National Fuel Gas (NFG) 10-K 17 Nov 23 2023 FY Annual report Financial data

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