468) | (65,040) | (64,059) | |
Benefit Obligation at End of Period | 768,750 | 813,828 | 1,098,456 | |
Change in Plan Assets | ||||
Fair Value of Assets at Beginning of Period | 845,205 | 1,095,729 | 1,016,796 | |
Actual Return on Plan Assets | 4,975 | (205,884) | 122,992 | |
Employer Contributions | 0 | 20,400 | 20,000 | |
Plan Participants’ Contributions | 0 | 0 | 0 | |
Benefits Paid | (65,468) | (65,040) | (64,059) | |
Fair Value of Assets at End of Period | 784,712 | 845,205 | 1,095,729 | |
Net Amount Recognized at End of Period (Funded Status) | 15,962 | 31,377 | (2,727) | |
Amounts Recognized in the Balance Sheets Consist of: | ||||
Non-Current Liabilities | 0 | 0 | (2,727) | |
Non-Current Assets | 15,962 | 31,377 | 0 | |
Net Amount Recognized at End of Period | 15,962 | 31,377 | (2,727) | |
Accumulated Benefit Obligation | $ 751,912 | $ 793,555 | $ 1,060,659 | |
Weighted Average Assumptions Used to Determine Benefit Obligation | ||||
Discount rate (as a percent) | 5.99% | 5.57% | 2.75% | |
Rate of compensation increase (as a percent) | 4.60% | 4.60% | 4.70% | |
Components of Net Periodic Benefit Cost | ||||
Service Cost | $ 5,187 | $ 8,758 | $ 9,865 | |
Interest Cost | 42,516 | 22,827 | 21,686 | |
Expected Return on Plan Assets | (66,593) | (52,294) | (58,148) | |
Amortization of Prior Service Cost (Credit) | 436 | 537 | 631 | |
Recognition of Actuarial (Gain) Loss | [1] | (7,680) | 26,405 | 36,814 |
Net Amortization and Deferral for Regulatory Purposes | 21,512 | 16,854 | 14,063 | |
Net Periodic Benefit Cost (Income) | $ (4,622) | $ 23,087 | $ 24,911 | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost | ||||
Effective Discount Rate for Benefit Obligations (as a percent) | 5.57% | 2.75% | 2.66% | |
Effective Rate for Interest on Benefit Obligations (as a percent) | 5.45% | 2.14% | 1.96% | |
Effective Discount Rate for Service Cost (as a percent) | 5.49% | 2.95% | 3.01% | |
Effective Rate for Interest on Service Cost (as a percent) | 5.53% | 2.70% | 2.60% | |
Expected Return on Plan Assets (as a percent) | 6.90% | 5.20% | 6% | |
Rate of Compensation Increase (as a percent) | 4.60% | 4.70% | 4.70% | |
Other Post-Retirement Benefits | ||||
Change in Benefit Obligation | ||||
Benefit Obligation at Beginning of Period | $ 299,283 | $ 431,213 | $ 476,722 | |
Service Cost | 587 | 1,328 | 1,602 | |
Interest Cost | 15,648 | 9,066 | 9,303 | |
Plan Participants’ Contributions | 3,297 | 3,271 | 3,216 | |
Retiree Drug Subsidy Receipts | 2,969 | 312 | 1,244 | |
Actuarial Gain | (20,789) | (120,276) | (34,729) | |
Benefits Paid | (26,717) | (25,631) | (26,145) | |
Benefit Obligation at End of Period | 274,278 | 299,283 | 431,213 | |
Change in Plan Assets | ||||
Fair Value of Assets at Beginning of Period | 461,438 | 575,565 | 547,885 | |
Actual Return on Plan Assets | 17,449 | (94,849) | 47,541 | |
Employer Contributions | 235 | 3,082 | 3,068 | |
Plan Participants’ Contributions | 3,297 | 3,271 | 3,216 | |
Benefits Paid | (26,717) | (25,631) | (26,145) | |
Fair Value of Assets at End of Period | 455,702 | 461,438 | 575,565 | |
Net Amount Recognized at End of Period (Funded Status) | 181,424 | 162,155 | 144,352 | |
Amounts Recognized in the Balance Sheets Consist of: | ||||
Non-Current Liabilities | (2,915) | (3,065) | (4,799) | |
Non-Current Assets | 184,339 | 165,220 | 149,151 | |
Net Amount Recognized at End of Period | $ 181,424 | $ 162,155 | $ 144,352 | |
Weighted Average Assumptions Used to Determine Benefit Obligation | ||||
Discount rate (as a percent) | 5.99% | 5.56% | 2.76% | |
Rate of compensation increase (as a percent) | 4.60% | 4.60% | 4.70% | |
Components of Net Periodic Benefit Cost | ||||
Service Cost | $ 587 | $ 1,328 | $ 1,602 | |
Interest Cost | 15,648 | 9,066 | 9,303 | |
Expected Return on Plan Assets | (25,612) | (29,359) | (28,964) | |
Amortization of Prior Service Cost (Credit) | (429) | (429) | (429) | |
Recognition of Actuarial (Gain) Loss | [1] | (8,755) | (7,610) | 849 |
Net Amortization and Deferral for Regulatory Purposes | 15,157 | 21,340 | 28,010 | |
Net Periodic Benefit Cost (Income) | $ (3,404) | $ (5,664) | $ 10,371 | |
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost | ||||
Effective Discount Rate for Benefit Obligations (as a percent) | 5.56% | 2.76% | 2.71% | |
Effective Rate for Interest on Benefit Obligations (as a percent) | 5.45% | 2.17% | 2.01% | |
Effective Discount Rate for Service Cost (as a percent) | 5.35% | 3% | 3.20% | |
Effective Rate for Interest on Service Cost (as a percent) | 5.47% | 2.93% | 2.98% | |
Expected Return on Plan Assets (as a percent) | 5.70% | 5.20% | 5.40% | |
Rate of Compensation Increase (as a percent) | 4.60% | 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. |
Retirement Plan and Other Pos_5
Retirement Plan and Other Post-Retirement Benefits - Schedule of Cumulative Amounts Recognized in AOCI (Loss) and Regulatory Assets and Liabilities (Details) $ in Thousands | 12 Months Ended | |
Sep. 30, 2023 USD ($) | [1] | |
Non-Qualified Benefit Plans | ||
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities | ||
Net Actuarial Gain (Loss) | $ (17,286) | |
Prior Service (Cost) Credit | 0 | |
Net Amount Recognized | (17,286) | |
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities | ||
Increase in Actuarial Gain (Loss), excluding amortization | (2,139) | [2] |
Change due to Amortization of Actuarial (Gain) Loss | 3,572 | |
Prior Service (Cost) Credit | 0 | |
Net Change | 1,433 | |
Retirement Plan | Qualified Plan | ||
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities | ||
Net Actuarial Gain (Loss) | (128,118) | |
Prior Service (Cost) Credit | (2,036) | |
Net Amount Recognized | (130,154) | |
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities | ||
Increase in Actuarial Gain (Loss), excluding amortization | (34,305) | [2] |
Change due to Amortization of Actuarial (Gain) Loss | (7,680) | |
Prior Service (Cost) Credit | 436 | |
Net Change | (41,549) | |
Other Post-Retirement Benefits | Qualified Plan | ||
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities | ||
Net Actuarial Gain (Loss) | 18,440 | |
Prior Service (Cost) Credit | 1,115 | |
Net Amount Recognized | 19,555 | |
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities | ||
Increase in Actuarial Gain (Loss), excluding amortization | 12,626 | [2] |
Change due to Amortization of Actuarial (Gain) Loss | (8,755) | |
Prior Service (Cost) Credit | (429) | |
Net Change | $ 3,442 | |
[1]Amounts presented are shown before recognizing deferred taxes.[2]Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial Loss amounts presented in the Change in Benefit Obligation. |
Retirement Plan and Other Pos_6
Retirement Plan and Other Post-Retirement Benefits - Schedule of Expected Benefit Payments (Details) - Other Post-Retirement Benefits $ in Thousands | Sep. 30, 2023 USD ($) |
Benefit Payments | |
2024 | $ 25,334 |
2025 | 25,479 |
2026 | 25,466 |
2027 | 25,389 |
2028 | 25,260 |
2029 through 2033 | 120,390 |
Subsidy Receipts | |
2024 | (1,787) |
2025 | (1,881) |
2026 | (1,969) |
2027 | (2,039) |
2028 | (2,091) |
2029 through 2033 | $ (10,896) |
Retirement Plan and Other Pos_7
Retirement Plan and Other Post-Retirement Benefits - Schedule of Health Care Cost Trend Rates (Details) | 12 Months Ended | |||||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||||
Retirement Benefits [Abstract] | ||||||
Rate of Medical Cost Increase for Pre Age 65 Participants | 6.25% | [1] | 5.30% | [2] | 5.38% | [2] |
Rate of Medical Cost Increase for Post Age 65 Participants | 5% | [1] | 4.84% | [2] | 4.84% | [2] |
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits | 6.85% | [1] | 6.29% | [2] | 6.53% | [2] |
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement | 5% | [1] | 4.84% | [2] | 4.84% | [2] |
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy | 6.60% | [1] | 5.96% | [2] | 6.15% | [2] |
Ultimate health care trend rate | 4% | 4% | 4% | |||
[1]It was assumed that this rate would gradually decline to 4% by 2048.[2]It was assumed that this rate would gradually decline to 4% by 2046. |
Retirement Plan and Other Pos_8
Retirement Plan and Other Post-Retirement Benefits - Schedule of Fair Value of Plan Assets (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 | |
Retirement Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Total plan assets | $ 784,712 | $ 845,205 | $ 1,095,729 | $ 1,016,796 | |
Retirement Plan | Total Retirement Plan Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 854,956 | 912,172 | |||
Retirement Plan | Domestic Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [1] | 37,611 | 41,633 | ||
Retirement Plan | International Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [2] | 0 | 1,363 | ||
Retirement Plan | Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [3] | 36,088 | 44,434 | ||
Retirement Plan | Domestic Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [4] | 612,820 | 658,833 | ||
Retirement Plan | International Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [5] | 7,778 | 7,782 | ||
Retirement Plan | Real Estate | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [6] | 123,859 | 140,739 | ||
Retirement Plan | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 36,800 | 17,388 | |||
Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 781,637 | 839,128 | |||
Retirement Plan | Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 3,075 | 6,077 | |||
Retirement Plan | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 73,319 | 73,044 | |||
Other Post-Retirement Benefits | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Total plan assets | 455,702 | 461,438 | $ 575,565 | $ 547,885 | |
Other Post-Retirement Benefits | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 9,637 | 10,635 | |||
Other Post-Retirement Benefits | Total VEBA Trust Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 371,588 | 385,770 | |||
Other Post-Retirement Benefits | Collective Trust Funds — Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 72,285 | 104,554 | |||
Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 289,666 | 270,581 | |||
Other Post-Retirement Benefits | Total Investments (including 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 444,907 | 458,814 | |||
Other Post-Retirement Benefits | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 73,319 | 73,044 | |||
Other Post-Retirement Benefits | Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 10,795 | 2,624 | |||
Level 1 | Retirement Plan | Total Retirement Plan Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 37,611 | 41,633 | |||
Level 1 | Retirement Plan | Domestic Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [1] | 37,611 | 41,633 | ||
Level 1 | Retirement Plan | International Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [2] | 0 | 0 | ||
Level 1 | Retirement Plan | Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [3] | 0 | 0 | ||
Level 1 | Retirement Plan | Domestic Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [4] | 0 | 0 | ||
Level 1 | Retirement Plan | International Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [5] | 0 | 0 | ||
Level 1 | Retirement Plan | Real Estate | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [6] | 0 | 0 | ||
Level 1 | Retirement Plan | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 1 | Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 34,399 | 38,323 | |||
Level 1 | Retirement Plan | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 3,212 | 3,310 | |||
Level 1 | Other Post-Retirement Benefits | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 1 | Other Post-Retirement Benefits | Total VEBA Trust Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 289,666 | 270,581 | |||
Level 1 | Other Post-Retirement Benefits | Collective Trust Funds — Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 1 | Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 289,666 | 270,581 | |||
Level 1 | Other Post-Retirement Benefits | Total Investments (including 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 292,878 | 273,891 | |||
Level 1 | Other Post-Retirement Benefits | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 3,212 | 3,310 | |||
Level 2 | Retirement Plan | Total Retirement Plan Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 564,282 | 587,388 | |||
Level 2 | Retirement Plan | Domestic Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [1] | 0 | 0 | ||
Level 2 | Retirement Plan | International Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [2] | 0 | 0 | ||
Level 2 | Retirement Plan | Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [3] | 0 | 0 | ||
Level 2 | Retirement Plan | Domestic Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [4] | 556,504 | 579,606 | ||
Level 2 | Retirement Plan | International Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [5] | 7,778 | 7,782 | ||
Level 2 | Retirement Plan | Real Estate | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [6] | 0 | 0 | ||
Level 2 | Retirement Plan | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 2 | Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 516,098 | 540,694 | |||
Level 2 | Retirement Plan | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 48,184 | 46,694 | |||
Level 2 | Other Post-Retirement Benefits | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 2 | Other Post-Retirement Benefits | Total VEBA Trust Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 2 | Other Post-Retirement Benefits | Collective Trust Funds — Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 2 | Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 2 | Other Post-Retirement Benefits | Total Investments (including 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 48,184 | 46,694 | |||
Level 2 | Other Post-Retirement Benefits | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 48,184 | 46,694 | |||
Level 3 | Retirement Plan | Total Retirement Plan Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Retirement Plan | Domestic Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [1] | 0 | 0 | ||
Level 3 | Retirement Plan | International Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [2] | 0 | 0 | ||
Level 3 | Retirement Plan | Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [3] | 0 | 0 | ||
Level 3 | Retirement Plan | Domestic Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [4] | 0 | 0 | ||
Level 3 | Retirement Plan | International Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [5] | 0 | 0 | ||
Level 3 | Retirement Plan | Real Estate | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [6] | 0 | 0 | ||
Level 3 | Retirement Plan | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Retirement Plan | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Other Post-Retirement Benefits | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Other Post-Retirement Benefits | Total VEBA Trust Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Other Post-Retirement Benefits | Collective Trust Funds — Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Other Post-Retirement Benefits | Total Investments (including 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Level 3 | Other Post-Retirement Benefits | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | 0 | 0 | |||
Measured at NAV | Retirement Plan | Total Retirement Plan Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [7] | 253,063 | 283,151 | ||
Measured at NAV | Retirement Plan | Domestic Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [1],[7] | 0 | 0 | ||
Measured at NAV | Retirement Plan | International Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [2],[7] | 0 | 1,363 | ||
Measured at NAV | Retirement Plan | Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [3],[7] | 36,088 | 44,434 | ||
Measured at NAV | Retirement Plan | Domestic Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [4],[7] | 56,316 | 79,227 | ||
Measured at NAV | Retirement Plan | International Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [5],[7] | 0 | 0 | ||
Measured at NAV | Retirement Plan | Real Estate | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [6],[7] | 123,859 | 140,739 | ||
Measured at NAV | Retirement Plan | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [7] | 36,800 | 17,388 | ||
Measured at NAV | Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [7] | 231,140 | 260,111 | ||
Measured at NAV | Retirement Plan | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [7] | 21,923 | 23,040 | ||
Measured at NAV | Other Post-Retirement Benefits | Cash Held in Collective Trust Funds | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [8] | 9,637 | 10,635 | ||
Measured at NAV | Other Post-Retirement Benefits | Total VEBA Trust Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [8] | 81,922 | 115,189 | ||
Measured at NAV | Other Post-Retirement Benefits | Collective Trust Funds — Global Equities | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [8] | 72,285 | 104,554 | ||
Measured at NAV | Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [8] | 0 | 0 | ||
Measured at NAV | Other Post-Retirement Benefits | Total Investments (including 401(h) Investments) | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [8] | 103,845 | 138,229 | ||
Measured at NAV | Other Post-Retirement Benefits | 401(h) Investments | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Plan assets, subtotals | [8] | $ 21,923 | $ 23,040 | ||
[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]Real Estate consists of investments held in a collective trust fund and a real estate investment trust.[7]Reflects the authoritative guidance related to investments measured at net asset value (NAV).[8]Reflects the authoritative guidance related to investments measured at net asset value (NAV). |
Retirement Plan and Other Pos_9
Retirement Plan and Other Post-Retirement Benefits - Schedule of Significant Unobservable Input Changes in Plan Assets (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Sep. 30, 2023 | Sep. 30, 2022 | |
Retirement Plan | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, Beginning of Year | $ 0 | $ 295 |
Unrealized Gains/(Losses) | 0 | 216 |
Sales | 0 | (511) |
Balance, End of Year | 0 | 0 |
Retirement Plan | Real Estate | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, Beginning of Year | 0 | 319 |
Unrealized Gains/(Losses) | 0 | 234 |
Sales | 0 | (553) |
Balance, End of Year | 0 | 0 |
Retirement Plan | Excluding 401(h) Investments | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, Beginning of Year | 0 | (24) |
Unrealized Gains/(Losses) | 0 | (18) |
Sales | 0 | 42 |
Balance, End of Year | 0 | 0 |
Other Post-Retirement Benefits | 401(h) Investments | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward] | ||
Balance, Beginning of Year | 0 | 24 |
Unrealized Gains/(Losses) | 0 | 18 |
Sales | 0 | (42) |
Balance, End of Year | $ 0 | $ 0 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Millions | Sep. 30, 2023 USD ($) |
Recorded Unconditional Purchase Obligation [Line Items] | |
Estimate minimum liability for environmental remediation | $ 3.7 |
Project costs | 55.9 |
Future purchase obligation first year | 201.7 |
Future purchase obligation second year | 91.1 |
Future purchase obligation third year | 113.8 |
Future purchase obligation fourth year | 118.3 |
Future purchase obligation fifth year | 121.7 |
Future purchase obligation thereafter | 768.9 |
Pipeline and Storage, Gathering and Utility Segments | |
Recorded Unconditional Purchase Obligation [Line Items] | |
Contract commitments first year | 74.9 |
Contract commitments second year | 8.4 |
Contract commitments third year | 7.2 |
Contract commitments fourth year | 5.9 |
Contract commitments fifth year | 3.3 |
Contract commitments thereafter | 4.7 |
Exploration and Production | |
Recorded Unconditional Purchase Obligation [Line Items] | |
Contract commitments first year | 279.5 |
Contract commitments second year | 185.1 |
Contract commitments third year | $ 47.3 |
Business Segment Information -
Business Segment Information - Narrative (Details) | 12 Months Ended |
Sep. 30, 2023 segment | |
Segment Reporting [Abstract] | |
Number of reportable segments | 4 |
Business Segment Information _2
Business Segment Information - Information By Segment (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | $ 2,173,771 | [2] | $ 2,186,046 | [3] | $ 1,742,659 |
Intersegment Revenues | 0 | 0 | 0 | |||
Interest Income | 11,479 | 6,111 | 4,388 | |||
Interest Expense | 131,886 | 130,357 | 146,357 | |||
Depreciation, Depletion and Amortization | 409,573 | 369,790 | 335,303 | |||
Income Tax Expense (Benefit) | 164,533 | 116,629 | 114,682 | |||
Significant Item: Gain on Sale of Assets | 0 | 12,736 | 51,066 | |||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 0 | 0 | 76,152 | |||
Segment Profit: Net Income (Loss) | 476,866 | 566,021 | 363,647 | |||
Expenditures for Additions to Long-Lived Assets | 1,123,573 | 829,388 | 769,911 | |||
Segment Assets | 8,280,260 | 7,896,262 | 7,464,825 | |||
Operating Revenues | 2,173,771 | 2,186,046 | 1,742,659 | |||
Total Reportable Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating Revenues | 2,510,323 | 2,500,572 | ||||
All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Segment Assets | 4,795 | |||||
Operating Revenues | 0 | 6 | ||||
Corporate | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 0 | [2] | 165 | [3] | 356 |
Corporate and Intersegment Eliminations | ||||||
Segment Reporting Information [Line Items] | ||||||
Intersegment Revenues | (336,552) | (314,697) | (299,688) | |||
Interest Income | (5,662) | (1,024) | 486 | |||
Interest Expense | (15,309) | (6,143) | (3,569) | |||
Depreciation, Depletion and Amortization | 429 | 183 | 179 | |||
Income Tax Expense (Benefit) | (983) | (4,429) | (1,821) | |||
Significant Item: Gain on Sale of Assets | 0 | 0 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 0 | |||||
Segment Profit: Net Income (Loss) | (3,498) | (12,650) | (3,065) | |||
Expenditures for Additions to Long-Lived Assets | 754 | 1,212 | 673 | |||
Segment Assets | (126,633) | (186,281) | (107,405) | |||
Operating Revenues | (336,552) | (314,532) | ||||
Total Reportable Segments | Total Reportable Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 2,173,771 | [2] | 2,185,881 | [3] | 1,741,130 |
Intersegment Revenues | 336,552 | 314,691 | 299,639 | |||
Interest Income | 17,141 | 7,132 | 3,672 | |||
Interest Expense | 147,038 | 136,496 | 149,926 | |||
Depreciation, Depletion and Amortization | 409,144 | 369,607 | 334,730 | |||
Income Tax Expense (Benefit) | 165,680 | 121,055 | 105,065 | |||
Significant Item: Gain on Sale of Assets | 12,736 | 0 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 76,152 | |||||
Segment Profit: Net Income (Loss) | 480,895 | 578,680 | 329,067 | |||
Expenditures for Additions to Long-Lived Assets | 1,122,819 | 828,176 | 769,238 | |||
Segment Assets | 8,402,098 | 8,080,507 | 7,568,084 | |||
Exploration and Production | Total Reportable Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 958,455 | [2] | 1,010,464 | [3] | 836,697 |
Intersegment Revenues | 0 | 0 | 0 | |||
Interest Income | 3,259 | 1,929 | 211 | |||
Interest Expense | 54,317 | 53,401 | 69,662 | |||
Depreciation, Depletion and Amortization | 241,142 | 208,148 | 182,492 | |||
Income Tax Expense (Benefit) | 87,796 | 43,898 | 33,370 | |||
Significant Item: Gain on Sale of Assets | 12,736 | 0 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 76,152 | |||||
Segment Profit: Net Income (Loss) | 232,275 | 306,064 | 101,916 | |||
Expenditures for Additions to Long-Lived Assets | 737,725 | 565,791 | 381,408 | |||
Segment Assets | 2,814,218 | 2,507,541 | 2,286,058 | |||
Operating Revenues | 958,455 | 1,010,464 | ||||
Exploration and Production | Total Reportable Segments | Customer Concentration Risk | Three Customers | Revenue Benchmark | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating Revenues | 850,000 | |||||
Exploration and Production | Total Reportable Segments | Customer Concentration Risk | One Customer | Revenue Benchmark | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating Revenues | 208,000 | |||||
Pipeline and Storage | Total Reportable Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 259,646 | [2] | 265,415 | [3] | 234,397 |
Intersegment Revenues | 119,545 | 111,629 | 109,160 | |||
Interest Income | 7,052 | 2,275 | 1,085 | |||
Interest Expense | 43,499 | 42,492 | 40,976 | |||
Depreciation, Depletion and Amortization | 70,827 | 67,701 | 62,431 | |||
Income Tax Expense (Benefit) | 34,489 | 35,043 | 28,812 | |||
Significant Item: Gain on Sale of Assets | 0 | 0 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 0 | |||||
Segment Profit: Net Income (Loss) | 100,501 | 102,557 | 92,542 | |||
Expenditures for Additions to Long-Lived Assets | 141,877 | 95,806 | 252,316 | |||
Segment Assets | 2,427,214 | 2,394,697 | 2,296,030 | |||
Operating Revenues | 379,191 | 377,044 | ||||
Pipeline and Storage | Total Reportable Segments | Customer Concentration Risk | Three Customers | Revenue Benchmark | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating Revenues | 15,000 | |||||
Pipeline and Storage | Total Reportable Segments | Customer Concentration Risk | One Customer | Revenue Benchmark | ||||||
Segment Reporting Information [Line Items] | ||||||
Operating Revenues | 14,000 | |||||
Gathering | Total Reportable Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 13,891 | [2] | 12,086 | [3] | 3,116 |
Intersegment Revenues | 216,426 | 202,757 | 190,148 | |||
Interest Income | 534 | 198 | 259 | |||
Interest Expense | 14,989 | 16,488 | 17,493 | |||
Depreciation, Depletion and Amortization | 35,725 | 33,998 | 32,350 | |||
Income Tax Expense (Benefit) | 36,128 | 24,949 | 28,876 | |||
Significant Item: Gain on Sale of Assets | 0 | 0 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 0 | |||||
Segment Profit: Net Income (Loss) | 99,724 | 101,111 | 80,274 | |||
Expenditures for Additions to Long-Lived Assets | 103,295 | 55,546 | 34,669 | |||
Segment Assets | 912,923 | 878,796 | 837,729 | |||
Operating Revenues | 230,317 | 214,843 | ||||
Utility | Total Reportable Segments | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 941,779 | [2] | 897,916 | [3] | 666,920 |
Intersegment Revenues | 581 | 305 | 331 | |||
Interest Income | 6,296 | 2,730 | 2,117 | |||
Interest Expense | 34,233 | 24,115 | 21,795 | |||
Depreciation, Depletion and Amortization | 61,450 | 59,760 | 57,457 | |||
Income Tax Expense (Benefit) | 7,267 | 17,165 | 14,007 | |||
Significant Item: Gain on Sale of Assets | 0 | 0 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 0 | |||||
Segment Profit: Net Income (Loss) | 48,395 | 68,948 | 54,335 | |||
Expenditures for Additions to Long-Lived Assets | 139,922 | 111,033 | 100,845 | |||
Segment Assets | 2,247,743 | 2,299,473 | 2,148,267 | |||
Operating Revenues | 942,360 | 898,221 | ||||
All Other | All Other | ||||||
Segment Reporting Information [Line Items] | ||||||
Revenues From External Customers | [1] | 0 | [2] | 0 | [3] | 1,173 |
Intersegment Revenues | 0 | 6 | 49 | |||
Interest Income | 0 | 3 | 230 | |||
Interest Expense | 157 | 4 | 0 | |||
Depreciation, Depletion and Amortization | 0 | 0 | 394 | |||
Income Tax Expense (Benefit) | (164) | 3 | 11,438 | |||
Significant Item: Gain on Sale of Assets | 0 | 51,066 | ||||
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties | 0 | |||||
Segment Profit: Net Income (Loss) | (531) | (9) | 37,645 | |||
Expenditures for Additions to Long-Lived Assets | $ 0 | 0 | 0 | |||
Segment Assets | $ 2,036 | $ 4,146 | ||||
[1]All Revenue from External Customers originated in the United States.[2]Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million of the Company's consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $14 million of the Company's consolidated revenue for the year ended September 30, 2023.[3]Revenues from three customers of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $850 million of the Company's consolidated revenue for the year ended September 30, 2022. These three customers were also customers of the Company's Pipeline and Storage segment, accounting for an additional $15 million of the Company's consolidated revenue for the year ended September 30, 2022. |
Business Segment Information _3
Business Segment Information - Schedule of Long-Lived Assets by Geographical Areas (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 |
United States | |||
Revenues from External Customers and Long-Lived Assets [Line Items] | |||
Long-lived assets | $ 7,865,832 | $ 7,135,131 | $ 6,942,376 |
Supplementary Information for_3
Supplementary Information for Oil and Gas Producing Activities - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | |
Supplementary Information for Oil and Gas Producing Activities Unaudited [Abstract] | |||
Proved Properties | [1] | $ 6,555,088 | $ 5,915,807 |
Unproved Properties | 161,097 | 65,994 | |
Capitalized costs relating to oil and gas producing activities, gross | 6,716,185 | 5,981,801 | |
Less — Accumulated Depreciation, Depletion and Amortization | 4,269,959 | 4,034,266 | |
Capitalized costs relating to oil and gas producing activities, net | 2,446,226 | 1,947,535 | |
Asset retirement costs | $ 129,200 | $ 120,800 | |
[1]Includes asset retirement costs of $129.2 million and $120.8 million at September 30, 2023 and 2022, respectively. |
Supplementary Information for_4
Supplementary Information for Oil and Gas Producing Activities - Summary of Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 | |
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition Costs | $ 120,349 | $ 0 | $ 0 | |
Development Costs | 8,034 | 3,001 | 3,704 | |
Exploration Costs | 0 | 0 | 0 | |
Capitalized Interest | 30 | 0 | 0 | |
Capitalized costs of unproved properties excluded from amortization, total | 128,413 | $ 3,001 | $ 3,704 | |
Capitalized Costs of Unproved Properties Cumulative Balance | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition Costs | 143,860 | |||
Development Costs | 17,207 | |||
Exploration Costs | 0 | |||
Capitalized Interest | 30 | |||
Capitalized costs of unproved properties excluded from amortization, total | $ 161,097 | |||
Costs Incurred Prior to Fiscal 2021 | ||||
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items] | ||||
Acquisition Costs | $ 23,511 | |||
Development Costs | 2,468 | |||
Exploration Costs | 0 | |||
Capitalized Interest | 0 | |||
Capitalized costs of unproved properties excluded from amortization, total | $ 25,979 |
Supplementary Information for_5
Supplementary Information for Oil and Gas Producing Activities - Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Property Acquisition Costs: | ||||
Proved | $ 33,190 | $ 2,491 | $ 1,801 | |
Unproved | 129,061 | 10,665 | 5,102 | |
Exploration Costs | [1] | 10,055 | 9,631 | 15,413 |
Development Costs | [2] | 553,469 | 528,684 | 329,368 |
Asset Retirement Costs | 8,363 | 9,768 | 20,194 | |
Total Property Acquisition Costs | 734,138 | 561,239 | 371,878 | |
Capitalized interest included in exploration costs | 0 | 0 | 100 | |
Capitalized interest included in development costs | $ 100 | $ 600 | $ 400 | |
[1]Amounts for 2023, 2022 and 2021 include capitalized interest of zero, zero and $0.1 million respectively.[2]Amounts for 2023, 2022 and 2021 include capitalized interest of $0.1 million, $0.6 million and $0.4 million, respectively. |
Supplementary Information for_6
Supplementary Information for Oil and Gas Producing Activities - Narrative (Details) $ in Millions, Bcf in Billions | 12 Months Ended | ||||
Sep. 30, 2023 USD ($) pUDLocation Bcf | Sep. 30, 2022 USD ($) pUDLocation Bcf | Sep. 30, 2021 USD ($) Bcf | Sep. 30, 2020 | Sep. 30, 2019 | |
Reserve Quantities [Line Items] | |||||
Amount spent for developing proved undeveloped reserves | $ | $ 342 | $ 154.3 | $ 81.2 | ||
Proved undeveloped reserve volume (in Bcfe) | 985 | 858 | 636 | ||
Percentage of PUD reserves to the total proved reserves | 21.70% | 20.60% | 16.50% | ||
Increase in PUD reserves (in Bcfe) | 127 | 222 | |||
New PUD reserve additions (in Bcfe) | 554 | 502 | |||
PUD reserves added back (in Bcfe) | 14 | ||||
Number of PUD wells added back | pUDLocation | 1 | ||||
PUD upward revisions (in Bcfe) | 23 | 23 | |||
PUD conversions to developed reserves (in Bcfe) | 402 | 287 | |||
Proved undeveloped reserves removed (in Bcfe) | 62 | 13 | |||
Number of PUD well locations removed | pUDLocation | 7 | 1 | |||
Investment made to convert proved undeveloped reserves to developed reserves | $ | $ 342 | $ 154 | |||
Conversion of undeveloped proved reserves to developed proved reserves after revisions (in Bcfe) | 440 | 333 | |||
Conversion of PUD to developed to PUD reserves booked at end of prior year (as a percent) | 47% | 45% | 34% | 36% | 39% |
Arbitrary discount rate (as a percent) | 10% | ||||
Total PUD Reserve Additions Estimated in the Next Fiscal Year | |||||
Reserve Quantities [Line Items] | |||||
Amount to be spent on developing proved undeveloped reserves | $ | $ 315 | ||||
Utica Shale | |||||
Reserve Quantities [Line Items] | |||||
Proved undeveloped reserve volume (in Bcfe) | 873 | 503 | 411 | ||
PUD conversions to developed reserves (in Bcfe) | 127 | 231 | |||
Marcellus Shale Fields | |||||
Reserve Quantities [Line Items] | |||||
Proved undeveloped reserve volume (in Bcfe) | 112 | 355 | 220 | ||
PUD conversions to developed reserves (in Bcfe) | 275 | 55 | |||
West Coast Region | |||||
Reserve Quantities [Line Items] | |||||
Proved undeveloped reserve volume (in Bcfe) | 0 | 5 | |||
PUD conversions to developed reserves (in Bcfe) | 1 | ||||
Proved undeveloped reserves removed (in Bcfe) | 3 | ||||
Number of well locations developed with net PUD reserves | pUDLocation | 6 | ||||
Number of well locations to be developed with net PUD reserves | pUDLocation | 17 | ||||
Appalachian Region | |||||
Reserve Quantities [Line Items] | |||||
Number of well locations developed with net PUD reserves | pUDLocation | 39 | 31 | |||
Number of well locations to be developed with net PUD reserves | pUDLocation | 77 | 65 |
Supplementary Information for_7
Supplementary Information for Oil and Gas Producing Activities - Results of Operations for Producing Activities (Details) - USD ($) | 12 Months Ended | |||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | ||
Reserve Quantities [Line Items] | ||||
Operating Revenues | [1] | $ 1,038,760,000 | $ 1,881,680,000 | $ 915,668,000 |
Production/Lifting Costs | 253,555,000 | 283,914,000 | 267,316,000 | |
Franchise/Ad Valorem Taxes | 17,532,000 | 25,112,000 | 22,128,000 | |
Purchased Emission Allowance Expense | 0 | 1,305,000 | 2,940,000 | |
Accretion Expense | 5,673,000 | 7,530,000 | 7,743,000 | |
Depreciation, Depletion and Amortization ($0.63, $0.57 and $0.54 per Mcfe of production, respectively) | 235,694,000 | 202,418,000 | 177,055,000 | |
Impairment of Oil and Gas Producing Properties | 0 | 0 | 76,152,000 | |
Income Tax Expense | 145,574,000 | 368,925,000 | 98,593,000 | |
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) | 380,732,000 | 992,476,000 | 263,741,000 | |
Revenues from sales to affiliates | 0 | 0 | 0 | |
Transfers to operations | 1,957,000 | 5,696,000 | 3,061,000 | |
Depreciation, Depletion and Amortization (per Mcfe of production) | 0.63 | 0.57 | 0.54 | |
Gas | ||||
Reserve Quantities [Line Items] | ||||
Gas (includes transfers to operations of $1,957, $5,696 and $3,061, respectively) | [2] | 1,036,499,000 | 1,730,723,000 | 780,477,000 |
Oil, Condensate and Other Liquids | ||||
Reserve Quantities [Line Items] | ||||
Operating Revenues | $ 2,261,000 | $ 150,957,000 | $ 135,191,000 | |
[1]Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments.[2]There were no revenues from sales to affiliates for all years presented. |
Supplementary Information for_8
Supplementary Information for Oil and Gas Producing Activities - Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Details) Bcf in Thousands | 12 Months Ended | ||||
Sep. 30, 2023 MBbls MMcf Bcf | Sep. 30, 2022 MBbls MMcf Bcf | Sep. 30, 2021 MBbls Bcf MMcf | Sep. 30, 2020 MMcf MBbls | ||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved undeveloped reserve volume | Bcf | 985,000,000 | 858,000,000 | 636,000,000 | ||
Gas MMcf | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved Developed and Undeveloped Reserves, Beginning of Period | 4,170,662 | 3,723,433 | 3,325,085 | ||
Extensions and Discoveries | 670,438 | 837,510 | 689,395 | ||
Revisions of Previous Estimates | 32,379 | 2,953 | 22,973 | ||
Production | (372,271) | (342,911) | (314,020) | ||
Sale of Minerals in Place | (50,323) | ||||
Purchases of Minerals in Place | 33,876 | ||||
Proved Developed and Undeveloped Reserves, End of Period | 4,535,084 | 4,170,662 | 3,723,433 | ||
Proved developed reserves volume | 3,550,034 | 3,312,568 | 3,091,463 | 2,773,823 | |
Proved undeveloped reserve volume | 985,050 | 858,094 | 631,970 | 551,262 | |
Oil Mbbl | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved Developed and Undeveloped Reserves, Beginning of Period | MBbls | 250 | 21,537 | 22,100 | ||
Extensions and Discoveries | MBbls | 296 | 1,041 | |||
Revisions of Previous Estimates | MBbls | (4) | 787 | 631 | ||
Production | (30) | (1,604) | (2,235) | ||
Sale of Minerals in Place | MBbls | (20,766) | ||||
Proved Developed and Undeveloped Reserves, End of Period | MBbls | 216 | 250 | 21,537 | ||
Proved developed reserves volume | MBbls | 216 | 250 | 20,941 | 22,100 | |
Proved undeveloped reserve volume | MBbls | 0 | 0 | 596 | 0 | |
Appalachian Region | Gas MMcf | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved Developed and Undeveloped Reserves, Beginning of Period | 4,170,662 | 3,693,148 | 3,296,113 | ||
Extensions and Discoveries | [1] | 670,438 | 837,510 | 689,395 | |
Revisions of Previous Estimates | 32,379 | 2,882 | 19,940 | ||
Production | [2] | (372,271) | (341,700) | (312,300) | |
Sale of Minerals in Place | (21,178) | ||||
Purchases of Minerals in Place | 33,876 | ||||
Proved Developed and Undeveloped Reserves, End of Period | 4,535,084 | 4,170,662 | 3,693,148 | ||
Proved developed reserves volume | 3,550,034 | 3,312,568 | 3,061,178 | 2,744,851 | |
Proved undeveloped reserve volume | 985,050 | 858,094 | 631,970 | 551,262 | |
Appalachian Region | Oil Mbbl | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved Developed and Undeveloped Reserves, Beginning of Period | MBbls | 250 | 11 | 12 | ||
Extensions and Discoveries | MBbls | 0 | 0 | |||
Revisions of Previous Estimates | MBbls | (4) | 255 | 1 | ||
Production | (30) | (16) | (2) | ||
Sale of Minerals in Place | MBbls | 0 | ||||
Proved Developed and Undeveloped Reserves, End of Period | MBbls | 216 | 250 | 11 | ||
Proved developed reserves volume | MBbls | 216 | 250 | 11 | 12 | |
Proved undeveloped reserve volume | MBbls | 0 | 0 | 0 | 0 | |
West Coast Region | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved undeveloped reserve volume | Bcf | 0 | 5,000,000 | |||
West Coast Region | Gas MMcf | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved Developed and Undeveloped Reserves, Beginning of Period | 0 | 30,285 | 28,972 | ||
Extensions and Discoveries | 0 | 0 | 0 | ||
Revisions of Previous Estimates | 0 | 71 | 3,033 | ||
Production | 0 | (1,211) | (1,720) | ||
Sale of Minerals in Place | (29,145) | ||||
Purchases of Minerals in Place | 0 | ||||
Proved Developed and Undeveloped Reserves, End of Period | 0 | 0 | 30,285 | ||
Proved developed reserves volume | 0 | 0 | 30,285 | 28,972 | |
Proved undeveloped reserve volume | 0 | 0 | 0 | 0 | |
West Coast Region | Oil Mbbl | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved Developed and Undeveloped Reserves, Beginning of Period | MBbls | 0 | 21,526 | 22,088 | ||
Extensions and Discoveries | MBbls | 296 | 1,041 | |||
Revisions of Previous Estimates | MBbls | 0 | 532 | 630 | ||
Production | 0 | (1,588) | (2,233) | ||
Sale of Minerals in Place | MBbls | (20,766) | ||||
Proved Developed and Undeveloped Reserves, End of Period | MBbls | 0 | 0 | 21,526 | ||
Proved developed reserves volume | MBbls | 0 | 0 | 20,930 | 22,088 | |
Proved undeveloped reserve volume | MBbls | 0 | 0 | 596 | 0 | |
Marcellus Shale Fields | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved undeveloped reserve volume | Bcf | 112,000,000 | 355,000,000 | 220,000,000 | ||
Marcellus Shale Fields | Gas MMcf | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Extensions and Discoveries | Bcf | 163 | 301 | 180 | ||
Production | (190,290) | (209,463) | (218,016) | ||
Percentage exceeding total reserve of production in proved developed and undeveloped reserves | 15% | ||||
Utica Shale | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Proved undeveloped reserve volume | Bcf | 873,000,000 | 503,000,000 | 411,000,000 | ||
Utica Shale | Gas MMcf | |||||
Proved Developed and Undeveloped Reserves [Roll Forward] | |||||
Extensions and Discoveries | Bcf | 507 | 537 | 497 | ||
Production | (180,750) | (130,240) | (93,253) | ||
Percentage exceeding total reserve of production in proved developed and undeveloped reserves | 15% | ||||
[1]Extensions and discoveries include 180 Bcf (during 2021), 301 Bcf (during 2022) and 163 Bcf (during 2023), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 497 Bcf (during 2021), 537 Bcf (during 2022) and 507 Bcf (during 2023), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.[2]Production includes 218,016 MMcf (during 2021), 209,463 MMcf (during 2022) and 190,290 MMcf (during 2023), from Marcellus Shale fields. Production includes 93,253 MMcf (during 2021), 130,240 MMcf (during 2022) and 180,750 MMcf (during 2023), from Utica Shale fields. |
Supplementary Information for_9
Supplementary Information for Oil and Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Thousands | Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | Sep. 30, 2020 |
Supplementary Information for Oil and Gas Producing Activities Unaudited [Abstract] | ||||
Future Cash Inflows | $ 11,947,345 | $ 19,209,099 | $ 10,175,182 | |
Less: | ||||
Future Production Costs | 3,538,389 | 3,138,226 | 3,423,629 | |
Future Development Costs | 1,095,096 | 781,847 | 597,662 | |
Future Income Tax Expense at Applicable Statutory Rate | 1,867,457 | 3,876,272 | 1,397,175 | |
Future Net Cash Flows | 5,446,403 | 11,412,754 | 4,756,716 | |
Less: | ||||
10% Annual Discount for Estimated Timing of Cash Flows | 2,874,295 | 5,964,424 | 2,403,144 | |
Standardized Measure of Discounted Future Net Cash Flows | $ 2,572,108 | $ 5,448,330 | $ 2,353,572 | $ 1,222,470 |
Supplementary Information fo_10
Supplementary Information for Oil and Gas Producing Activities - Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Sep. 30, 2023 | Sep. 30, 2022 | Sep. 30, 2021 | |
Standardized Measure of Discounted Future Net Cash Flows [Roll Forward] | |||
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year | $ 5,448,330 | $ 2,353,572 | $ 1,222,470 |
Sales, Net of Production Costs | (767,487) | (1,572,402) | (626,132) |
Net Changes in Prices, Net of Production Costs | (3,918,392) | 4,132,889 | 1,478,995 |
Extensions and Discoveries | 237,057 | 1,355,257 | 462,040 |
Changes in Estimated Future Development Costs | (222,233) | (32,160) | 48,247 |
Purchases of Minerals in Place | 34,346 | 0 | 0 |
Sales of Minerals in Place | 0 | (311,308) | 0 |
Previously Estimated Development Costs Incurred | 342,024 | 154,253 | 81,239 |
Net Change in Income Taxes at Applicable Statutory Rate | 959,728 | (1,180,349) | (415,993) |
Revisions of Previous Quantity Estimates | 33,192 | 3,316 | (52,383) |
Accretion of Discount and Other | 425,543 | 545,262 | 155,089 |
Standardized Measure of Discounted Future Net Cash Flows at End of Year | $ 2,572,108 | $ 5,448,330 | $ 2,353,572 |