National Fuel Gas (NFG) 10-K 22 Nov 24 2024 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Sep. 30, 2024	Oct. 31, 2024	Mar. 31, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--09-30
Document Period End Date	Sep. 30, 2024
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			$ 4,834,365,000
Entity Listing, Par Value Per Share	$ 1
Entity Common Stock, Shares Outstanding		90,822,810
Documents Incorporated by Reference	Portions of the registrant’s definitive Proxy Statement for its 2025 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2024, are incorporated by reference into Part III of this report.
Entity Central Index Key	0000070145
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Amendment Flag	false

Audit Information

Audit Information	12 Months Ended
	Sep. 30, 2024
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, 2024	Sep. 30, 2023	Sep. 30, 2022
INCOME
Operating Revenues	$ 1,944,810	$ 2,173,771	$ 2,186,046
Operating Expenses:
Purchased Gas	150,062	437,595	392,093
Property, Franchise and Other Taxes	88,851	92,700	101,182
Depreciation, Depletion and Amortization	457,026	409,573	369,790
Impairment of Assets	519,129	0	0
Total Operating Expenses	1,735,086	1,418,624	1,384,266
Gain on Sale of Assets	0	0	12,736
Operating Income	209,724	755,147	814,516
Other Income (Expense):
Other Income (Deductions)	16,226	18,138	(1,509)
Interest Expense on Long-Term Debt	(122,799)	(111,948)	(120,507)
Other Interest Expense	(15,896)	(19,938)	(9,850)
Income Before Income Taxes	87,255	641,399	682,650
Income Tax Expense	9,742	164,533	116,629
Net Income Available for Common Stock	77,513	476,866	566,021
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	1,885,856	1,587,085	1,191,175
Beginning Retained Earnings Unappropriated and Current Period Net Income	1,963,369	2,063,951	1,757,196
Dividends on Common Stock	(185,220)	(178,095)	(170,111)
Balance at End of Year	$ 1,727,326	$ 1,885,856	$ 1,587,085
Basic:
Net Income Available for Common Stock (in dollars per share)	$ 0.84	$ 5.20	$ 6.19
Diluted:
Net Income Available for Common Stock (in dollars per share)	$ 0.84	$ 5.17	$ 6.15
Weighted Average Common Shares Outstanding:
Used in Basic Calculation (in shares)	91,791,167	91,748,890	91,410,625
Used in Diluted Calculation (in shares)	92,344,511	92,285,918	92,107,066
Earnings Reinvested in the Business
Other Income (Expense):
Net Income Available for Common Stock	$ 77,513	$ 476,866	$ 566,021
EARNINGS REINVESTED IN THE BUSINESS
Share Repurchases	(50,823)	0	0
Dividends on Common Stock	(185,220)	(178,095)	(170,111)
Utility
INCOME
Operating Revenues	696,807	941,779	897,916
Operating Expenses:
Operation and Maintenance	218,393	205,239	193,058
Exploration and Production and Other
INCOME
Operating Revenues	961,078	958,455	1,010,629
Operating Expenses:
Operation and Maintenance	141,308	124,270	191,572
Pipeline and Storage and Gathering
INCOME
Operating Revenues	286,925	273,537	277,501
Operating Expenses:
Operation and Maintenance	$ 160,317	$ 149,247	$ 136,571

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Net Income Available for Common Stock	$ 77,513	$ 476,866	$ 566,021
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(17,511)	(9,660)	9,561
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	2,507	1,674	11,054
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	286,894	708,206	(1,050,831)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(216,655)	88,656	882,581
Other Post-Retirement Adjustment for Regulatory Proceeding	0	0	(7,351)
Other Comprehensive Income (Loss), Before Tax	55,235	788,876	(154,986)
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(3,996)	(2,284)	2,169
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	584	411	2,574
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	81,197	214,270	(287,608)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(62,134)	5,806	241,559
Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding	0	0	(1,544)
Income Taxes — Net	15,651	218,203	(42,850)
Other Comprehensive Income (Loss)	39,584	570,673	(112,136)
Comprehensive Income	$ 117,097	$ 1,047,539	$ 453,885

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2024	Sep. 30, 2023
ASSETS
Property, Plant and Equipment		$ 14,524,798	$ 13,635,303
Less — Accumulated Depreciation, Depletion and Amortization		7,185,593	6,335,441
Property, Plant and Equipment, Net, Total		7,339,205	7,299,862
Current Assets
Cash and Temporary Cash Investments		38,222	55,447
Hedging Collateral Deposits		0	0
Receivables — Net of Allowance for Uncollectible Accounts of $26,194 and $36,295, Respectively		127,222	160,601
Unbilled Revenue		15,521	16,622
Gas Stored Underground		35,055	32,509
Materials and Supplies - at average cost		47,670	48,989
Other Current Assets		92,229	100,260
Total Current Assets		355,919	414,428
Other Assets
Recoverable Future Taxes		80,084	69,045
Unamortized Debt Expense		5,604	7,240
Other Regulatory Assets		108,022	72,138
Deferred Charges		69,662	82,416
Other Investments		81,705	73,976
Goodwill		5,476	5,476
Prepaid Pension and Post-Retirement Benefit Costs		180,230	200,301
Fair Value of Derivative Financial Instruments		87,905	50,487
Other		5,958	4,891
Total Other Assets		624,646	565,970
Total Assets		8,319,770	8,280,260
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 91,005,993 Shares and 91,819,405 Shares, Respectively		91,006	91,819
Paid In Capital		1,045,487	1,040,761
Earnings Reinvested in the Business		1,727,326	1,885,856
Accumulated Other Comprehensive Loss		(15,476)	(55,060)
Total Comprehensive Shareholders’ Equity		2,848,343	2,963,376
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,188,243	2,384,485
Total Capitalization		5,036,586	5,347,861
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		90,700	287,500
Current Portion of Long-Term Debt	[1]	500,000	0
Accounts Payable		165,068	152,193
Amounts Payable to Customers		42,720	59,019
Dividends Payable		46,872	45,451
Interest Payable on Long-Term Debt		27,247	20,399
Customer Advances		19,373	21,003
Customer Security Deposits		36,265	28,764
Other Accruals and Current Liabilities		162,903	160,974
Fair Value of Derivative Financial Instruments		4,744	31,009
Total Current and Accrued Liabilities		1,095,892	806,312
Other Liabilities
Deferred Income Taxes		1,111,165	1,124,170
Taxes Refundable to Customers		305,645	268,562
Cost of Removal Regulatory Liability		292,477	277,694
Other Regulatory Liabilities		151,452	165,441
Other Post-Retirement Liabilities		3,511	2,915
Asset Retirement Obligations		203,006	165,492
Other Liabilities		120,036	121,813
Total Other Liabilities		2,187,292	2,126,087
Commitments and Contingencies (Note L)		0	0
Total Capitalization and Liabilities		$ 8,319,770	$ 8,280,260
[1] Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% medium-term notes and $450.0 million of 5.20% notes. None of the Company’s long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Statement of Financial Position [Abstract]
Allowance for Uncollectible Accounts	$ 26,194	$ 36,295
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)	91,005,993	91,819,405
Common Stock, Shares Outstanding (in shares)	91,005,993	91,819,405

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Operating Activities
Net Income Available for Common Stock	$ 77,513	$ 476,866	$ 566,021
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Gain on Sale of Assets	0	0	(12,736)
Impairment of Assets	519,129	0	0
Depreciation, Depletion and Amortization	457,026	409,573	369,790
Deferred Income Taxes	(2,610)	151,403	104,415
Stock-Based Compensation	22,080	20,630	19,506
Reduction of Other Post-Retirement Regulatory Liability	0	0	(18,533)
Other	24,411	19,647	31,983
Change in:
Receivables and Unbilled Revenue	34,369	213,579	(168,769)
Gas Stored Underground and Materials, Supplies and Emission Allowances	1,738	(8,406)	3,109
Unrecovered Purchased Gas Costs	0	99,342	(66,214)
Other Current Assets	8,144	(41,077)	291
Accounts Payable	5,616	(37,095)	11,907
Amounts Payable to Customers	(16,299)	58,600	398
Customer Advances	(1,630)	(5,105)	8,885
Customer Security Deposits	7,501	4,481	4,991
Other Accruals and Current Liabilities	2,637	(67,664)	34,260
Other Assets	(48,183)	(26,564)	(58,924)
Other Liabilities	(25,481)	(31,135)	(17,859)
Net Cash Provided by Operating Activities	1,065,961	1,237,075	812,521
Investing Activities
Capital Expenditures	(931,236)	(1,009,868)	(811,826)
Net Proceeds from Sale of Exploration and Production Properties	0	0	254,439
Sale of Fixed Income Mutual Fund Shares in Grantor Trust	0	10,000	30,000
Acquisition of Upstream Assets	0	(124,758)	0
Other	(2,669)	12,279	8,683
Net Cash Used in Investing Activities	(933,905)	(1,112,347)	(518,704)
Financing Activities
Proceeds from Issuance of Short-Term Note Payable to Bank	0	250,000	0
Repayment of Short-Term Note Payable to Bank	0	(250,000)	0
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper	(196,800)	227,500	(98,500)
Net Proceeds from Issuance of Long-Term Debt	299,359	297,306	0
Shares Repurchased Under Repurchase Plan	(64,086)	0	0
Reduction of Long-Term Debt	0	(549,000)	0
Net Repurchases of Common Stock Under Stock and Benefit Plans	(3,956)	(6,709)	(9,590)
Dividends Paid on Common Stock	(183,798)	(176,096)	(168,147)
Net Cash Used in Financing Activities	(149,281)	(206,999)	(276,237)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(17,225)	(82,271)	17,580
Cash, Cash Equivalents and Restricted Cash At Beginning of Year	55,447	137,718	120,138
Cash, Cash Equivalents and Restricted Cash At End of Year	38,222	55,447	137,718
Cash Paid For:
Interest	125,130	124,441	124,312
Income Taxes	4,132	38,098	16,680
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	119,988	109,208	120,262
Non-Cash Contingent Consideration for Asset Sale	$ 0	$ 0	$ 12,571

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2024
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 exploration and production properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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. However, final billings were suppressed in the Utility segment during the COVID-19 pandemic as a result of state shut-off moratoriums. Those moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby resulting in higher amounts being written off in 2023 and 2024. Activity in the allowance for uncollectible accounts are as follows: Year Ended September 30 2024 2023 2022 (Thousands) Balance at Beginning of Year $ 36,295 $ 40,228 $ 31,639 Additions Charged to Costs and Expenses 13,180 14,482 13,209 Add: Discounts on Purchased Receivables 753 1,380 1,314 Deduct: Net Accounts Receivable Written-Off 24,034 19,795 5,934 Balance at End of Year $ 26,194 $ 36,295 $ 40,228 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 Utility segment’s tariff in its New York rate jurisdiction contains a system modernization/improvement tracker that is intended to provide recovery for leak prone pipe replacement. Amounts calculated under the tracker that are in excess of the annual amount that can be billed to the ratepayer are deferred as a regulatory asset per commission authorization. The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNA, which covers the eight-month period from October through May. The WNA is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNA as a five-year pilot program. The program became effective October 2023 and covers the eight-month period from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNA, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues. The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. 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 of activities is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance. 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, 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 properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center. The Company’s capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $2.3 billion and $2.4 billion at September 30, 2024 and 2023, respectively. For further discussion of capitalized costs, refer to Note N — Supplementary Information for Exploration and Production Activities. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying commodity pricing (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. The book value of the exploration and production properties exceeded the ceiling at September 30, 2024 as well as at June 30, 2024. As such, the Company recognized non-cash, pre-tax ceiling test impairment charges in the Exploration and Production segment of $463.7 million for the year ended September 30, 2024. Deferred income tax benefits of $127.3 million related to the non-cash impairment charges were also recognized for the year ended September 30, 2024. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2024, 2023 and 2022, estimated future net cash flows were increased by $428.5 million, increased by $38.8 million and decreased by $1.0 billion, respectively. The Exploration and Production segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting. As discussed in Note I — Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded at September 30, 2024. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility and Gathering segments at September 30, 2024. An impairment charge related to the Northern Access Project, which is discussed at Note I — Fair Value Measurements, was recorded in the Pipeline and Storage segment at September 30, 2024. The impairment charge reduced the value of certain assets recorded in Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet. 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 exploration and production properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved exploration and production properties is excluded from this computation. Depreciation, depletion and amortization expense for exploration and production properties was $270.6 million, $235.7 million and $202.4 million for the years ended September 30, 2024, 2023 and 2022, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated useful lives of property in service. The following is a summary of depreciable plant by segment: As of September 30 2024 2023 (Thousands) Exploration and Production $ 7,275,495 $ 6,741,095 Pipeline and Storage 2,919,506 2,803,690 Gathering 1,142,000 1,032,969 Utility 2,645,981 2,507,465 All Other and Corporate 15,915 15,787 $ 13,998,897 $ 13,101,006 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2024 2023 2022 Exploration and Production, per Mcfe(1) $ 0.71 $ 0.65 $ 0.59 Pipeline and Storage 2.7 % 2.6 % 2.7 % Gathering 3.6 % 3.6 % 3.6 % Utility 2.8 % 2.7 % 2.7 % All Other and Corporate 3.0 % 2.9 % 1.4 % (1) Amounts include depletion of exploration and production properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Exploration and Production Activities, depletion of exploration and production properties amounted to $0.69, $0.63 and $0.57 per Mcfe of production in 2024, 2023 and 2022, respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2024 and 2023 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. 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, 2024, 2023 and 2022, 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, 2024 and 2023, 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, 2024 Balance at October 1, 2023 $ 4,623 $ (59,683) $ (55,060) Other Comprehensive Gains and Losses Before Reclassifications 205,697 (13,515) 192,182 Amounts Reclassified From Other Comprehensive Loss (154,521) 1,923 (152,598) Balance at September 30, 2024 $ 55,799 $ (71,275) $ (15,476) 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) 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, 2024 and 2023. The total amount for accumulated losses was $70.9 million and $59.3 million at September 30, 2024 and 2023, respectively. 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, 2024 and 2023 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 2024 2023 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $ 217,012 $ (88,015) Operating Revenues Foreign Currency Contracts (357) (641) Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (56) (82) (1) Net Actuarial Loss (2,451) (1,592) (1) 214,148 (90,330) Total Before Income Tax (61,550) 6,217 Income Tax Expense $ 152,598 $ (84,113) Net of Tax (1) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details. Gas Stored Underground In the Utility segment, gas stored underground in the amount of $35.0 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 2024, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $8.3 million at September 30, 2024. 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, 2024, 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 2024 2023 2022 2021 Cash and Temporary Cash Investments $ 38,222 $ 55,447 $ 46,048 $ 31,528 Hedging Collateral Deposits — — 91,670 88,610 Cash, Cash Equivalents, and Restricted Cash $ 38,222 $ 55,447 $ 137,718 $ 120,138 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 2024 2023 (Thousands) Prepayments $ 18,463 $ 18,966 Prepaid Property and Other Taxes 14,187 14,186 Federal Income Taxes Receivable 8,154 14,602 State Income Taxes Receivable 13,161 16,133 Regulatory Assets 38,264 36,373 $ 92,229 $ 100,260 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2024 2023 (Thousands) Accrued Capital Expenditures $ 47,344 $ 43,323 Regulatory Liabilities 29,352 38,105 Liability for Royalty and Working Interests 15,007 17,679 Non-Qualified Benefit Plan Liability 14,135 13,052 Other 57,065 48,815 $ 162,903 $ 160,974 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, 2024 and 2023, customers in the balanced billing programs had advanced excess funds of $19.4 million and $21.0 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, 2024 and 2023, the Company had received customer security deposits amounting to $36.3 million and $28.8 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 2024, 2023 and/or 2022 were restricted stock units, performance shares and SARs. For fiscal 2024, 2023 and 2022, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Restricted stock units, performance shares and SARs that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 569 securities, 3,888 securities and 2,858 securities excluded as being antidilutive for the years ended September 30, 2024, 2023 and 2022, respectively. Share Repurchases The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note H — Capitalization and Short-Term Borrowings for further discussion of the Company’s share repurchase program. Stock-Based Compensation 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. 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, 2024
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.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Sep. 30, 2024
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, 2024, 2023 and 2022, presented by type of service from each reportable segment. Year Ended September 30, 2024 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 738,778 $ — $ — $ — $ 738,778 $ — $ — $ 738,778 Production of Crude Oil 2,298 — — — 2,298 — — 2,298 Natural Gas Processing 1,053 — — — 1,053 — — 1,053 Natural Gas Gathering Service — — 244,225 — 244,225 — (228,688) 15,537 Natural Gas Transportation Service — 311,900 — 103,866 415,766 — (99,658) 316,108 Natural Gas Storage Service — 95,933 — — 95,933 — (40,995) 54,938 Natural Gas Residential Sales — — — 502,744 502,744 — — 502,744 Natural Gas Commercial Sales — — — 68,466 68,466 — — 68,466 Natural Gas Industrial Sales — — — 3,103 3,103 — (5) 3,098 Other 1,937 4,560 — (1,256) 5,241 — (902) 4,339 Total Revenues from Contracts with Customers 744,066 412,393 244,225 676,923 2,077,607 — (370,248) 1,707,359 Alternative Revenue Programs — — — 20,439 20,439 — — 20,439 Derivative Financial Instruments 217,012 — — — 217,012 — — 217,012 Total Revenues $ 961,078 $ 412,393 $ 244,225 $ 697,362 $ 2,315,058 $ — $ (370,248) $ 1,944,810 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: $233.8 million for fiscal 2025; $183.5 million for fiscal 2026; $142.9 million for fiscal 2027; $123.4 million for fiscal 2028; $109.1 million for fiscal 2029; and $523.1 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

Leases

Leases	12 Months Ended
	Sep. 30, 2024
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 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, 2024 or September 30, 2023. The Company also 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 ten months to fifteen years. Most building leases include one or more options to renew, generally at the Company’s sole discretion, with renewal terms that can extend the lease terms from one year to sixteen years. Renewal options are included in the lease term if they are reasonably certain to be exercised. 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 2 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 exploration and production properties under the full cost method of accounting as well as certain equipment leases related to construction projects, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the Company’s total operating lease costs (in thousands): Year Ended September 30 2024 2023 Operating Lease Expense $ 11,827 $ 7,484 Variable Lease Expense(1) 601 507 Short-Term Lease Expense(2) 299 1,694 Total Lease Expense $ 12,727 $ 9,685 Lease Costs Recorded to Property, Plant and Equipment(3) $ 20,143 $ 24,018 (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 exploration and production properties under full cost pool accounting as well as certain equipment leases used on construction projects. Right-of-use assets and lease liabilities are recognized at the commencement date of a leasing arrangement based on the present value of lease payments over the lease term. The weighted average remaining lease term was 5.7 years and 6.1 years as of September 30, 2024 and 2023, respectively. The weighted average discount rate was 5.68% and 5.48% as of September 30, 2024 and 2023, 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 2024 2023 Assets: Deferred Charges $ 44,206 $ 39,664 Liabilities: Other Accruals and Current Liabilities $ 11,518 $ 9,969 Other Liabilities $ 32,616 $ 29,510 Cash paid for lease liabilities, reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $12.7 million and $9.7 million for the years ended September 30, 2024 and 2023, respectively. The Company did not record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2024 or 2023. The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2024 (in thousands): At September 30, 2024 2025 $ 11,801 2026 9,653 2027 8,880 2028 7,707 2029 4,478 Thereafter 9,234 Total Lease Payments 51,753 Less: Interest (7,619) Total Lease Liability $ 44,134

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Sep. 30, 2024
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). 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. During fiscal 2024, the Company experienced an increase in plugging and abandonment costs associated with the Exploration and Production segment’s natural gas wells and the Pipeline and Storage segment’s natural gas storage wells, which contributed to an increase in the asset retirement obligation. This increase in plugging and abandonment costs is the primary component of the Revision of Estimates amount for fiscal 2024 shown in the table below. As discussed in Note B — Asset Acquisitions and Divestitures, on June 30, 2022, the Company completed the sale of Seneca’s California oil and gas assets to Sentinel Peak Resources California LLC. 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 2024 2023 2022 (Thousands) Balance at Beginning of Year $ 165,492 $ 161,545 $ 209,639 Liabilities Incurred 2,367 3,313 2,401 Revisions of Estimates 51,967 6,728 10,700 Liabilities Settled (25,556) (14,448) (71,171) Accretion Expense 8,736 8,354 9,976 Balance at End of Year $ 203,006 $ 165,492 $ 161,545

Regulatory Matters

Regulatory Matters	12 Months Ended
	Sep. 30, 2024
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 2024 2023 (Thousands) Regulatory Assets: Pension Costs(1) (Note K) $ 30,259 $ 20,459 Post-Retirement Benefit Costs(1) (Note K) 7,932 2,536 Recoverable Future Taxes (Note G) 80,084 69,045 System Modernization / Improvement Tracker (2) (See Regulatory Mechanisms in Note A) 47,043 30,375 Asset Retirement Obligations(1) (Note E) 21,951 19,384 Unamortized Debt Expense (Note A) 5,604 7,240 Other(3) 39,101 35,757 Total Regulatory Assets 231,974 184,796 Less: Amounts Included in Other Current Assets (38,264) (36,373) Total Long-Term Regulatory Assets $ 193,710 $ 148,423 At September 30 2024 2023 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 292,477 $ 277,694 Taxes Refundable to Customers (Note G) 305,645 268,562 Post-Retirement Benefit Costs(5) (Note K) 141,199 159,760 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 42,720 59,019 Environmental Site Remediation Costs(4) (Note L) 5,390 619 Other(6) 34,215 43,167 Total Regulatory Liabilities 821,646 808,821 Less: Amounts included in Current and Accrued Liabilities (72,072) (97,124) Total Long-Term Regulatory Liabilities $ 749,574 $ 711,697 (1) Included in Other Regulatory Assets on the Consolidated Balance Sheets. (2) $15,681 and $19,584 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $31,362 and $10,791 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. (3) $22,583 and $16,789 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $16,518 and $18,968 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2024 and 2023, since such amounts are expected to be passed back to ratepayers in the next 12 months. $135,399 and $153,960 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. (6) $23,552 and $32,305 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,663 and $10,862 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, 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 approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024. Thereafter, settlement discussions with parties commenced and to facilitate these discussions, the Company requested postponements of the evidentiary hearing and agreed to extensions of the suspension period for the effective date of new base delivery rates subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period. The settlement negotiations were successful and resulted in a Joint Proposal (“JP”) that establishes a three-year rate plan allowing for an $86 million increase in annual revenue requirement over three years, with the first-year impact of $57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027. The JP settles all contested issues among the signatory parties and includes, among other things, a return on equity of 9.7%, a common equity ratio of 48% for rate setting purposes, an earnings sharing mechanism, an uncollectible expense tracker, and continuation of the Company’s leak prone pipe replacement program. The revenue requirement in the JP also includes the impact of negative pension/OPEB expense. The JP was filed with the NYPSC on September 9, 2024. On November 14, 2024, the NYPSC issued an order extending the suspension period through December 31, 2024. That order also includes a “make-whole” provision from September 30, 2024 until the date new rates take effect under the final decision on the JP. Pennsylvania Jurisdiction 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. On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge (“DSIC”) to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. If approved as filed, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if its total plant in service exceeds approximately $781.3 million and its quarterly rate of return does not exceed the authorized PaPUC rate of return. As of September 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division was $785.2 million. The DSIC petition is currently pending before the PaPUC. FERC Jurisdiction Supply Corporation’s rate settlement, approved June 11, 2024 provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2024
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 2024 2023 2022 (Thousands) Current Income Taxes — Federal $ 6,453 $ 11,744 $ — State 5,899 1,386 12,214 Deferred Income Taxes — Federal 894 106,801 137,025 State (3,504) 44,602 (32,610) Total Income Taxes $ 9,742 $ 164,533 $ 116,629 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, impose a corporate minimum tax, and impose an excise tax on corporate stock buybacks. The provisions of the IRA did not have a material impact on the accompanying financial statements, although some of the provisions may be applicable in future years. 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 2024 2023 2022 (Thousands) U.S. Income Before Income Taxes $ 87,255 $ 641,399 $ 682,650 Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21% $ 18,324 $ 134,694 $ 143,357 State Valuation Allowance (1) — — (24,850) State Income Taxes (2) 1,892 36,331 8,736 Amortization of Excess Deferred Federal Income Taxes (5,607) (6,053) (5,184) Plant Flow Through Items (6,135) (2,856) (814) Stock Compensation 1,758 957 820 Federal Tax Credits (5) (6) (5,701) Miscellaneous (485) 1,466 265 Total Income Taxes $ 9,742 $ 164,533 $ 116,629 (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 2024 2023 (Thousands) Deferred Tax Liabilities: Unrealized Hedging Gains $ 22,433 $ 3,385 Property, Plant and Equipment 1,134,727 1,178,893 Pension and Other Post-Retirement Benefit Costs 59,877 44,358 Other 13,885 21,470 Total Deferred Tax Liabilities 1,230,922 1,248,106 Deferred Tax Assets: Tax Loss and Credit Carryforwards (31,111) (33,744) Pension and Other Post-Retirement Benefit Costs (49,622) (41,843) Other (39,024) (48,349) Total Deferred Tax Assets (119,757) (123,936) Total Net Deferred Income Taxes $ 1,111,165 $ 1,124,170 The following is a summary of changes in valuation allowances for deferred tax assets: Year Ended September 30 2024 2023 2022 (Thousands) Balance at Beginning of Year $ — $ — $ 57,645 Additions — — — Deductions — — 57,645 Balance at End of Year $ — $ — $ — 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 $305.6 million and $268.6 million at September 30, 2024 and 2023, 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 $80.1 million and $69.0 million at September 30, 2024 and 2023, respectively. The Company is in the Compliance Maintenance Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2024. 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 2021 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, 2024, 2023, or 2022. 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 elected this change in tax accounting method for Distribution Corporation with its most recent consolidated tax return filing. The Company is planning to elect this same change in tax accounting method for Supply Corporation with its consolidated tax return filing in the upcoming year and has reflected an estimate in the September 30, 2024 financial statements of what is intended to be treated as a repair for tax purposes rather than being capitalized. That estimate has been recorded in Income Tax Expense. Tax carryforwards available at September 30, 2024, were as follows: Jurisdiction Tax Attribute Amount Expires Pennsylvania Net Operating Loss $ 438,058 2031-2044

Capitalization and Short-Term B

Capitalization and Short-Term Borrowings	12 Months Ended
	Sep. 30, 2024
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, 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 (55,060) Net Income Available for Common Stock 77,513 Dividends Declared on Common Stock ($2.02 Per Share) (185,220) Other Comprehensive Income, Net of Tax 39,584 Share-Based Payment Expense(1) 19,868 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 333 333 (1,955) Share Repurchases Under Repurchase Plan (1,146) (1,146) (13,187) (50,823) Balance at September 30, 2024 91,006 $ 91,006 $ 1,045,487 $ 1,727,326 (2) $ (15,476) (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, 2024, $1.6 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 2024, 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 2024, the Company issued 115,337 original issue shares of common stock for restricted stock units that vested and 251,255 original issue shares of common stock for performance shares that vested. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During 2024, 78,141 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 36,078 original issue shares of common stock during 2024. In addition, the Company issued 8,318 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment features of the Company’s DCP during 2024. On March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $200 million in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. During 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $56.32 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $65.2 million. Share repurchases that settled during 2024 were funded with cash provided by operating activities and/or short-term borrowings. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings. Stock Award Plans 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, 2024, 2023 and 2022 was approximately $19.8 million, $18.6 million and $17.6 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, 2024, 2023 and 2022 was approximately $2.5 million, $2.4 million and $2.5 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, 2024, 2023 and 2022. The tax benefit related to stock-based compensation exercises and vestings was $0.3 million for the year ended September 30, 2024. Pursuant to registration statements for these plans, there were 3,889,027 shares available for future grant at September 30, 2024. These shares include shares available for future options, SARs, restricted stock and performance share grants. Restricted Stock Units Transactions for 2024 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2023 342,186 $ 49.63 Granted in 2024 220,778 $ 42.44 Vested in 2024 (115,337) $ 46.92 Forfeited in 2024 (9,434) $ 50.43 Outstanding at September 30, 2024 438,193 $ 46.70 The Company also granted 133,173 and 128,950 nonperformance-based restricted stock units during the years ended September 30, 2023 and 2022, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2023 and 2022 was $58.10 per share and $54.10 per share, respectively. As of September 30, 2024, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $9.2 million, which will be recognized over a weighted average period of 3.0 years. Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2024 will lapse as follows: 2025 — 129,688 units; 2026 — 111,557 units; 2027 — 86,667 units; 2028 — 34,757 units; 2029 — 19,228 units; and 56,296 units thereafter. Performance Shares Transactions for 2024 involving performance shares for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2023 586,791 $ 55.46 Granted in 2024 361,729 $ 44.23 Vested in 2024 (251,255) $ 38.62 Forfeited in 2024 (35,357) $ 46.49 Change in Units Based on Performance Achieved 57,669 $ 37.36 Outstanding at September 30, 2024 719,577 $ 54.69 The Company also granted 202,259 and 195,397 performance shares during the years ended September 30, 2023 and 2022, respectively. The weighted average grant date fair value of such performance shares granted in 2023 and 2022 was $64.28 per share and $65.39 per share, respectively. As of September 30, 2024, unrecognized compensation expense related to performance shares totaled approximately $15.7 million, which will be recognized over a weighted average period of 2.4 years. Vesting restrictions for the outstanding performance shares at September 30, 2024 will lapse as follows: 2025 — 177,118 shares; 2026 — 188,767 shares; 2027 — 297,392 shares; 2028 - zero; 2029 - zero; and 56,300 shares thereafter. The performance shares granted during the years ended September 30, 2024, 2023 and 2022 include awards that must meet a performance goal related to either relative return on capital over a three-year or five-year performance cycle (“ROC performance shares”), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle (“ESG performance shares”) or relative shareholder return over a three-year or five-year performance cycle (“TSR performance shares”). The performance goal over the respective performance cycles for the ROC performance shares granted during 2024, 2023 and 2022 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). 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 2024, 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. The performance goal over the respective performance cycles for the TSR performance shares granted during 2024, 2023 and 2022 is the Company’s three-year (or five-year) total shareholder return relative to the three-year (or five-year) total shareholder return of the other companies in the Report Group. Three-year (or five-year) total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. 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 weighted average assumptions were used in estimating the fair value of the TSR performance shares at the date of grant: Year Ended September 30 2024 2023 2022 Risk-Free Interest Rate 4.36 % 4.03 % 0.85 % Remaining Term at Date of Grant (Years) 2.98 2.80 2.80 Expected Volatility 23.9 % 31.6 % 29.7 % Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2024, 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 2024 2023 (Thousands) Medium-Term Notes(1): 7.38% due June 2025 $ 50,000 $ 50,000 Notes(1)(2)(3): 2.95% to 5.50% due July 2025 to March 2031 2,350,000 2,350,000 Delayed Draw Term Loan(4): Variable Rate due February 2026 300,000 — Total Long-Term Debt 2,700,000 2,400,000 Less Unamortized Discount and Debt Issuance Costs 11,757 15,515 Less Current Portion(5) 500,000 — $ 2,188,243 $ 2,384,485 (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) The interest rate on the delayed draw term loan is a weighted average SOFR interest rate of 6.71% that was locked in from April 2024 until the beginning of October 2024. The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100.0 million until January 2025. (5) Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% medium-term notes and $450.0 million of 5.20% notes. None of the Company’s long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under a $250.0 million unsecured committed delayed draw term loan under a previous 364-Day Credit Agreement. As of September 30, 2024, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $500.0 million in 2025, $800.0 million in 2026, $600.0 million in 2027, $300.0 million in 2028, zero in 2029, and $500.0 million thereafter. Short-Term Borrowings 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. As initially entered, the Credit Agreement provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. In February 2024, the Company and eleven of the banks in the syndicate consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion to February 25, 2028. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. 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. At September 30, 2024, the Company had outstanding commercial paper of $90.7 million with a weighted average interest rate on the commercial paper of 5.30%. At September 30, 2023, the Company had outstanding commercial paper of $287.5 million with a weighted average interest rate on the commercial paper of 6.13%. The Company did not have any outstanding short-term notes payable to banks at September 30, 2024 and 2023. Debt Restrictions Both the Credit Agreement and the Term Loan Agreement provide that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company’s total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $717.9 million. As a result, at September 30, 2024, $358.9 million was added back to the Company’s total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company’s consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: all unrealized gains or losses on commodity-related derivative financial instruments, and up to $10 million in unrealized gains or losses on other derivative financial instruments. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. At September 30, 2024, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and the Term Loan Agreement was 0.47. The constraints specified in the agreements would have permitted an additional $3.07 billion in short-term and/or long-term debt to be outstanding at September 30, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65. A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources. The Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. The Company’s present liquidity position is believed to be adequate to satisfy known demands. In order to issue incremental long-term debt, the Company must meet an interest coverage test under its existing indenture covenants. 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 1974 indenture, given the impairments of exploration and production properties the Company recognized during the year ended September 30, 2024, the indenture covenants would preclude the Company from issuing incremental long-term debt beginning January 2025, for a period likely extending to June 2025, when the remaining debt outstanding under the 1974 indenture matures. The indenture covenants do not, however, prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. As of September 30, 2024, the Company has $50.0 million in principal and $3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture. Currently, the Company does not anticipate a need to issue incremental long-term debt and only has plans for new long-term debt to replace maturing long-term debt. To the extent a need arises to issue incremental long-term debt, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture. Depositing the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt. In addition to the covenants noted above, the Company’s 1974 indenture contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Sep. 30, 2024
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, 2024 and 2023. 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, 2024 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 29,238 $ — $ — $ — $ 29,238 Derivative Financial Instruments: Over the Counter Swaps — Gas — 76,009 — (17,198) 58,811 Over the Counter No Cost Collars — Gas — 32,584 — (3,774) 28,810 Contingent Consideration for Asset Sale — 729 — — 729 Foreign Currency Contracts — 281 — (726) (445) Other Investments: Balanced Equity Mutual Fund 19,523 — — — 19,523 Fixed Income Mutual Fund 17,374 — — — 17,374 Total $ 66,135 $ 109,603 $ — $ (21,698) $ 154,040 Liabilities: Derivative Financial Instruments: Over the Counter Swaps — Gas $ — $ 22,206 $ — $ (17,198) $ 5,008 Over the Counter No Cost Collars — Gas — 3,501 — (3,774) (273) Foreign Currency Contracts — 726 — (726) — Total $ — $ 26,433 $ — $ (21,698) $ 4,735 Total Net Assets/(Liabilities) $ 66,135 $ 83,170 $ — $ — $ 149,305 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 (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. The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of September 30, 2024, 2023 and 2022 (in thousands): Impairments Nonrecurring Fair Value Measures Year Ended September 30, Segment Date of Measurement Fair Value 2024 2023 2022 Impairment of Assets: Northern Access Project Pipeline and Storage September 30, 2024 $ 12,133 $ 46,075 $ — $ — Water Disposal Assets Exploration and Production September 30, 2024 $ 3,000 9,362 — — Total Impairment $ 55,437 $ — $ — Northern Access Project On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Substantial litigation ensued over the next several years concerning various federal and state authorizations for the project, with the majority of project development activities suspended pending resolution. These legal actions included, most recently, an appeal of FERC’s June 2022 order granting Supply Corporation and Empire an extension of time to construct the project through December 31, 2024. In March 2024, the U.S. Court of Appeals for the D.C. Circuit issued an order affirming FERC’s extension of time, with such order final as of late June 2024. Upon resolution of the extensive litigation, Supply Corporation and Empire began to assess next steps for the project, including a review of the status of necessary federal and state authorizations, as well as potential changes in expected capital expenditures and the related transportation rates that Supply Corporation and Empire needed to support the project. As a result of this review, and in accordance with the precedent agreements between the respective parties, Supply Corporation and Empire sent notifications to Seneca, the sole shipper for the project, indicating their intent to increase the project’s firm transportation rates to account for the anticipated increase in capital expenditures to complete the project. Upon receipt, Seneca indicated it was unwilling to accept the revised transportation rates and intended to terminate the precedent agreements for the project. The precedent agreements were subsequently terminated on October 16, 2024. Accordingly, the Company will no longer pursue construction of the Northern Access project and has taken an impairment charge of $46.1 million at September 30, 2024. Derivative Financial Instruments At September 30, 2024, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment. 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 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, 2024, 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, 2024 and September 30, 2023 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.

Financial Instruments

Financial Instruments	12 Months Ended
	Sep. 30, 2024
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 2024 Carrying Amount 2024 Fair Value 2023 Carrying Amount 2023 Fair Value (Thousands) Long-Term Debt $ 2,688,243 $ 2,656,888 $ 2,384,485 $ 2,210,478 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 or SOFR for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2. Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value. Other Investments The components of the Company’s Other Investments are as follows (in thousands): At September 30 2024 2023 (Thousands) Life Insurance Contracts $ 44,808 $ 42,242 Equity Mutual Fund 19,523 15,837 Fixed Income Mutual Fund 17,374 15,897 $ 81,705 $ 73,976 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 6 years. On June 30, 2022, the Company completed the sale of Seneca’s California assets. The terms of the purchase and sale agreement specified that the Company could receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The calendar 2023 contingency period expired with the ICE Brent Average falling below $95 per barrel. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. 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 $0.7 million and $7.3 million at September 30, 2024 and September 30, 2023, respectively. A $6.6 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the year ended September 30, 2024. The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2024 and September 30, 2023. Cash Flow Hedges For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. As of September 30, 2024, the Company had 349.4 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding. As of September 30, 2024, the Company was hedging a total of $51.2 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts. As of September 30, 2024, the Company had $55.8 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $33.3 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The remaining unrealized gains will be reclassified into the Consolidated Statement of Income in subsequent periods. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2024 and 2023 (Dollar Amounts in Thousands) Derivatives in Cash Amount of Location of Amount of 2024 2023 2024 2023 Commodity Contracts $ 286,392 $ 708,234 Operating Revenue $ 217,012 $ (88,015) Foreign Currency Contracts 502 (28) Operating Revenue (357) (641) Total $ 286,894 $ 708,206 $ 216,655 $ (88,656) 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 seventeen are in a net gain position. On average, the Company had $5.1 million of credit exposure per counterparty in a gain position at September 30, 2024. The maximum credit exposure per counterparty in a gain position at September 30, 2024 was $18.9 million. As of September 30, 2024, 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, 2024, sixteen of the nineteen counterparties to the Company’s outstanding derivative financial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit that could be extended to the Company when it is in a derivative financial liability position would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At September 30, 2024, the Company did not have any derivative financial instrument liabilities with a credit-risk related contingency feature according to the Company’s internal model (discussed in Note I — Fair Value Measurements). Depending on the movement of commodity prices in the future, it is possible that the Company’s derivative asset positions could swing into liability positions, at which point the Company could be required to post hedging collateral deposits. The Company’s requirement to post hedging collateral deposits and the Company’s right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value.

Retirement Plan and Other Post-

Retirement Plan and Other Post-Retirement Benefits	12 Months Ended
	Sep. 30, 2024
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 $6.5 million, $5.7 million and $5.3 million for the years ended September 30, 2024, 2023 and 2022, 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 $9.0 million, $8.2 million and $7.8 million for the years ended September 30, 2024, 2023 and 2022, 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 2024 2023 2022 2024 2023 2022 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 768,750 $ 813,828 $ 1,098,456 $ 274,278 $ 299,283 $ 431,213 Service Cost 4,197 5,187 8,758 434 587 1,328 Interest Cost 43,558 42,516 22,827 15,561 15,648 9,066 Plan Participants’ Contributions — — — 3,401 3,297 3,271 Retiree Drug Subsidy Receipts — — — 1,208 2,969 312 Actuarial (Gain) Loss 72,016 (27,313) (251,173) 54,443 (20,789) (120,276) Benefits Paid (66,215) (65,468) (65,040) (28,300) (26,717) (25,631) Benefit Obligation at End of Period $ 822,306 $ 768,750 $ 813,828 $ 321,025 $ 274,278 $ 299,283 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 784,712 $ 845,205 $ 1,095,729 $ 455,702 $ 461,438 $ 575,565 Actual Return on Plan Assets 105,488 4,975 (205,884) 64,783 17,449 (94,849) Employer Contributions — — 20,400 479 235 3,082 Plan Participants’ Contributions — — — 3,401 3,297 3,271 Benefits Paid (66,215) (65,468) (65,040) (28,300) (26,717) (25,631) Fair Value of Assets at End of Period $ 823,985 $ 784,712 $ 845,205 $ 496,065 $ 455,702 $ 461,438 Net Amount Recognized at End of Period (Funded Status) $ 1,679 $ 15,962 $ 31,377 $ 175,040 $ 181,424 $ 162,155 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ — $ — $ — $ (3,511) $ (2,915) $ (3,065) Non-Current Assets 1,679 15,962 31,377 178,551 184,339 165,220 Net Amount Recognized at End of Period $ 1,679 $ 15,962 $ 31,377 $ 175,040 $ 181,424 $ 162,155 Accumulated Benefit Obligation $ 804,916 $ 751,912 $ 793,555 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 4.97 % 5.99 % 5.57 % 4.98 % 5.99 % 5.56 % Rate of Compensation Increase 4.60 % 4.60 % 4.60 % 4.60 % 4.60 % 4.60 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2024 2023 2022 2024 2023 2022 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 4,197 $ 5,187 $ 8,758 $ 434 $ 587 $ 1,328 Interest Cost 43,558 42,516 22,827 15,561 15,648 9,066 Expected Return on Plan Assets (68,343) (66,593) (52,294) (26,642) (25,612) (29,359) Amortization of Prior Service Cost (Credit) 362 436 537 (429) (429) (429) Recognition of Actuarial (Gain) Loss(1) (1,339) (7,680) 26,405 (2,266) (8,755) (7,610) Net Amortization and Deferral for Regulatory Purposes 16,231 21,512 16,854 8,759 15,157 21,340 Net Periodic Benefit Cost (Income) $ (5,334) $ (4,622) $ 23,087 $ (4,583) $ (3,404) $ (5,664) Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 5.99 % 5.57 % 2.75 % 5.99 % 5.56 % 2.76 % Effective Rate for Interest on Benefit Obligations 5.93 % 5.45 % 2.14 % 5.93 % 5.45 % 2.17 % Effective Discount Rate for Service Cost 6.01 % 5.49 % 2.95 % 5.99 % 5.35 % 3.00 % Effective Rate for Interest on Service Cost 5.98 % 5.53 % 2.70 % 6.01 % 5.47 % 2.93 % Expected Return on Plan Assets 7.40 % 6.90 % 5.20 % 6.00 % 5.70 % 5.20 % Rate of Compensation Increase 4.60 % 4.60 % 4.70 % 4.60 % 4.60 % 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 in 2024, 2023 and 2022, respectively. The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $57.5 million, $58.5 million and $64.9 million at September 30, 2024, 2023 and 2022, respectively. The projected benefit obligations for the plans were $66.0 million, $69.5 million and $77.2 million at September 30, 2024, 2023 and 2022, respectively. At September 30, 2024, $14.1 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $51.9 million is recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2023, $13.1 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $56.4 million was 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. The weighted average discount rates for these plans were 4.71%, 5.91% and 5.49% as of September 30, 2024, 2023 and 2022, respectively and the weighted average rate of compensation increase for these plans was 8.00% as of September 30, 2024, 2023 and 2022. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2024, as well as the changes in such amounts during 2024, 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 Loss $ (164,328) $ (128) $ (13,394) Prior Service (Cost) Credit (1,674) 686 — Net Amount Recognized $ (166,002) $ 558 $ (13,394) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2024(1) Increase in Actuarial Loss, excluding amortization(2) $ (34,871) $ (16,302) $ (880) Change due to Amortization of Actuarial (Gain) Loss (1,339) (2,266) 4,772 Prior Service (Cost) Credit 362 (429) — Net Change $ (35,848) $ (18,997) $ 3,892 (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, 2024, the Company recorded a $36.0 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $15.0 million (pre-tax) decrease to Accumulated Other Comprehensive Income. The effect of the discount rate change for the Retirement Plan in 2024 was to increase the projected benefit obligation of the Retirement Plan by $69.6 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2024 by $2.5 million. The effect of the discount rate change for the Retirement Plan in 2023 was to decrease the projected benefit obligation of the Retirement Plan by $28.4 million. The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected benefit obligation of the Retirement Plan by $262.2 million. The Company did not make any cash contributions to the Retirement Plan during the year ended September 30, 2024. The Company does not expect to make any contributions to the Retirement Plan in 2025. The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $67.7 million in 2025; $67.2 million in 2026; $66.6 million in 2027; $65.8 million in 2028; $65.0 million in 2029; and $305.1 million in the five years thereafter. The effect of the discount rate change in 2024 was to increase the other post-retirement benefit obligation by $28.1 million. The health care cost trend rates were updated, which increased the other post-retirement benefit obligation in 2024 by $25.2 million. Other actuarial experience increased the other post-retirement benefit obligation in 2024 by $1.2 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience. The effect of the discount rate change in 2023 was to decrease the other post-retirement benefit obligation by $10.7 million. 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 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 2025 $ 25,736 $ (1,696) 2026 $ 26,193 $ (1,745) 2027 $ 26,534 $ (1,782) 2028 $ 26,775 $ (1,806) 2029 $ 26,804 $ (1,829) 2030 through 2034 $ 128,836 $ (9,197) Assumed health care cost trend rates as of September 30 were: 2024 2023 2022 Rate of Medical Cost Increase for Pre Age 65 Participants 6.25 % (1) 6.25 % (2) 5.30 % (3) Rate of Medical Cost Increase for Post Age 65 Participants 5.75 % (1) 5.00 % (2) 4.84 % (3) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 10.25 % (1) 6.85 % (2) 6.29 % (3) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 5.75 % (1) 5.00 % (2) 4.84 % (3) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 4.00 % (1) 6.60 % (2) 5.96 % (3) (1) It was assumed that this rate would gradually decline to 4% by 2049. (2) It was assumed that this rate would gradually decline to 4% by 2048. (3) It was assumed that this rate would gradually decline to 4% by 2046. The Company made direct payments of $0.5 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2024. The Company did not make any cash contributions to its VEBA trusts during the year ended September 30, 2024, and does not expect to make any contributions to its VEBA trusts in 2025. Investment Valuation 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, 2024 and 2023, 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, 2024 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 37,984 $ 37,984 $ — $ — $ — Global Equities(2) 38,234 — — — 38,234 Domestic Fixed Income(3)(7) 681,755 — 633,600 — 48,155 International Fixed Income(4) 8,587 — 8,587 — — Real Estate (5) 109,383 — — — 109,383 Cash Held in Collective Trust Funds 41,709 — — — 41,709 Total Retirement Plan Investments 917,652 37,984 642,187 — 237,481 401(h) Investments (83,682) (3,500) (59,166) — (21,016) Total Retirement Plan Investments (excluding 401(h) Investments) $ 833,970 $ 34,484 $ 583,021 $ — $ 216,465 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (9,985) Total Retirement Plan Assets $ 823,985 At September 30, 2023 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 37,611 $ 37,611 $ — $ — $ — Global Equities(2) 36,088 — — — 36,088 Domestic Fixed Income(3) 612,820 — 556,504 — 56,316 International Fixed Income(4) 7,778 — 7,778 — — Real Estate (5) 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 (1) Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. (2) Global Equities are comprised of collective trust funds. (3) Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. (4) International Fixed Income securities are comprised mostly of corporate/government bonds. (5) Real Estate consists of investments held in a collective trust fund and a partnership. (6) Reflects the authoritative guidance related to investments measured at net asset value (NAV). (7) Domestic Fixed Income securities include $8.5 million of derivative instruments used as part of the Company’s overall liability-driven investment strategy as a way to assist in matching the duration of the assets of the Retirement Plan investments with its liability to plan participants. At September 30, 2024 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 82,814 $ — $ — $ — $ 82,814 Exchange Traded Funds — Fixed Income 314,052 314,052 — — — Cash Held in Collective Trust Funds 14,274 — — — 14,274 Total VEBA Trust Investments 411,140 314,052 — — 97,088 401(h) Investments 83,682 3,500 59,166 — 21,016 Total Investments (including 401(h) Investments) $ 494,822 $ 317,552 $ 59,166 $ — $ 118,104 Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 1,243 Total Other Post-Retirement Benefit Assets $ 496,065 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 (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. For the years ended September 30, 2024 and September 30, 2023, there were no transfers from Level 1 to Level 2. For the years ended September 30, 2024 and September 30, 2023, there were no assets or liabilities measured at fair value and classified as Level 3. The Company’s assumption regarding the expected long-term rate of return on plan assets is 6.60% (Retirement Plan) and 5.40% (other post-retirement benefits), effective for fiscal 2025. 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. The actual asset allocations as of September 30, 2024 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets in conjunction with the Company’s liability driven investment strategy. Given the level of the VEBA trust and 401(h) assets in relation to the Other Post-Retirement Benefits, the majority of those assets are and will remain in fixed income securities. Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis. The Company determines the service and interest cost components of net periodic benefit cost using the spot rate approach, which uses individual spot rates along the yield curve that correspond to the timing of each

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Sep. 30, 2024
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, 2024, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $2.4 million. The Company’s liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2024. The Company has a regulatory liability of $5.4 million related to environmental clean-up costs at September 30, 2024 and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company. 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: $215.6 million in 2025, $88.4 million in 2026, $93.2 million in 2027, $113.1 million in 2028, $116.4 million in 2029 and $663.2 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, 2024, the future contractual commitments related to the system modernization and expansion projects are $86.3 million in 2025, $8.7 million in 2026, $6.5 million in 2027, $3.8 million in 2028, $3.8 million in 2029 and $3.9 million thereafter. The Company, in its Exploration and Production segment, has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. The future contractual commitments are $218.6 million in 2025, $73.6 million in 2026, and $13.9 million in 2027. There are no contractual commitments extending beyond 2027. 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, 2024
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 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, 2024 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 961,078 $ 271,388 $ 15,537 $ 696,807 $ 1,944,810 $ — $ — $ 1,944,810 Intersegment Revenues $ — $ 141,005 $ 228,688 $ 555 $ 370,248 $ — $ (370,248) $ — Interest Income $ 2,729 $ 8,632 $ 333 $ 5,736 $ 17,430 $ — $ (8,703) $ 8,727 Interest Expense $ 59,799 $ 47,428 $ 14,206 $ 34,727 $ 156,160 $ 374 $ (17,839) $ 138,695 Depreciation, Depletion and Amortization $ 277,945 $ 74,530 $ 38,817 $ 65,261 $ 456,553 $ — $ 473 $ 457,026 Significant Non-Cash Item: Impairment of Assets $ 473,054 $ 46,075 $ — $ — $ 519,129 $ — $ — $ 519,129 Income Tax Expense (Benefit) $ (58,430) $ 26,045 $ 38,217 $ 3,951 $ 9,783 $ (186) $ 145 $ 9,742 Segment Profit: Net Income (Loss) $ (163,954) $ 79,670 $ 106,913 $ 57,089 $ 79,718 $ (617) $ (1,588) $ 77,513 Expenditures for Additions to Long-Lived Assets $ 536,349 $ 110,830 $ 109,251 $ 184,615 $ 941,045 $ — $ 970 $ 942,015 At September 30, 2024 (Thousands) Segment Assets $ 2,644,820 $ 2,446,243 $ 987,103 $ 2,398,709 $ 8,476,875 $ 6,227 $ (163,332) $ 8,319,770 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 (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 2024 2023 2022 (Thousands) Long-Lived Assets: United States $ 7,963,851 $ 7,865,832 $ 7,135,131

Supplementary Information for E

Supplementary Information for Exploration and Production Activities	12 Months Ended
	Sep. 30, 2024
Supplementary Information for Exploration and Production Activities Unaudited [Abstract]
Supplementary Information for Exploration and Production Activities (unaudited, except for Capitalized Costs Relating to Exploration and Production Activities)	Supplementary Information for Exploration and Production Activities (unaudited, except for Capitalized Costs Relating to Exploration and Production Activities) The Company follows authoritative guidance related to exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of first day of the month commodity price for each month within the twelve month period prior to the end of the reporting period. The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about exploration and production activities and related SEC authoritative guidance. As discussed in Note B — Asset Acquisitions and Divestitures, the Company completed the sale of its California 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 Exploration and Production Activities At September 30 2024 2023 (Thousands) Proved Properties(1) $ 7,079,903 $ 6,555,088 Unproved Properties 200,986 161,097 7,280,889 6,716,185 Less — Accumulated Depreciation, Depletion and Amortization 5,004,299 4,269,959 $ 2,276,590 $ 2,446,226 (1) Includes asset retirement costs of $175.2 million and $129.2 million at September 30, 2024 and 2023, 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 2029. 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, 2024: Total as of September 30, 2024 Year Costs Incurred 2024 2023 2022 Prior (Thousands) Acquisition Costs $ 140,753 $ 8,136 $ 104,858 $ 2,072 $ 25,687 Development Costs 48,642 46,597 1,821 185 39 Exploration Costs 10,813 10,813 — — — Capitalized Interest 778 778 — — — $ 200,986 $ 66,324 $ 106,679 $ 2,257 $ 25,726 Costs Incurred in Property Acquisition, Exploration and Development Activities Year Ended September 30 2024 2023 2022 (Thousands) United States Property Acquisition Costs: Proved $ 17,069 $ 33,190 $ 2,491 Unproved 19,526 129,061 10,665 Exploration Costs(1) 53,519 10,055 9,631 Development Costs(2) 429,151 553,469 528,684 Asset Retirement Costs 46,017 8,363 9,768 $ 565,282 $ 734,138 $ 561,239 (1) Amounts for 2024, 2023 and 2022 include capitalized interest of $0.1 million, zero and zero respectively. (2) Amounts for 2024, 2023 and 2022 include capitalized interest of $0.7 million, $0.1 million and $0.6 million, respectively. For the years ended September 30, 2024, 2023 and 2022, the Company spent $305.6 million, $342.0 million and $154.3 million, respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2024 2023 2022 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of $1,557, $1,957 and $5,696, respectively)(1) $ 738,778 $ 1,036,499 $ 1,730,723 Oil, Condensate and Other Liquids 2,298 2,261 150,957 Total Operating Revenues(2) 741,076 1,038,760 1,881,680 Production/Lifting Costs 270,927 253,555 283,914 Franchise/Ad Valorem Taxes 13,468 17,532 25,112 Purchased Emission Allowance Expense — — 1,305 Accretion Expense 5,992 5,673 7,530 Depreciation, Depletion and Amortization ($0.69, $0.63 and $0.57 per Mcfe of production, respectively) 270,648 235,694 202,418 Impairment of Exploration and Production Properties 463,692 — — Income Tax Expense (Benefit) (76,983) 145,574 368,925 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ (206,668) $ 380,732 $ 992,476 (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 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 15 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, 2024 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, 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 Extensions and Discoveries 601,679 (1) — 601,679 Revisions of Previous Estimates 7,046 — 7,046 Production (392,047) (2) — (392,047) September 30, 2024 4,751,762 — 4,751,762 Proved Developed Reserves: 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 September 30, 2024 3,484,852 — 3,484,852 Proved Undeveloped Reserves: September 30, 2021 631,970 — 631,970 September 30, 2022 858,094 — 858,094 September 30, 2023 985,050 — 985,050 September 30, 2024 1,266,910 — 1,266,910 (1) Extensions and discoveries include 301 Bcf (during 2022), 163 Bcf (during 2023) and 230 Bcf (during 2024), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 537 Bcf (during 2022), 507 Bcf (during 2023) and 372 Bcf (during 2024), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 209,463 MMcf (during 2022), 190,290 MMcf (during 2023) and 235,955 MMcf (during 2024), from Marcellus Shale fields. Production includes 130,240 MMcf (during 2022), 180,750 MMcf (during 2023) and 154,701 MMcf (during 2024), from Utica Shale fields. Oil Mbbl U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Revisions of Previous Estimates 8 — 8 Production (31) — (31) September 30, 2024 193 — 193 Proved Developed Reserves: September 30, 2021 11 20,930 20,941 September 30, 2022 250 — 250 September 30, 2023 216 — 216 September 30, 2024 193 — 193 Proved Undeveloped Reserves: September 30, 2021 — 596 596 September 30, 2022 — — — September 30, 2023 — — — September 30, 2024 — — — The Company’s proved undeveloped (PUD) reserves increased from 985 Bcfe at September 30, 2023 to 1,267 Bcfe at September 30, 2024. PUD reserves in the Utica Shale increased from 873 Bcfe at September 30, 2023 to 925 Bcfe at September 30, 2024. PUD reserves in the Marcellus Shale increased from 112 Bcfe at September 30, 2023 to 342 Bcfe at September 30, 2024. The Company’s total PUD reserves were 26.7% of total proved reserves at September 30, 2024, up from 21.7% of total proved reserves at September 30, 2023. The Company’s 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 increase in PUD reserves in 2024 of 282 Bcfe is a result of 602 Bcfe in new PUD reserve additions and 76 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 291 Bcfe in PUD conversions to developed reserves (all Utica Shale), and 105 Bcfe in PUD reserves removed for nine PUD locations due to schedule and pad layout changes. The increase in PUD reserves in 2023 of 127 Bcfe is a result of 554 Bcfe in new PUD reserve additions, 14 Bcfe for one PUD well added back into the schedule and 23 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 402 Bcfe in PUD conversions to developed reserves (275 Bcfe from the Marcellus Shale and 127 Bcfe from the Utica Shale), and 62 Bcfe in PUD reserves removed for seven PUD locations due to schedule and pad layout changes. The Company invested $306 million during the year ended September 30, 2024 to convert 291 Bcfe (374 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 30% of the net PUD reserves recorded at September 30, 2023. The Company developed 20 of 73 PUD locations in 2024. 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. In 2025, the Company estimates that it will invest approximately $300 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 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, 47% of its beginning year PUD reserves in fiscal 2023 and 30% of its beginning year PUD reserves in fiscal 2024. At September 30, 2024, 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 Reserves The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s exploration and production properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions. The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other exploration and production companies than is provided by a simple comparison of raw proved reserve quantities. Year Ended September 30 2024 2023 2022 (Thousands) United States Future Cash Inflows $ 8,514,126 $ 11,947,345 $ 19,209,099 Less: Future Production Costs 3,672,901 3,538,389 3,138,226 Future Development Costs 1,191,708 1,095,096 781,847 Future Income Tax Expense at Applicable Statutory Rate 826,094 1,867,457 3,876,272 Future Net Cash Flows 2,823,423 5,446,403 11,412,754 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,486,968 2,874,295 5,964,424 Standardized Measure of Discounted Future Net Cash Flows $ 1,336,455 $ 2,572,108 $ 5,448,330 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2024 2023 2022 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 2,572,108 $ 5,448,330 $ 2,353,572 Sales, Net of Production Costs (456,506) (767,487) (1,572,402) Net Changes in Prices, Net of Production Costs (1,829,714) (3,918,392) 4,132,889 Extensions and Discoveries (11,007) 237,057 1,355,257 Changes in Estimated Future Development Costs 32,990 (222,233) (32,160) Purchases of Minerals in Place — 34,346 — Sales of Minerals in Place — — (311,308) Previously Estimated Development Costs Incurred 305,602 342,024 154,253 Net Change in Income Taxes at Applicable Statutory Rate 462,075 959,728 (1,180,349) Revisions of Previous Quantity Estimates 19,216 33,192 3,316 Accretion of Discount and Other 241,691 425,543 545,262 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,336,455 $ 2,572,108 $ 5,448,330

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Pay vs Performance Disclosure
Net Income Available for Common Stock	$ 77,513	$ 476,866	$ 566,021

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2024
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

Insider Trading Policies and Pr

Insider Trading Policies and Procedures	12 Months Ended
	Sep. 30, 2024
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Sep. 30, 2024
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 exploration and production properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation	Regulation
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts
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 Utility segment’s tariff in its New York rate jurisdiction contains a system modernization/improvement tracker that is intended to provide recovery for leak prone pipe replacement. Amounts calculated under the tracker that are in excess of the annual amount that can be billed to the ratepayer are deferred as a regulatory asset per commission authorization. The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNA, which covers the eight-month period from October through May. The WNA is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNA as a five-year pilot program. The program became effective October 2023 and covers the eight-month period from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNA, causing weather variations to have a direct impact on the Pennsylvania rate jurisdiction’s revenues. The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. 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 of activities is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance. 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
Property, Plant and Equipment	Property, Plant and Equipment In the Company’s Exploration and Production segment, property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center. The Company’s capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $2.3 billion and $2.4 billion at September 30, 2024 and 2023, respectively. For further discussion of capitalized costs, refer to Note N — Supplementary Information for Exploration and Production Activities. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying commodity pricing (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. The book value of the exploration and production properties exceeded the ceiling at September 30, 2024 as well as at June 30, 2024. As such, the Company recognized non-cash, pre-tax ceiling test impairment charges in the Exploration and Production segment of $463.7 million for the year ended September 30, 2024. Deferred income tax benefits of $127.3 million related to the non-cash impairment charges were also recognized for the year ended September 30, 2024. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2024, 2023 and 2022, estimated future net cash flows were increased by $428.5 million, increased by $38.8 million and decreased by $1.0 billion, respectively. The Exploration and Production segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting. As discussed in Note I — Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded at September 30, 2024. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility and Gathering segments at September 30, 2024. An impairment charge related to the Northern Access Project, which is discussed at Note I — Fair Value Measurements, was recorded in the Pipeline and Storage segment at September 30, 2024. The impairment charge reduced the value of certain assets recorded in Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet. 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 exploration and production properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved exploration and production properties is excluded from this computation. Depreciation, depletion and amortization expense for exploration and production properties was $270.6 million, $235.7 million and $202.4 million for the years ended September 30, 2024, 2023 and 2022, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated useful lives of property in service.
Goodwill	Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2024 and 2023 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. 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, 2024, 2023 and 2022, 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
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, 2024, 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. 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 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 Advances
Customer Security Deposits	Customer Security Deposits
Earnings Per Common Share	Earnings Per Common Share
Share Repurchases	Share Repurchases The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note H — Capitalization and Short-Term Borrowings for further discussion of the Company’s share repurchase program.
Stock-Based Compensation	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. 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2024
Accounting Policies [Abstract]
Schedule of Allowance for Uncollectible Accounts	Activity in the allowance for uncollectible accounts are as follows: Year Ended September 30 2024 2023 2022 (Thousands) Balance at Beginning of Year $ 36,295 $ 40,228 $ 31,639 Additions Charged to Costs and Expenses 13,180 14,482 13,209 Add: Discounts on Purchased Receivables 753 1,380 1,314 Deduct: Net Accounts Receivable Written-Off 24,034 19,795 5,934 Balance at End of Year $ 26,194 $ 36,295 $ 40,228
Schedule of Depreciable Plant By Segment	The following is a summary of depreciable plant by segment: As of September 30 2024 2023 (Thousands) Exploration and Production $ 7,275,495 $ 6,741,095 Pipeline and Storage 2,919,506 2,803,690 Gathering 1,142,000 1,032,969 Utility 2,645,981 2,507,465 All Other and Corporate 15,915 15,787 $ 13,998,897 $ 13,101,006
Average Depreciation, Depletion and Amortization Rates	Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2024 2023 2022 Exploration and Production, per Mcfe(1) $ 0.71 $ 0.65 $ 0.59 Pipeline and Storage 2.7 % 2.6 % 2.7 % Gathering 3.6 % 3.6 % 3.6 % Utility 2.8 % 2.7 % 2.7 % All Other and Corporate 3.0 % 2.9 % 1.4 % (1) Amounts include depletion of exploration and production properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Exploration and Production Activities, depletion of exploration and production properties amounted to $0.69, $0.63 and $0.57 per Mcfe of production in 2024, 2023 and 2022, respectively.
Components of Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Loss and changes for the years ended September 30, 2024 and 2023, 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, 2024 Balance at October 1, 2023 $ 4,623 $ (59,683) $ (55,060) Other Comprehensive Gains and Losses Before Reclassifications 205,697 (13,515) 192,182 Amounts Reclassified From Other Comprehensive Loss (154,521) 1,923 (152,598) Balance at September 30, 2024 $ 55,799 $ (71,275) $ (15,476) 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)
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, 2024 and 2023 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 2024 2023 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $ 217,012 $ (88,015) Operating Revenues Foreign Currency Contracts (357) (641) Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (56) (82) (1) Net Actuarial Loss (2,451) (1,592) (1) 214,148 (90,330) Total Before Income Tax (61,550) 6,217 Income Tax Expense $ 152,598 $ (84,113) Net of Tax (1) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.
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 2024 2023 2022 2021 Cash and Temporary Cash Investments $ 38,222 $ 55,447 $ 46,048 $ 31,528 Hedging Collateral Deposits — — 91,670 88,610 Cash, Cash Equivalents, and Restricted Cash $ 38,222 $ 55,447 $ 137,718 $ 120,138
Schedule of Other Current Assets	The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2024 2023 (Thousands) Prepayments $ 18,463 $ 18,966 Prepaid Property and Other Taxes 14,187 14,186 Federal Income Taxes Receivable 8,154 14,602 State Income Taxes Receivable 13,161 16,133 Regulatory Assets 38,264 36,373 $ 92,229 $ 100,260
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 2024 2023 (Thousands) Accrued Capital Expenditures $ 47,344 $ 43,323 Regulatory Liabilities 29,352 38,105 Liability for Royalty and Working Interests 15,007 17,679 Non-Qualified Benefit Plan Liability 14,135 13,052 Other 57,065 48,815 $ 162,903 $ 160,974

Asset Acquisitions and Divest_2

Asset Acquisitions and Divestitures (Tables)	12 Months Ended
	Sep. 30, 2024
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, 2024
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, 2024, 2023 and 2022, presented by type of service from each reportable segment. Year Ended September 30, 2024 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 738,778 $ — $ — $ — $ 738,778 $ — $ — $ 738,778 Production of Crude Oil 2,298 — — — 2,298 — — 2,298 Natural Gas Processing 1,053 — — — 1,053 — — 1,053 Natural Gas Gathering Service — — 244,225 — 244,225 — (228,688) 15,537 Natural Gas Transportation Service — 311,900 — 103,866 415,766 — (99,658) 316,108 Natural Gas Storage Service — 95,933 — — 95,933 — (40,995) 54,938 Natural Gas Residential Sales — — — 502,744 502,744 — — 502,744 Natural Gas Commercial Sales — — — 68,466 68,466 — — 68,466 Natural Gas Industrial Sales — — — 3,103 3,103 — (5) 3,098 Other 1,937 4,560 — (1,256) 5,241 — (902) 4,339 Total Revenues from Contracts with Customers 744,066 412,393 244,225 676,923 2,077,607 — (370,248) 1,707,359 Alternative Revenue Programs — — — 20,439 20,439 — — 20,439 Derivative Financial Instruments 217,012 — — — 217,012 — — 217,012 Total Revenues $ 961,078 $ 412,393 $ 244,225 $ 697,362 $ 2,315,058 $ — $ (370,248) $ 1,944,810 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, 2024
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 2024 2023 Operating Lease Expense $ 11,827 $ 7,484 Variable Lease Expense(1) 601 507 Short-Term Lease Expense(2) 299 1,694 Total Lease Expense $ 12,727 $ 9,685 Lease Costs Recorded to Property, Plant and Equipment(3) $ 20,143 $ 24,018 (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)
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 2024 2023 Assets: Deferred Charges $ 44,206 $ 39,664 Liabilities: Other Accruals and Current Liabilities $ 11,518 $ 9,969 Other Liabilities $ 32,616 $ 29,510
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, 2024 (in thousands): At September 30, 2024 2025 $ 11,801 2026 9,653 2027 8,880 2028 7,707 2029 4,478 Thereafter 9,234 Total Lease Payments 51,753 Less: Interest (7,619) Total Lease Liability $ 44,134

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Sep. 30, 2024
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 2024 2023 2022 (Thousands) Balance at Beginning of Year $ 165,492 $ 161,545 $ 209,639 Liabilities Incurred 2,367 3,313 2,401 Revisions of Estimates 51,967 6,728 10,700 Liabilities Settled (25,556) (14,448) (71,171) Accretion Expense 8,736 8,354 9,976 Balance at End of Year $ 203,006 $ 165,492 $ 161,545

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2024
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 2024 2023 (Thousands) Regulatory Assets: Pension Costs(1) (Note K) $ 30,259 $ 20,459 Post-Retirement Benefit Costs(1) (Note K) 7,932 2,536 Recoverable Future Taxes (Note G) 80,084 69,045 System Modernization / Improvement Tracker (2) (See Regulatory Mechanisms in Note A) 47,043 30,375 Asset Retirement Obligations(1) (Note E) 21,951 19,384 Unamortized Debt Expense (Note A) 5,604 7,240 Other(3) 39,101 35,757 Total Regulatory Assets 231,974 184,796 Less: Amounts Included in Other Current Assets (38,264) (36,373) Total Long-Term Regulatory Assets $ 193,710 $ 148,423 At September 30 2024 2023 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 292,477 $ 277,694 Taxes Refundable to Customers (Note G) 305,645 268,562 Post-Retirement Benefit Costs(5) (Note K) 141,199 159,760 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 42,720 59,019 Environmental Site Remediation Costs(4) (Note L) 5,390 619 Other(6) 34,215 43,167 Total Regulatory Liabilities 821,646 808,821 Less: Amounts included in Current and Accrued Liabilities (72,072) (97,124) Total Long-Term Regulatory Liabilities $ 749,574 $ 711,697 (1) Included in Other Regulatory Assets on the Consolidated Balance Sheets. (2) $15,681 and $19,584 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $31,362 and $10,791 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. (3) $22,583 and $16,789 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $16,518 and $18,968 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2024 and 2023, since such amounts are expected to be passed back to ratepayers in the next 12 months. $135,399 and $153,960 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. (6) $23,552 and $32,305 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,663 and $10,862 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2024
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 2024 2023 2022 (Thousands) Current Income Taxes — Federal $ 6,453 $ 11,744 $ — State 5,899 1,386 12,214 Deferred Income Taxes — Federal 894 106,801 137,025 State (3,504) 44,602 (32,610) Total Income Taxes $ 9,742 $ 164,533 $ 116,629
Schedule of Income Tax Reconciliation by Applying Federal Income Tax Rate	The following is a reconciliation of this difference: Year Ended September 30 2024 2023 2022 (Thousands) U.S. Income Before Income Taxes $ 87,255 $ 641,399 $ 682,650 Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21% $ 18,324 $ 134,694 $ 143,357 State Valuation Allowance (1) — — (24,850) State Income Taxes (2) 1,892 36,331 8,736 Amortization of Excess Deferred Federal Income Taxes (5,607) (6,053) (5,184) Plant Flow Through Items (6,135) (2,856) (814) Stock Compensation 1,758 957 820 Federal Tax Credits (5) (6) (5,701) Miscellaneous (485) 1,466 265 Total Income Taxes $ 9,742 $ 164,533 $ 116,629 (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 2024 2023 (Thousands) Deferred Tax Liabilities: Unrealized Hedging Gains $ 22,433 $ 3,385 Property, Plant and Equipment 1,134,727 1,178,893 Pension and Other Post-Retirement Benefit Costs 59,877 44,358 Other 13,885 21,470 Total Deferred Tax Liabilities 1,230,922 1,248,106 Deferred Tax Assets: Tax Loss and Credit Carryforwards (31,111) (33,744) Pension and Other Post-Retirement Benefit Costs (49,622) (41,843) Other (39,024) (48,349) Total Deferred Tax Assets (119,757) (123,936) Total Net Deferred Income Taxes $ 1,111,165 $ 1,124,170
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 2024 2023 2022 (Thousands) Balance at Beginning of Year $ — $ — $ 57,645 Additions — — — Deductions — — 57,645 Balance at End of Year $ — $ — $ —
Summary of Operating Loss and Tax Credit Carryforwards	Tax carryforwards available at September 30, 2024, were as follows: Jurisdiction Tax Attribute Amount Expires Pennsylvania Net Operating Loss $ 438,058 2031-2044

Capitalization and Short-Term_2

Capitalization and Short-Term Borrowings (Tables)	12 Months Ended
	Sep. 30, 2024
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, 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 (55,060) Net Income Available for Common Stock 77,513 Dividends Declared on Common Stock ($2.02 Per Share) (185,220) Other Comprehensive Income, Net of Tax 39,584 Share-Based Payment Expense(1) 19,868 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 333 333 (1,955) Share Repurchases Under Repurchase Plan (1,146) (1,146) (13,187) (50,823) Balance at September 30, 2024 91,006 $ 91,006 $ 1,045,487 $ 1,727,326 (2) $ (15,476) (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, 2024, $1.6 billion of accumulated earnings was free of such limitations.
Schedule of Share-Based Compensation for Non-Performance Based Restricted Stock Units	Transactions for 2024 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2023 342,186 $ 49.63 Granted in 2024 220,778 $ 42.44 Vested in 2024 (115,337) $ 46.92 Forfeited in 2024 (9,434) $ 50.43 Outstanding at September 30, 2024 438,193 $ 46.70
Schedule of Share-Based Compensation for Performance Shares	Transactions for 2024 involving performance shares for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2023 586,791 $ 55.46 Granted in 2024 361,729 $ 44.23 Vested in 2024 (251,255) $ 38.62 Forfeited in 2024 (35,357) $ 46.49 Change in Units Based on Performance Achieved 57,669 $ 37.36 Outstanding at September 30, 2024 719,577 $ 54.69
Schedule of Weighted Average Assumptions Used in Estimating Fair Value	The following weighted average assumptions were used in estimating the fair value of the TSR performance shares at the date of grant: Year Ended September 30 2024 2023 2022 Risk-Free Interest Rate 4.36 % 4.03 % 0.85 % Remaining Term at Date of Grant (Years) 2.98 2.80 2.80 Expected Volatility 23.9 % 31.6 % 29.7 % 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 2024 2023 (Thousands) Medium-Term Notes(1): 7.38% due June 2025 $ 50,000 $ 50,000 Notes(1)(2)(3): 2.95% to 5.50% due July 2025 to March 2031 2,350,000 2,350,000 Delayed Draw Term Loan(4): Variable Rate due February 2026 300,000 — Total Long-Term Debt 2,700,000 2,400,000 Less Unamortized Discount and Debt Issuance Costs 11,757 15,515 Less Current Portion(5) 500,000 — $ 2,188,243 $ 2,384,485 (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) The interest rate on the delayed draw term loan is a weighted average SOFR interest rate of 6.71% that was locked in from April 2024 until the beginning of October 2024. The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100.0 million until January 2025. (5)

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2024
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, 2024 and 2023. 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, 2024 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 29,238 $ — $ — $ — $ 29,238 Derivative Financial Instruments: Over the Counter Swaps — Gas — 76,009 — (17,198) 58,811 Over the Counter No Cost Collars — Gas — 32,584 — (3,774) 28,810 Contingent Consideration for Asset Sale — 729 — — 729 Foreign Currency Contracts — 281 — (726) (445) Other Investments: Balanced Equity Mutual Fund 19,523 — — — 19,523 Fixed Income Mutual Fund 17,374 — — — 17,374 Total $ 66,135 $ 109,603 $ — $ (21,698) $ 154,040 Liabilities: Derivative Financial Instruments: Over the Counter Swaps — Gas $ — $ 22,206 $ — $ (17,198) $ 5,008 Over the Counter No Cost Collars — Gas — 3,501 — (3,774) (273) Foreign Currency Contracts — 726 — (726) — Total $ — $ 26,433 $ — $ (21,698) $ 4,735 Total Net Assets/(Liabilities) $ 66,135 $ 83,170 $ — $ — $ 149,305 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 (1)
Fair Value Measurements, Nonrecurring	The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of September 30, 2024, 2023 and 2022 (in thousands): Impairments Nonrecurring Fair Value Measures Year Ended September 30, Segment Date of Measurement Fair Value 2024 2023 2022 Impairment of Assets: Northern Access Project Pipeline and Storage September 30, 2024 $ 12,133 $ 46,075 $ — $ — Water Disposal Assets Exploration and Production September 30, 2024 $ 3,000 9,362 — — Total Impairment $ 55,437 $ — $ —

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Sep. 30, 2024
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 2024 Carrying Amount 2024 Fair Value 2023 Carrying Amount 2023 Fair Value (Thousands) Long-Term Debt $ 2,688,243 $ 2,656,888 $ 2,384,485 $ 2,210,478
Schedule of Other Investments	The components of the Company’s Other Investments are as follows (in thousands): At September 30 2024 2023 (Thousands) Life Insurance Contracts $ 44,808 $ 42,242 Equity Mutual Fund 19,523 15,837 Fixed Income Mutual Fund 17,374 15,897 $ 81,705 $ 73,976
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, 2024 and 2023 (Dollar Amounts in Thousands) Derivatives in Cash Amount of Location of Amount of 2024 2023 2024 2023 Commodity Contracts $ 286,392 $ 708,234 Operating Revenue $ 217,012 $ (88,015) Foreign Currency Contracts 502 (28) Operating Revenue (357) (641) Total $ 286,894 $ 708,206 $ 216,655 $ (88,656)

Retirement Plan and Other Pos_2

Retirement Plan and Other Post-Retirement Benefits (Tables)	12 Months Ended
	Sep. 30, 2024
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 2024 2023 2022 2024 2023 2022 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 768,750 $ 813,828 $ 1,098,456 $ 274,278 $ 299,283 $ 431,213 Service Cost 4,197 5,187 8,758 434 587 1,328 Interest Cost 43,558 42,516 22,827 15,561 15,648 9,066 Plan Participants’ Contributions — — — 3,401 3,297 3,271 Retiree Drug Subsidy Receipts — — — 1,208 2,969 312 Actuarial (Gain) Loss 72,016 (27,313) (251,173) 54,443 (20,789) (120,276) Benefits Paid (66,215) (65,468) (65,040) (28,300) (26,717) (25,631) Benefit Obligation at End of Period $ 822,306 $ 768,750 $ 813,828 $ 321,025 $ 274,278 $ 299,283 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 784,712 $ 845,205 $ 1,095,729 $ 455,702 $ 461,438 $ 575,565 Actual Return on Plan Assets 105,488 4,975 (205,884) 64,783 17,449 (94,849) Employer Contributions — — 20,400 479 235 3,082 Plan Participants’ Contributions — — — 3,401 3,297 3,271 Benefits Paid (66,215) (65,468) (65,040) (28,300) (26,717) (25,631) Fair Value of Assets at End of Period $ 823,985 $ 784,712 $ 845,205 $ 496,065 $ 455,702 $ 461,438 Net Amount Recognized at End of Period (Funded Status) $ 1,679 $ 15,962 $ 31,377 $ 175,040 $ 181,424 $ 162,155 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ — $ — $ — $ (3,511) $ (2,915) $ (3,065) Non-Current Assets 1,679 15,962 31,377 178,551 184,339 165,220 Net Amount Recognized at End of Period $ 1,679 $ 15,962 $ 31,377 $ 175,040 $ 181,424 $ 162,155 Accumulated Benefit Obligation $ 804,916 $ 751,912 $ 793,555 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 4.97 % 5.99 % 5.57 % 4.98 % 5.99 % 5.56 % Rate of Compensation Increase 4.60 % 4.60 % 4.60 % 4.60 % 4.60 % 4.60 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2024 2023 2022 2024 2023 2022 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 4,197 $ 5,187 $ 8,758 $ 434 $ 587 $ 1,328 Interest Cost 43,558 42,516 22,827 15,561 15,648 9,066 Expected Return on Plan Assets (68,343) (66,593) (52,294) (26,642) (25,612) (29,359) Amortization of Prior Service Cost (Credit) 362 436 537 (429) (429) (429) Recognition of Actuarial (Gain) Loss(1) (1,339) (7,680) 26,405 (2,266) (8,755) (7,610) Net Amortization and Deferral for Regulatory Purposes 16,231 21,512 16,854 8,759 15,157 21,340 Net Periodic Benefit Cost (Income) $ (5,334) $ (4,622) $ 23,087 $ (4,583) $ (3,404) $ (5,664) Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 5.99 % 5.57 % 2.75 % 5.99 % 5.56 % 2.76 % Effective Rate for Interest on Benefit Obligations 5.93 % 5.45 % 2.14 % 5.93 % 5.45 % 2.17 % Effective Discount Rate for Service Cost 6.01 % 5.49 % 2.95 % 5.99 % 5.35 % 3.00 % Effective Rate for Interest on Service Cost 5.98 % 5.53 % 2.70 % 6.01 % 5.47 % 2.93 % Expected Return on Plan Assets 7.40 % 6.90 % 5.20 % 6.00 % 5.70 % 5.20 % Rate of Compensation Increase 4.60 % 4.60 % 4.70 % 4.60 % 4.60 % 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 2024, as well as the changes in such amounts during 2024, 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 Loss $ (164,328) $ (128) $ (13,394) Prior Service (Cost) Credit (1,674) 686 — Net Amount Recognized $ (166,002) $ 558 $ (13,394) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2024(1) Increase in Actuarial Loss, excluding amortization(2) $ (34,871) $ (16,302) $ (880) Change due to Amortization of Actuarial (Gain) Loss (1,339) (2,266) 4,772 Prior Service (Cost) Credit 362 (429) — Net Change $ (35,848) $ (18,997) $ 3,892 (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 2025 $ 25,736 $ (1,696) 2026 $ 26,193 $ (1,745) 2027 $ 26,534 $ (1,782) 2028 $ 26,775 $ (1,806) 2029 $ 26,804 $ (1,829) 2030 through 2034 $ 128,836 $ (9,197)
Schedule of Health Care Cost Trend Rates	Assumed health care cost trend rates as of September 30 were: 2024 2023 2022 Rate of Medical Cost Increase for Pre Age 65 Participants 6.25 % (1) 6.25 % (2) 5.30 % (3) Rate of Medical Cost Increase for Post Age 65 Participants 5.75 % (1) 5.00 % (2) 4.84 % (3) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 10.25 % (1) 6.85 % (2) 6.29 % (3) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 5.75 % (1) 5.00 % (2) 4.84 % (3) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 4.00 % (1) 6.60 % (2) 5.96 % (3) (1) It was assumed that this rate would gradually decline to 4% by 2049. (2) It was assumed that this rate would gradually decline to 4% by 2048. (3) 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, 2024 and 2023, 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, 2024 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 37,984 $ 37,984 $ — $ — $ — Global Equities(2) 38,234 — — — 38,234 Domestic Fixed Income(3)(7) 681,755 — 633,600 — 48,155 International Fixed Income(4) 8,587 — 8,587 — — Real Estate (5) 109,383 — — — 109,383 Cash Held in Collective Trust Funds 41,709 — — — 41,709 Total Retirement Plan Investments 917,652 37,984 642,187 — 237,481 401(h) Investments (83,682) (3,500) (59,166) — (21,016) Total Retirement Plan Investments (excluding 401(h) Investments) $ 833,970 $ 34,484 $ 583,021 $ — $ 216,465 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (9,985) Total Retirement Plan Assets $ 823,985 At September 30, 2023 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 37,611 $ 37,611 $ — $ — $ — Global Equities(2) 36,088 — — — 36,088 Domestic Fixed Income(3) 612,820 — 556,504 — 56,316 International Fixed Income(4) 7,778 — 7,778 — — Real Estate (5) 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 (1) Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. (2) Global Equities are comprised of collective trust funds. (3) Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. (4) International Fixed Income securities are comprised mostly of corporate/government bonds. (5) Real Estate consists of investments held in a collective trust fund and a partnership. (6) Reflects the authoritative guidance related to investments measured at net asset value (NAV). (7) Domestic Fixed Income securities include $8.5 million of derivative instruments used as part of the Company’s overall liability-driven investment strategy as a way to assist in matching the duration of the assets of the Retirement Plan investments with its liability to plan participants. At September 30, 2024 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 82,814 $ — $ — $ — $ 82,814 Exchange Traded Funds — Fixed Income 314,052 314,052 — — — Cash Held in Collective Trust Funds 14,274 — — — 14,274 Total VEBA Trust Investments 411,140 314,052 — — 97,088 401(h) Investments 83,682 3,500 59,166 — 21,016 Total Investments (including 401(h) Investments) $ 494,822 $ 317,552 $ 59,166 $ — $ 118,104 Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 1,243 Total Other Post-Retirement Benefit Assets $ 496,065 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 (1) Reflects the authoritative guidance related to investments measured at net asset value (NAV).

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Sep. 30, 2024
Segment Reporting [Abstract]
Schedule of Information by Segment	Year Ended September 30, 2024 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 961,078 $ 271,388 $ 15,537 $ 696,807 $ 1,944,810 $ — $ — $ 1,944,810 Intersegment Revenues $ — $ 141,005 $ 228,688 $ 555 $ 370,248 $ — $ (370,248) $ — Interest Income $ 2,729 $ 8,632 $ 333 $ 5,736 $ 17,430 $ — $ (8,703) $ 8,727 Interest Expense $ 59,799 $ 47,428 $ 14,206 $ 34,727 $ 156,160 $ 374 $ (17,839) $ 138,695 Depreciation, Depletion and Amortization $ 277,945 $ 74,530 $ 38,817 $ 65,261 $ 456,553 $ — $ 473 $ 457,026 Significant Non-Cash Item: Impairment of Assets $ 473,054 $ 46,075 $ — $ — $ 519,129 $ — $ — $ 519,129 Income Tax Expense (Benefit) $ (58,430) $ 26,045 $ 38,217 $ 3,951 $ 9,783 $ (186) $ 145 $ 9,742 Segment Profit: Net Income (Loss) $ (163,954) $ 79,670 $ 106,913 $ 57,089 $ 79,718 $ (617) $ (1,588) $ 77,513 Expenditures for Additions to Long-Lived Assets $ 536,349 $ 110,830 $ 109,251 $ 184,615 $ 941,045 $ — $ 970 $ 942,015 At September 30, 2024 (Thousands) Segment Assets $ 2,644,820 $ 2,446,243 $ 987,103 $ 2,398,709 $ 8,476,875 $ 6,227 $ (163,332) $ 8,319,770 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 (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 2024 2023 2022 (Thousands) Long-Lived Assets: United States $ 7,963,851 $ 7,865,832 $ 7,135,131

Supplementary Information for_2

Supplementary Information for Exploration and Production Activities (Tables)	12 Months Ended
	Sep. 30, 2024
Supplementary Information for Exploration and Production Activities Unaudited [Abstract]
Schedule of Capitalized Costs Relating to Exploration and Production Activities	Capitalized Costs Relating to Exploration and Production Activities At September 30 2024 2023 (Thousands) Proved Properties(1) $ 7,079,903 $ 6,555,088 Unproved Properties 200,986 161,097 7,280,889 6,716,185 Less — Accumulated Depreciation, Depletion and Amortization 5,004,299 4,269,959 $ 2,276,590 $ 2,446,226 (1) Includes asset retirement costs of $175.2 million and $129.2 million at September 30, 2024 and 2023, respectively.
Summary of Capitalized Costs of Unproved Properties Excluded from Amortization	Following is a summary of costs excluded from amortization at September 30, 2024: Total as of September 30, 2024 Year Costs Incurred 2024 2023 2022 Prior (Thousands) Acquisition Costs $ 140,753 $ 8,136 $ 104,858 $ 2,072 $ 25,687 Development Costs 48,642 46,597 1,821 185 39 Exploration Costs 10,813 10,813 — — — Capitalized Interest 778 778 — — — $ 200,986 $ 66,324 $ 106,679 $ 2,257 $ 25,726
Schedule of Costs Incurred in Property Acquisition, Exploration and Development Activities	Costs Incurred in Property Acquisition, Exploration and Development Activities Year Ended September 30 2024 2023 2022 (Thousands) United States Property Acquisition Costs: Proved $ 17,069 $ 33,190 $ 2,491 Unproved 19,526 129,061 10,665 Exploration Costs(1) 53,519 10,055 9,631 Development Costs(2) 429,151 553,469 528,684 Asset Retirement Costs 46,017 8,363 9,768 $ 565,282 $ 734,138 $ 561,239 (1) Amounts for 2024, 2023 and 2022 include capitalized interest of $0.1 million, zero and zero respectively. (2) Amounts for 2024, 2023 and 2022 include capitalized interest of $0.7 million, $0.1 million and $0.6 million, respectively.
Schedule of Results of Operations for Producing Activities	Results of Operations for Producing Activities Year Ended September 30 2024 2023 2022 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of $1,557, $1,957 and $5,696, respectively)(1) $ 738,778 $ 1,036,499 $ 1,730,723 Oil, Condensate and Other Liquids 2,298 2,261 150,957 Total Operating Revenues(2) 741,076 1,038,760 1,881,680 Production/Lifting Costs 270,927 253,555 283,914 Franchise/Ad Valorem Taxes 13,468 17,532 25,112 Purchased Emission Allowance Expense — — 1,305 Accretion Expense 5,992 5,673 7,530 Depreciation, Depletion and Amortization ($0.69, $0.63 and $0.57 per Mcfe of production, respectively) 270,648 235,694 202,418 Impairment of Exploration and Production Properties 463,692 — — Income Tax Expense (Benefit) (76,983) 145,574 368,925 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ (206,668) $ 380,732 $ 992,476 (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 Gas and Oil Reserve Quantities	Gas MMcf U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Extensions and Discoveries 601,679 (1) — 601,679 Revisions of Previous Estimates 7,046 — 7,046 Production (392,047) (2) — (392,047) September 30, 2024 4,751,762 — 4,751,762 Proved Developed Reserves: 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 September 30, 2024 3,484,852 — 3,484,852 Proved Undeveloped Reserves: September 30, 2021 631,970 — 631,970 September 30, 2022 858,094 — 858,094 September 30, 2023 985,050 — 985,050 September 30, 2024 1,266,910 — 1,266,910 (1) Extensions and discoveries include 301 Bcf (during 2022), 163 Bcf (during 2023) and 230 Bcf (during 2024), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 537 Bcf (during 2022), 507 Bcf (during 2023) and 372 Bcf (during 2024), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 209,463 MMcf (during 2022), 190,290 MMcf (during 2023) and 235,955 MMcf (during 2024), from Marcellus Shale fields. Production includes 130,240 MMcf (during 2022), 180,750 MMcf (during 2023) and 154,701 MMcf (during 2024), from Utica Shale fields. Oil Mbbl U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: 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 Revisions of Previous Estimates 8 — 8 Production (31) — (31) September 30, 2024 193 — 193 Proved Developed Reserves: September 30, 2021 11 20,930 20,941 September 30, 2022 250 — 250 September 30, 2023 216 — 216 September 30, 2024 193 — 193 Proved Undeveloped Reserves: September 30, 2021 — 596 596 September 30, 2022 — — — September 30, 2023 — — — September 30, 2024 — — —
Schedule of Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves	Year Ended September 30 2024 2023 2022 (Thousands) United States Future Cash Inflows $ 8,514,126 $ 11,947,345 $ 19,209,099 Less: Future Production Costs 3,672,901 3,538,389 3,138,226 Future Development Costs 1,191,708 1,095,096 781,847 Future Income Tax Expense at Applicable Statutory Rate 826,094 1,867,457 3,876,272 Future Net Cash Flows 2,823,423 5,446,403 11,412,754 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,486,968 2,874,295 5,964,424 Standardized Measure of Discounted Future Net Cash Flows $ 1,336,455 $ 2,572,108 $ 5,448,330
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 2024 2023 2022 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 2,572,108 $ 5,448,330 $ 2,353,572 Sales, Net of Production Costs (456,506) (767,487) (1,572,402) Net Changes in Prices, Net of Production Costs (1,829,714) (3,918,392) 4,132,889 Extensions and Discoveries (11,007) 237,057 1,355,257 Changes in Estimated Future Development Costs 32,990 (222,233) (32,160) Purchases of Minerals in Place — 34,346 — Sales of Minerals in Place — — (311,308) Previously Estimated Development Costs Incurred 305,602 342,024 154,253 Net Change in Income Taxes at Applicable Statutory Rate 462,075 959,728 (1,180,349) Revisions of Previous Quantity Estimates 19,216 33,192 3,316 Accretion of Discount and Other 241,691 425,543 545,262 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,336,455 $ 2,572,108 $ 5,448,330

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Allowance of Uncollectible Amounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Allowance for Uncollectible Accounts [Roll Forward]
Balance at Beginning of Year	$ 36,295	$ 40,228	$ 31,639
Additions Charged to Costs and Expenses	13,180	14,482	13,209
Add: Discounts on Purchased Receivables	753	1,380	1,314
Deduct: Net Accounts Receivable Written-Off	24,034	19,795	5,934
Balance at End of Year	$ 26,194	$ 36,295	$ 40,228

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Summary of Significant Accounting Policies [Line Items]
Weather impact on revenues tempered by WNA, period	8 months
Above/below average weather normalized usage, surcharge calculation period	12 months
Capitalized costs relating to exploration and production activities, net	$ 2,276,590	$ 2,446,226
Full cost ceiling test discount factor (as a percent)	10%
Impairment Of Exploration And Production Properties	$ 463,700
Increase (decrease) estimated future net cash flows	428,500	38,800	$ (1,000,000)
Depreciation, depletion and amortization for exploration and production properties	270,648	235,694	$ 202,418
Goodwill	5,476	5,476
Prior service cost	400	400
Accumulated losses	70,900	59,300
Gas stored underground	$ 35,055	32,509
Rate recovery period	4 years
Balanced billing, estimated annual usage, payment period	12 months
Customer advances	$ 19,373	21,003
Customer security deposits	$ 36,265	$ 28,764
Antidilutive securities (in shares)	569	3,888	2,858
Impairment Of Exploration And Production Properties
Summary of Significant Accounting Policies [Line Items]
Deferred income tax benefit	$ 127,300
Amount Exceeds LIFO Basis
Summary of Significant Accounting Policies [Line Items]
Gas stored underground	8,300
LIFO Method
Summary of Significant Accounting Policies [Line Items]
Gas stored underground	$ 35,000

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Schedule of Depreciable Plant by Segment (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Segment Reporting Information [Line Items]
Depreciable plant	$ 13,998,897	$ 13,101,006
Exploration and Production
Segment Reporting Information [Line Items]
Depreciable plant	7,275,495	6,741,095
Pipeline and Storage
Segment Reporting Information [Line Items]
Depreciable plant	2,919,506	2,803,690
Gathering
Segment Reporting Information [Line Items]
Depreciable plant	1,142,000	1,032,969
Utility
Segment Reporting Information [Line Items]
Depreciable plant	2,645,981	2,507,465
All Other and Corporate
Segment Reporting Information [Line Items]
Depreciable plant	$ 15,915	$ 15,787

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Average Depreciation, Depletion and Amortization Rates (Details) - USD ($)		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Exploration and Production
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization rate (in dollars per Mcfe of production)	[1]	$ 0.71	$ 0.65	$ 0.59
Pipeline and Storage
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.70%	2.60%	2.70%
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		2.80%	2.70%	2.70%
All Other and Corporate
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		3%	2.90%	1.40%
Exploration and Production Properties
Segment Reporting Information [Line Items]
Depreciation, depletion and amortization rate (in dollars per Mcfe of production)		$ 0.69	$ 0.63	$ 0.57
[1] Amounts include depletion of exploration and production properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Exploration and Production Activities, depletion of exploration and production properties amounted to $0.69, $0.63 and $0.57 per Mcfe of production in 2024, 2023 and 2022, respectively.

Summary of Significant Accoun_8

Summary of Significant Accounting Policies - Components of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ (55,060)	$ (625,733)
Other Comprehensive Gains and Losses Before Reclassifications	192,182	486,560
Amounts Reclassified From Other Comprehensive Loss	(152,598)	84,113
Ending balance	(15,476)	(55,060)
Gains and Losses on Derivative Financial Instruments
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	4,623	(572,163)
Other Comprehensive Gains and Losses Before Reclassifications	205,697	493,936
Amounts Reclassified From Other Comprehensive Loss	(154,521)	82,850
Ending balance	55,799	4,623
Funded Status of the Pension and Other Post-Retirement Benefit Plans
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(59,683)	(53,570)
Other Comprehensive Gains and Losses Before Reclassifications	(13,515)	(7,376)
Amounts Reclassified From Other Comprehensive Loss	1,923	1,263
Ending balance	$ (71,275)	$ (59,683)

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, 2024	Sep. 30, 2023	Sep. 30, 2022
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ 1,944,810	$ 2,173,771	$ 2,186,046
Total Before Income Tax		87,255	641,399	682,650
Income Tax Expense		(9,742)	(164,533)	(116,629)
Net of Tax		77,513	476,866	$ 566,021
Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss)
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Total Before Income Tax		214,148	(90,330)
Income Tax Expense		(61,550)	6,217
Net of Tax		152,598	(84,113)
Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Income (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]	(56)	(82)
Net Actuarial Loss	[1]	(2,451)	(1,592)
Commodity Contracts | Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) | Gains (Losses) on Derivative Financial Instruments
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		217,012	(88,015)
Foreign Currency Contracts | Amount of Gain or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) | Gains (Losses) on Derivative Financial Instruments
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ (357)	$ (641)
[1] These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.

Summary of Significant Accou_10

Summary of Significant Accounting Policies - Consolidated Statement of Cash Flows (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Accounting Policies [Abstract]
Cash and Temporary Cash Investments	$ 38,222	$ 55,447	$ 46,048	$ 31,528
Hedging Collateral Deposits	0	0	91,670	88,610
Cash, Cash Equivalents, and Restricted Cash	$ 38,222	$ 55,447	$ 137,718	$ 120,138

Summary of Significant Accou_11

Summary of Significant Accounting Policies - Components of Other Current Assets (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Summary of Significant Accounting Policies [Line Items]
Prepayments	$ 18,463	$ 18,966
Prepaid Property and Other Taxes	14,187	14,186
Regulatory Assets	38,264	36,373
Other Current Assets	92,229	100,260
Federal
Summary of Significant Accounting Policies [Line Items]
Income Taxes Receivable	8,154	14,602
State
Summary of Significant Accounting Policies [Line Items]
Income Taxes Receivable	$ 13,161	$ 16,133

Summary of Significant Accou_12

Summary of Significant Accounting Policies - Schedule of Other Accruals and Current Liabilities (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Summary Of Significant Accounting Policies [Abstract]
Accrued Capital Expenditures	$ 47,344	$ 43,323
Regulatory Liabilities	29,352	38,105
Liability for Royalty and Working Interests	15,007	17,679
Non-Qualified Benefit Plan Liability	14,135	13,052
Other	57,065	48,815
Other Accruals and Current Liabilities	$ 162,903	$ 160,974

Asset Acquisitions and Divest_3

Asset Acquisitions and Divestitures - Narrative (Details)			12 Months Ended				36 Months Ended
	Jun. 01, 2023 USD ($) a	Jun. 30, 2022 USD ($)	Sep. 30, 2024 USD ($)	Dec. 31, 2023 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2025 USD ($) payment
Asset Acquisition [Line Items]
Net Proceeds from Sale of Exploration and Production Properties			$ 0		$ 0	$ 254,439,000
Gain on Sale of Assets			0		0	12,736,000
Reduction in asset retirement obligation			25,556,000		14,448,000	$ 71,171,000
California Asset Sale
Asset Acquisition [Line Items]
Total sale price		$ 253,500,000
Net Proceeds from Sale of Exploration and Production 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
Asset Acquisition [Line Items]
ICE Brent Average (in dollars per barrel)				$ 95
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	$ 700,000		$ 7,300,000
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, 2024	Sep. 30, 2023	Sep. 30, 2022
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	$ 1,707,359	$ 2,254,894	$ 3,061,283
Alternative Revenue Programs	20,439	6,892	7,357
Derivative Financial Instruments	217,012	(88,015)	(882,594)
Total Revenues	1,944,810	2,173,771	2,186,046
Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	2,077,607	2,591,446	3,375,809
Alternative Revenue Programs	20,439	6,892	7,357
Derivative Financial Instruments	217,012	(88,015)	(882,594)
Total Revenues	2,315,058	2,510,323	2,500,572
All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	6
Alternative Revenue Programs	0	0	0
Derivative Financial Instruments	0	0	0
Total Revenues	0	0	6
Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	(370,248)	(336,552)	(314,532)
Alternative Revenue Programs	0	0	0
Derivative Financial Instruments	0	0	0
Total Revenues	(370,248)	(336,552)	(314,532)
Exploration and Production | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	744,066	1,046,470	1,893,058
Alternative Revenue Programs	0	0	0
Derivative Financial Instruments	217,012	(88,015)	(882,594)
Total Revenues	961,078	958,455	1,010,464
Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	412,393	379,191	377,044
Alternative Revenue Programs	0	0	0
Derivative Financial Instruments	0	0	0
Total Revenues	412,393	379,191	377,044
Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	244,225	230,317	214,843
Alternative Revenue Programs	0	0	0
Derivative Financial Instruments	0	0	0
Total Revenues	244,225	230,317	214,843
Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	676,923	935,468	890,864
Alternative Revenue Programs	20,439	6,892	7,357
Derivative Financial Instruments	0	0	0
Total Revenues	697,362	942,360	898,221
Production of Natural Gas
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	738,778	1,036,499	1,730,723
Production of Natural Gas | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	738,778	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	0
Production of Natural Gas | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Production of Natural Gas | Exploration and Production | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	738,778	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	0
Production of Natural Gas | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Production of Natural Gas | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Production of Crude Oil
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	2,298	2,261	150,957
Production of Crude Oil | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	2,298	2,261	150,957
Production of Crude Oil | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Production of Crude Oil | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Production of Crude Oil | Exploration and Production | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	2,298	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	0
Production of Crude Oil | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Production of Crude Oil | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Processing
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	1,053	1,203	3,511
Natural Gas Processing | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	1,053	1,203	3,511
Natural Gas Processing | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Processing | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Processing | Exploration and Production | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	1,053	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	0
Natural Gas Processing | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Processing | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Gathering Service
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	15,537	13,891	12,086
Natural Gas Gathering Service | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	244,225	230,317	214,843
Natural Gas Gathering Service | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Gathering Service | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	(228,688)	(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	0
Natural Gas Gathering Service | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Gathering Service | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	244,225	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	0
Natural Gas Transportation Service
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	316,108	306,640	321,713
Natural Gas Transportation Service | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	415,766	389,529	396,462
Natural Gas Transportation Service | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Transportation Service | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	(99,658)	(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	0
Natural Gas Transportation Service | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	311,900	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	0
Natural Gas Transportation Service | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	103,866	98,304	106,495
Natural Gas Storage Service
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	54,938	48,679	48,183
Natural Gas Storage Service | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	95,933	84,962	84,565
Natural Gas Storage Service | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Storage Service | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	(40,995)	(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	0
Natural Gas Storage Service | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	95,933	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	0
Natural Gas Storage Service | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Residential Sales
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	502,744	727,728	688,271
Natural Gas Residential Sales | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	502,744	727,728	688,271
Natural Gas Residential Sales | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Residential Sales | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	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	0
Natural Gas Residential Sales | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Residential Sales | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Residential Sales | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	502,744	727,728	688,271
Natural Gas Commercial Sales
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	68,466	103,270	95,114
Natural Gas Commercial Sales | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	68,466	103,270	95,114
Natural Gas Commercial Sales | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Commercial Sales | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	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	0
Natural Gas Commercial Sales | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Commercial Sales | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Commercial Sales | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	68,466	103,270	95,114
Natural Gas Industrial Sales
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	3,098	5,651	4,902
Natural Gas Industrial Sales | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	3,103	5,658	4,902
Natural Gas Industrial Sales | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Industrial Sales | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	(5)	(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	0
Natural Gas Industrial Sales | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Industrial Sales | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Natural Gas Industrial Sales | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	3,103	5,658	4,902
Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	4,339	9,072	5,823
Other | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	5,241	10,019	6,461
Other | All Other
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	6
Other | Corporate and Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	(902)	(947)	(644)
Other | Exploration and Production | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	1,937	6,507	7,867
Other | Pipeline and Storage | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	4,560	3,004	2,512
Other | Gathering | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	0	0	0
Other | Utility | Total Reportable Segments
Disaggregation of Revenue [Line Items]
Total Revenues from Contracts with Customers	$ (1,256)	$ 508	$ (3,918)

Revenue from Contracts with C_4

Revenue from Contracts with Customers - Narrative (Details) $ in Millions	12 Months Ended
	Sep. 30, 2024 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]: 2024-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 233.8
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	$ 183.5
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	$ 142.9
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	$ 123.4
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	$ 109.1
Remaining performance obligations, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 523.1
Remaining performance obligations, period

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($)	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023
Lessee, Lease, Description [Line Items]
Weighted average remaining lease term	5 years 8 months 12 days	6 years 1 month 6 days
Weighted average discount rate	5.68%	5.48%
Cash paid for operating liabilities	$ 12,700,000	$ 9,700,000
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	10 months
Operating lease renewal term	1 year
Buildings and Property | Maximum
Lessee, Lease, Description [Line Items]
Non-cancelable lease term	15 years
Operating lease renewal term	16 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	2 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, 2024	Sep. 30, 2023
Lessee, Lease, Description [Line Items]
Operating Lease Expense		$ 11,827	$ 7,484
Variable Lease Expense	[1]	601	507
Short-Term Lease Expense/Costs	[2]	299	1,694
Total Lease Expense		12,727	9,685
Exploration and Production Properties
Lessee, Lease, Description [Line Items]
Lease Costs Recorded to Property, Plant and Equipment	[3]	$ 20,143	$ 24,018
[1] Variable lease payments that are not dependent on an index or rate are not included in the lease liability. Short-term lease costs exclude expenses related to leases with a lease term of one month or less. Lease costs relating to drilling rig leases that are capitalized as part of exploration and production properties under full cost pool accounting as well as certain equipment leases used on construction projects.

Leases - Balance Sheet Informat

Leases - Balance Sheet Information Related to Operating Leases (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Assets:
Deferred Charges	$ 44,206	$ 39,664
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Deferred Charges	Deferred Charges
Liabilities:
Other Accruals and Current Liabilities	$ 11,518	$ 9,969
Other Liabilities	$ 32,616	$ 29,510
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, 2024 USD ($)
Leases [Abstract]
2025	$ 11,801
2026	9,653
2027	8,880
2028	7,707
2029	4,478
Thereafter	9,234
Total Lease Payments	51,753
Less: Interest	(7,619)
Total Lease Liability	$ 44,134

Asset Retirement Obligation - N

Asset Retirement Obligation - Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Jun. 30, 2022	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Asset Retirement Obligation [Line Items]
Liabilities Settled		$ 25,556	$ 14,448	$ 71,171
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, 2024	Sep. 30, 2023	Sep. 30, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at Beginning of Year	$ 165,492	$ 161,545	$ 209,639
Liabilities Incurred	2,367	3,313	2,401
Revisions of Estimates	51,967	6,728	10,700
Liabilities Settled	(25,556)	(14,448)	(71,171)
Accretion Expense	8,736	8,354	9,976
Balance at End of Year	$ 203,006	$ 165,492	$ 161,545

Regulatory Matters - Schedule o

Regulatory Matters - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		Sep. 30, 2024	Sep. 30, 2023
Regulatory Assets:
Total Regulatory Assets		$ 231,974	$ 184,796
Less: Amounts Included in Other Current Assets		(38,264)	(36,373)
Regulatory Liabilities:
Total Regulatory Liabilities		821,646	808,821
Less: Amounts included in Current and Accrued Liabilities		(72,072)	(97,124)
Total Long-Term Regulatory Liabilities		749,574	711,697
Cost of Removal Regulatory Liability
Regulatory Liabilities:
Total Regulatory Liabilities		292,477	277,694
Taxes Refundable to Customers
Regulatory Liabilities:
Total Regulatory Liabilities		305,645	268,562
Post-Retirement Benefit Costs
Regulatory Liabilities:
Total Regulatory Liabilities	[1]	141,199	159,760
Less: Amounts included in Current and Accrued Liabilities		(5,800)	(5,800)
Total Long-Term Regulatory Liabilities		135,399	153,960
Amounts Payable to Customers
Regulatory Liabilities:
Total Regulatory Liabilities		42,720	59,019
Environmental Site Remediation Costs
Regulatory Liabilities:
Total Regulatory Liabilities	[2]	5,390	619
Other
Regulatory Liabilities:
Total Regulatory Liabilities	[3]	34,215	43,167
Total Long-Term Regulatory Liabilities		10,663	10,862
Other Accruals and Current Liabilities
Regulatory Liabilities:
Less: Amounts included in Current and Accrued Liabilities		(23,552)	(32,305)
Pension Costs
Regulatory Assets:
Total Regulatory Assets	[4]	30,259	20,459
Post-Retirement Benefit Costs
Regulatory Assets:
Total Regulatory Assets	[4]	7,932	2,536
Recoverable Future Taxes
Regulatory Assets:
Total Regulatory Assets		80,084	69,045
System Modernization And Improvement Tracker
Regulatory Assets:
Total Regulatory Assets	[5]	47,043	30,375
Less: Amounts Included in Other Current Assets		(15,681)	(19,584)
Total Long-Term Regulatory Assets		31,362	10,791
Asset Retirement Obligations
Regulatory Assets:
Total Regulatory Assets	[4]	21,951	19,384
Unamortized Debt Expense
Regulatory Assets:
Total Regulatory Assets		5,604	7,240
Other
Regulatory Assets:
Total Regulatory Assets	[6]	39,101	35,757
Total Long-Term Regulatory Assets		16,518	18,968
Long-Term Regulatory Assets
Regulatory Assets:
Total Long-Term Regulatory Assets		193,710	148,423
Other Current Assets
Regulatory Assets:
Less: Amounts Included in Other Current Assets		$ (22,583)	$ (16,789)
[1] $5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2024 and 2023, since such amounts are expected to be passed back to ratepayers in the next 12 months. $135,399 and $153,960 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. $23,552 and $32,305 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,663 and $10,862 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. Included in Other Regulatory Assets on the Consolidated Balance Sheets. $15,681 and $19,584 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $31,362 and $10,791 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively. $22,583 and $16,789 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $16,518 and $18,968 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2024 and 2023, respectively.

Regulatory Matters - Narrative

Regulatory Matters - Narrative (Details) - USD ($) $ in Millions				12 Months Ended	36 Months Ended	89 Months Ended
	Oct. 31, 2023	Aug. 01, 2023	Oct. 28, 2022	Sep. 30, 2025	Sep. 30, 2027	Sep. 30, 2024	Aug. 01, 2024
New York
Regulatory Matters [Line Items]
Approved return on equity (as a percent)						8.70%
Proposed base rate increase	$ 88
New York | Forecast
Regulatory Matters [Line Items]
Proposed rate plan period					3 years
Proposed increase in annual revenue requirement over three years					$ 86
Proposed increase in annual revenue requirement in first year				$ 57
Proposed return on equity					9.70%
Proposed common equity ratio for rate setting (as a percent)					0.48
Pennsylvania
Regulatory Matters [Line Items]
Proposed base rate increase			$ 28.1
Public utilities authorized rate increase, amount		$ 23
Public utilities, distribution system improvement charge, plant						$ 785.2
Pennsylvania | Minimum
Regulatory Matters [Line Items]
Proposed public utilities distribution system improvement charge plant minimum							$ 781.3

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, 2024	Sep. 30, 2023	Sep. 30, 2022
Current Income Taxes —
Federal	$ 6,453	$ 11,744	$ 0
State	5,899	1,386	12,214
Deferred Income Taxes —
Federal	894	106,801	137,025
State	(3,504)	44,602	(32,610)
Total Income Taxes	$ 9,742	$ 164,533	$ 116,629

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, 2022	Oct. 01, 2024	Sep. 30, 2023
Income Taxes [Line Items]
Taxes refundable to customers					$ 305,645,000			$ 268,562,000
Recoverable future taxes					80,084,000			69,045,000
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					305,600,000			268,600,000
Recoverable future taxes					$ 80,100,000			$ 69,000,000
Pennsylvania
Income Taxes [Line Items]
Corporate income tax rate					8.99%
Increase (decrease) 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%
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, 2024	Sep. 30, 2023	Sep. 30, 2022
Income Tax Disclosure [Abstract]
U.S. Income Before Income Taxes		$ 87,255	$ 641,399	$ 682,650
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21%		18,324	134,694	143,357
State Valuation Allowance	[1]	0	0	(24,850)
State Income Taxes	[2]	1,892	36,331	8,736
Amortization of Excess Deferred Federal Income Taxes		(5,607)	(6,053)	(5,184)
Plant Flow Through Items		(6,135)	(2,856)	(814)
Stock Compensation		1,758	957	820
Federal Tax Credits		(5)	(6)	(5,701)
Miscellaneous		(485)	1,466	265
Total Income Taxes		$ 9,742	$ 164,533	$ 116,629
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. 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, 2024	Sep. 30, 2023
Deferred Tax Liabilities:
Unrealized Hedging Gains	$ 22,433	$ 3,385
Property, Plant and Equipment	1,134,727	1,178,893
Pension and Other Post-Retirement Benefit Costs	59,877	44,358
Other	13,885	21,470
Total Deferred Tax Liabilities	1,230,922	1,248,106
Deferred Tax Assets:
Tax Loss and Credit Carryforwards	(31,111)	(33,744)
Pension and Other Post-Retirement Benefit Costs	(49,622)	(41,843)
Other	(39,024)	(48,349)
Total Deferred Tax Assets	(119,757)	(123,936)
Total Net Deferred Income Taxes	$ 1,111,165	$ 1,124,170

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, 2024	Sep. 30, 2023	Sep. 30, 2022
Valuation Allowance [Roll Forward]
Balance at Beginning of Year	$ 0	$ 0	$ 57,645
Additions	0	0	0
Deductions	0	0	57,645
Balance at End of Year	$ 0	$ 0	$ 0

Income Taxes Income Taxes - Sum

Income Taxes Income Taxes - Summary of Operating Loss and Tax Credit Carryforwards (Details) $ in Thousands	Sep. 30, 2024 USD ($)
Pennsylvania
Operating Loss Carryforwards [Line Items]
Net Operating Loss	$ 438,058

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, 2024		Sep. 30, 2023	Sep. 30, 2022
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance (in shares)		91,819,405
Beginning balance		$ 2,963,376
Net Income Available for Common Stock		77,513		$ 476,866	$ 566,021
Dividends Declared on Common Stock		(185,220)		(178,095)	(170,111)
Other Comprehensive Income (Loss), Net of Tax		$ 39,584		$ 570,673	$ (112,136)
Ending balance (in shares)		91,005,993		91,819,405
Ending balance		$ 2,848,343		$ 2,963,376
Dividend per share (in dollars per share)		$ 2.02		$ 1.94	$ 1.86
Accumulated earnings free from limitations		$ 1,600,000
Stock And Benefit Plans
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share repurchases (in shares)		(78,141)
Share Repurchase Plan
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share repurchases (in shares)		(1,146,259)
Share Repurchases		$ (65,200)
Common Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance (in shares)		91,819,000		91,478,000	91,182,000
Beginning balance		$ 91,819		$ 91,478	$ 91,182
Common stock issued under stock and benefit plans (in shares)		333,000		341,000	296,000
Common stock issued under stock and benefit plans		$ 333		$ 341	$ 296
Ending balance (in shares)		91,006,000		91,819,000	91,478,000
Ending balance		$ 91,006		$ 91,819	$ 91,478
Common Stock | Share Repurchase Plan
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share repurchases (in shares)		(1,146,000)
Share Repurchases		$ (1,146)
Paid In Capital
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance		1,040,761		1,027,066	1,017,446
Share-Based Payment Expense	[1]	19,868		18,746	17,699
Ending balance		1,045,487		1,040,761	1,027,066
Paid In Capital | Stock And Benefit Plans
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share Repurchases		(1,955)		(5,051)	(8,079)
Paid In Capital | Share Repurchase Plan
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share Repurchases		(13,187)
Earnings Reinvested in the Business
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance		1,885,856		1,587,085	1,191,175
Net Income Available for Common Stock		77,513		476,866	566,021
Dividends Declared on Common Stock		(185,220)		(178,095)	(170,111)
Share Repurchases		(50,823)		0	0
Ending balance		1,727,326	[2]	1,885,856	1,587,085
Earnings Reinvested in the Business | Share Repurchase Plan
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share Repurchases		(50,823)
Accumulated Other Comprehensive Income (Loss)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance		(55,060)		(625,733)	(513,597)
Other Comprehensive Income (Loss), Net of Tax		39,584		570,673	(112,136)
Ending balance		$ (15,476)		$ (55,060)	$ (625,733)
[1] Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available for Common Stock, net of tax benefits. 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, 2024, $1.6 billion of accumulated earnings was free of such limitations.

Capitalization and Short-Term_4

Capitalization and Short-Term Borrowings - Narrative (Details)		12 Months Ended
	May 18, 2023 USD ($)	Sep. 30, 2024 USD ($) $ / shares shares	Sep. 30, 2023 USD ($) $ / shares shares	Sep. 30, 2022 USD ($) $ / shares shares	May 31, 2024 USD ($) bank	Apr. 01, 2024 USD ($)	Mar. 08, 2024 USD ($)	Feb. 29, 2024 bank	Feb. 14, 2024 USD ($) lender	Feb. 28, 2022 USD ($) bank
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
Stock repurchase program, authorized amount							$ 200,000,000
Stock-based compensation expense		$ 19,800,000	$ 18,600,000	$ 17,600,000
Tax benefit related to stock-based compensation expense		2,500,000	2,400,000	2,500,000
Capitalized stock-based compensation costs		100,000	100,000	100,000
Tax benefit related to stock-based compensation exercises and vestings		$ 300,000
Number of shares available for future grant (in shares) | shares		3,889,027
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		$ 299,359,000	297,306,000	0
Repayments of short-term borrowings		0	250,000,000	$ 0
Principal amounts of long-term debt maturing in 2025		500,000,000
Principal amounts of long-term debt maturing in 2026		800,000,000
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 in 2029		0
Principal amounts of long-term debt maturing after 2029		500,000,000
Commercial paper, outstanding		90,700,000	287,500,000
Short-term notes payable outstanding to banks		$ 0	0
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		717,900,000
Committed credit facility debt to capitalization ratio ceiling test impairment adjustment		358,900,000
Debt to capitalization ratio maximum excluded unrealized gains or losses on other derivative financial instruments in AOCI		$ 10,000,000
Debt to capitalization ratio		0.47
Permitted additional short-term and/or long-term debt to be outstanding under the Credit Agreement		$ 3,070,000,000
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%
Stock And Benefit Plans
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Shares repurchased (in shares) | shares		78,141
Share Repurchase Plan
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Shares repurchased (in shares) | shares		1,146,259
Share repurchase program, average price per share (in USD per share) | $ / shares		$ 56.32
Share Repurchases		$ 65,200,000
364-Day Credit Agreement
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Repayments of short-term borrowings			$ 250,000,000
Credit Agreement
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Maximum borrowing capacity					$ 1,000,000,000					$ 1,000,000,000
Number of banks in syndicate | bank					3			11		12
Term Loan Agreement
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Long-term debt, face amount						$ 300,000,000
Net proceeds from issuance of long-term debt		$ 299,400,000
Rate adjustment to SOFR		0.0010
Spread on variable rate		1.375%
Debt instruments, number of lenders | lender									6
Maximum borrowing capacity									$ 300,000,000
Commercial Paper
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Amount available to be issued under commercial paper program		$ 500,000,000
Weighted average interest rate		5.30%	6.13%
5.50% Notes Due October 1, 2026
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Long-term debt, face amount	$ 300,000,000	$ 300,000,000
Net proceeds from issuance of long-term debt	$ 297,300,000
Long-term debt, interest rate	5.50%	5.50%
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
Interest payments Remaining		$ 3,200,000
Board Of Directors
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Common stock issued (in shares) | shares		36,078
Officer DCP Plan
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Common stock issued (in shares) | shares		8,318
Restricted Stock Units (RSUs)
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Common stock issued (in shares) | shares		115,337
Performance Shares
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Common stock issued (in shares) | shares		251,255
Number of shares granted (in shares) | shares		361,729	202,259	195,397
Weighted average fair value of award (in dollars per share) | $ / shares		$ 44.23	$ 64.28	$ 65.39
Unrecognized compensation expense		$ 15,700,000
Unrecognized compensation expense recognized weighted average period		2 years 4 months 24 days
Performance Shares | 2025
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		177,118
Performance Shares | 2026
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		188,767
Performance Shares | 2027
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		297,392
Performance Shares | 2028
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		0
Performance Shares | 2029
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		0
Performance Shares | Thereafter
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		56,300
Non-Performance Based Restricted Stock Units (RSUs)
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Number of shares granted (in shares) | shares		220,778	133,173	128,950
Weighted average fair value of award (in dollars per share) | $ / shares		$ 42.44	$ 58.10	$ 54.10
Unrecognized compensation expense		$ 9,200,000
Unrecognized compensation expense recognized weighted average period		3 years
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		129,688
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		111,557
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		86,667
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		34,757
Non-Performance Based Restricted Stock Units (RSUs) | 2029
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		19,228
Non-Performance Based Restricted Stock Units (RSUs) | Thereafter
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Non-vested stock-based compensation lapse (in shares) | shares		56,296
ROC Performance Shares | Three Year Performance Cycle
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Performance shares calculation period		3 years	3 years	3 years
ROC Performance Shares | Five Year Performance Cycle
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Performance shares calculation period		5 years	5 years	5 years
ESG Performance Shares | Three Year Performance Cycle
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Performance shares calculation period		3 years	3 years	3 years
TSR Performance Shares | Three Year Performance Cycle
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Performance shares calculation period		3 years	3 years	3 years
TSR Performance Shares | Five Year Performance Cycle
Schedule of Capitalization, Long-Term Debt and Equity [Line Items]
Performance shares calculation period		5 years	5 years	5 years

Capitalization and Short-Term_5

Capitalization and Short-Term Borrowings - Schedule of Share-Based Compensation for Restricted Stock Units and Performance Shares (Details) - $ / shares	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Non-Performance Based Restricted Stock Units (RSUs)
Number of Restricted Stock Units
Outstanding, beginning of year (in shares)	342,186
Granted (in shares)	220,778	133,173	128,950
Vested (in shares)	(115,337)
Forfeited (in shares)	(9,434)
Outstanding, end of year (in shares)	438,193	342,186
Weighted Average Fair Value per Award
Outstanding, beginning of year (in dollars per share)	$ 49.63
Granted (in dollars per share)	42.44	$ 58.10	$ 54.10
Vested (in dollars per share)	46.92
Forfeited (in dollars per share)	50.43
Outstanding, end of year (in dollars per share)	$ 46.70	$ 49.63
Performance Shares
Number of Restricted Stock Units
Outstanding, beginning of year (in shares)	586,791
Granted (in shares)	361,729	202,259	195,397
Vested (in shares)	(251,255)
Forfeited (in shares)	(35,357)
Change in Units Based on Performance Achieved (in shares)	57,669
Outstanding, end of year (in shares)	719,577	586,791
Weighted Average Fair Value per Award
Outstanding, beginning of year (in dollars per share)	$ 55.46
Granted (in dollars per share)	44.23	$ 64.28	$ 65.39
Vested (in dollars per share)	38.62
Forfeited (in dollars per share)	46.49
Change in Units Based on Performance Achieved (in dollars per share)	37.36
Outstanding, end of year (in dollars per share)	$ 54.69	$ 55.46

Capitalization and Short-Term_6

Capitalization and Short-Term Borrowings - Weighted Average Assumptions Used in Estimating Fair Value (Details) - Performance Shares	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-Free Interest Rate	4.36%	4.03%	0.85%
Remaining Term at Date of Grant (Years)	2 years 11 months 23 days	2 years 9 months 18 days	2 years 9 months 18 days
Expected Volatility	23.90%	31.60%	29.70%

Capitalization and Short-Term_7

Capitalization and Short-Term Borrowings - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023	May 18, 2023
Debt Instrument [Line Items]
Total Long-Term Debt		$ 2,700,000	$ 2,400,000
Less Unamortized Discount and Debt Issuance Costs		11,757	15,515
Less Current Portion	[1]	500,000	0
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,188,243	2,384,485
7.38% due June 2025
Debt Instrument [Line Items]
Medium-Term Notes	[2]	50,000	$ 50,000
Less Current Portion		$ 50,000
Long-term debt, interest rate		7.38%	7.38%
2.95% to 5.50% due July 2025 to March 2031
Debt Instrument [Line Items]
Notes	[2],[3],[4]	$ 2,350,000	$ 2,350,000
Percentage of principal amount		101%	101%
Variable Rate due February 2026
Debt Instrument [Line Items]
Long-term debt, face amount	[5]	$ 300,000	$ 0
Long-term debt, weighted average variable interest rate		6.71%
4.62% through December 2024
Debt Instrument [Line Items]
Long-term debt, face amount		$ 200,000
Long-term debt, variable interest rate		4.62%
4.58% until January 2025
Debt Instrument [Line Items]
Long-term debt, face amount		$ 100,000
Long-term debt, variable interest rate		4.58%
4.75% Notes Due September 1, 2028
Debt Instrument [Line Items]
Long-term debt, face amount		$ 300,000
Long-term debt, interest rate		4.75%
Maximum interest rate adjustment		2%
3.95% Notes Due September 15, 2027
Debt Instrument [Line Items]
Long-term debt, face amount		$ 300,000
Long-term debt, interest rate		3.95%
Maximum interest rate adjustment		2%
2.95% Notes Due March 1, 2031
Debt Instrument [Line Items]
Long-term debt, face amount		$ 500,000
Long-term debt, interest rate		2.95%
Maximum interest rate adjustment		2%
5.50% Notes Due January 15, 2026
Debt Instrument [Line Items]
Long-term debt, face amount		$ 500,000
Long-term debt, interest rate		5.50%
Maximum interest rate adjustment		2%
5.50% Notes Due October 1, 2026
Debt Instrument [Line Items]
Long-term debt, face amount		$ 300,000		$ 300,000
Long-term debt, interest rate		5.50%		5.50%
Maximum interest rate adjustment		2%
5.20% Notes Due July 2025
Debt Instrument [Line Items]
Less Current Portion		$ 450,000
Long-term debt, interest rate		5.20%
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] Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% medium-term notes and $450.0 million of 5.20% notes. None of the Company’s long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. The Medium-Term Notes and Notes are unsecured. 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. The interest rate on the delayed draw term loan is a weighted average SOFR interest rate of 6.71% that was locked in from April 2024 until the beginning of October 2024. The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100.0 million until January 2025.

Fair Value Measurements - Recur

Fair Value Measurements - Recurring Fair Value Measures of Assets and Liabilities (Details) - USD ($) $ in Thousands		Sep. 30, 2024	Sep. 30, 2023
Assets:
Cash Equivalents — Money Market Mutual Funds	[1]	$ 29,238	$ 39,332
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]	$ 154,040	$ 121,553
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]	$ 4,735	$ 31,009
Total Net Assets/(Liabilities)	[1]	149,305	90,544
Over the Counter Swaps — Gas
Derivative Financial Instruments:
Derivative Asset	[1]	58,811	28,292
Derivative Financial Instruments:
Derivative Liability	[1]	5,008	30,803
Over the Counter No Cost Collars — Gas
Derivative Financial Instruments:
Derivative Asset	[1]	28,810	16,221
Derivative Financial Instruments:
Derivative Liability	[1]	(273)	205
Contingent Consideration for Asset Sale
Derivative Financial Instruments:
Derivative Asset	[1]	729	7,277
Foreign Currency Contracts
Derivative Financial Instruments:
Derivative Asset	[1]	(445)	(1,303)
Derivative Financial Instruments:
Derivative Liability	[1]	0	1
Balanced Equity Mutual Fund
Derivative Financial Instruments:
Other Investments	[1]	19,523	15,837
Fixed Income Mutual Fund
Derivative Financial Instruments:
Other Investments	[1]	17,374	15,897
Level 1
Assets:
Cash Equivalents — Money Market Mutual Funds		29,238	39,332
Derivative Financial Instruments:
Total Assets		66,135	71,066
Derivative Financial Instruments:
Total Liabilities		0	0
Total Net Assets/(Liabilities)		66,135	71,066
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	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		19,523	15,837
Level 1 | Fixed Income Mutual Fund
Derivative Financial Instruments:
Other Investments		17,374	15,897
Level 2
Assets:
Cash Equivalents — Money Market Mutual Funds		0	0
Derivative Financial Instruments:
Total Assets		109,603	104,193
Derivative Financial Instruments:
Total Liabilities		26,433	84,715
Total Net Assets/(Liabilities)		83,170	19,478
Level 2 | Over the Counter Swaps — Gas
Derivative Financial Instruments:
Derivative Asset		76,009	65,800
Derivative Financial Instruments:
Derivative Liability		22,206	68,311
Level 2 | Over the Counter No Cost Collars — Gas
Derivative Financial Instruments:
Derivative Asset		32,584	30,966
Derivative Financial Instruments:
Derivative Liability		3,501	14,950
Level 2 | Contingent Consideration for Asset Sale
Derivative Financial Instruments:
Derivative Asset		729	7,277
Level 2 | Foreign Currency Contracts
Derivative Financial Instruments:
Derivative Asset		281	150
Derivative Financial Instruments:
Derivative Liability		726	1,454
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
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	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
Derivative Financial Instruments:
Total Assets	[1]	(21,698)	(53,706)
Derivative Financial Instruments:
Total Liabilities	[1]	(21,698)	(53,706)
Total Net Assets/(Liabilities)	[1]	0	0
Netting Adjustments | Over the Counter Swaps — Gas
Derivative Financial Instruments:
Derivative Asset	[1]	(17,198)	(37,508)
Derivative Financial Instruments:
Derivative Liability	[1]	(17,198)	(37,508)
Netting Adjustments | Over the Counter No Cost Collars — Gas
Derivative Financial Instruments:
Derivative Asset	[1]	(3,774)	(14,745)
Derivative Financial Instruments:
Derivative Liability	[1]	(3,774)	(14,745)
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]	(726)	(1,453)
Derivative Financial Instruments:
Derivative Liability	[1]	(726)	(1,453)
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 - Nonre

Fair Value Measurements - Nonrecurring Fair Value Measures Within Level 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	$ 519,129	$ 0	$ 0
Fair Value, Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	55,437	0	0
Pipeline and Storage | Fair Value, Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	46,075	0	0
Fair Value	12,133
Exploration and Production
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	473,054
Exploration and Production | Fair Value, Nonrecurring | Level 3
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	9,362	$ 0	$ 0
Property, plant, and equipment, fair value	$ 3,000

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	$ 519,129	$ 0	$ 0
Northern Access Project
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Impairment of Assets	$ 46,100

Financial Instruments - Long-Te

Financial Instruments - Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Financial Instruments, Owned, at Fair Value, by Type, Alternative [Abstract]
Carrying Amount	$ 2,688,243	$ 2,384,485
Fair Value	$ 2,656,888	$ 2,210,478

Financial Instruments - Other I

Financial Instruments - Other Investments (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Summary of Investment Holdings [Line Items]
Life Insurance Contracts	$ 44,808	$ 42,242
Total other investments	81,705	73,976
Equity Mutual Fund
Summary of Investment Holdings [Line Items]
Mutual Funds	19,523	15,837
Fixed Income Mutual Fund
Summary of Investment Holdings [Line Items]
Mutual Funds	$ 17,374	$ 15,897

Financial Instruments - Narrati

Financial Instruments - Narrative (Details) Bcf in Billions	12 Months Ended		36 Months Ended
	Sep. 30, 2024 USD ($) counterparty Bcf	Dec. 31, 2023 USD ($)	Dec. 31, 2025 USD ($) payment	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Jun. 30, 2022 USD ($)	Sep. 30, 2021 USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Foreign currency forward contracts duration maximum	6 years
After tax net hedging gains in accumulated other comprehensive income (loss)	$ 55,800,000
After tax net hedging gains reclassified within twelve months	33,300,000
Fair market value of derivative liability with a credit-risk related contingency	0
Hedging collateral deposits	0			$ 0	$ 91,670,000		$ 88,610,000
Foreign Currency Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Hedging notional amount of forecasted transportation costs	$ 51,200,000
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	17
Credit risk exposure per counterparty	$ 5,100,000
Maximum credit risk exposure per counterparty	18,900,000
Collateral received by company	$ 0
Number of counterparties with a common credit-risk related contingency | counterparty	16
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	$ 700,000			$ 7,300,000		$ 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	$ (6,600,000)
California Asset Sale | Minimum
Derivative Instruments, Gain (Loss) [Line Items]
ICE Brent Average (in dollars per barrel)		$ 95
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	349.4

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, 2024	Sep. 30, 2023	Sep. 30, 2022
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)	$ 286,894	$ 708,206	$ (1,050,831)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	216,655	(88,656)	$ (882,581)
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)	286,392	708,234
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	217,012	(88,015)
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)	502	(28)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	$ (357)	$ (641)

Retirement Plan and Other Pos_3

Retirement Plan and Other Post-Retirement Benefits - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Benefit Cost (Income)	$ 9,500	$ 8,300	$ 8,900
Accumulated Benefit Obligation	57,500	58,500	64,900
Projected benefit obligation	$ 66,000	$ 69,500	$ 77,200
Discount rate (as a percent)	4.71%	5.91%	5.49%
Rate of compensation increase (as a percent)	8%	8%	8%
Pre-tax decrease to accumulated other comprehensive income	$ 55,235	$ 788,876	$ (154,986)
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	$ 14,100	$ 13,100	$ 17,500
Other Liabilities
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	51,900	56,400	59,700
Retirement Savings Account
Defined Benefit Plan Disclosure [Line Items]
Costs recognized	6,500	5,700	5,300
Tax-Deferred Savings Plans
Defined Benefit Plan Disclosure [Line Items]
Costs recognized	9,000	8,200	7,800
Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Benefit Cost (Income)	(5,334)	(4,622)	23,087
Accumulated Benefit Obligation	804,916	751,912	793,555
Projected benefit obligation	$ 822,306	$ 768,750	$ 813,828	$ 1,098,456
Discount rate (as a percent)	4.97%	5.99%	5.57%
Rate of compensation increase (as a percent)	4.60%	4.60%	4.60%
Annual contribution expected for next fiscal year	$ 0
Expected future benefit payments in 2025	67,700
Expected future benefit payments in 2026	67,200
Expected future benefit payments in 2027	66,600
Expected future benefit payments in 2028	65,800
Expected future benefit payments 2029	65,000
Expected future benefit payments 2030 through 2034	305,100
Employer contributions	$ 0	$ 0	$ 20,400
Expected long term rate of return on plan assets (as a percent)	7.40%	6.90%	5.20%
Retirement Plan | Scenario, Plan
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets (as a percent)	6.60%
Retirement Plan | Other Actuarial Experience
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ 2,500
Retirement Plan | Discount Rate Change
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	69,600	$ (28,400)	$ (262,200)
Non-Qualified Benefit Plans, Other Post-Retirement Benefit Plan and Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Increase to other regulatory assets	36,000
Pre-tax decrease to accumulated other comprehensive income	15,000
Other Post-Retirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net Periodic Benefit Cost (Income)	(4,583)	(3,404)	(5,664)
Projected benefit obligation	$ 321,025	$ 274,278	$ 299,283	$ 431,213
Discount rate (as a percent)	4.98%	5.99%	5.56%
Rate of compensation increase (as a percent)	4.60%	4.60%	4.60%
Expected future benefit payments in 2025	$ 25,736
Expected future benefit payments in 2026	26,193
Expected future benefit payments in 2027	26,534
Expected future benefit payments in 2028	26,775
Expected future benefit payments 2029	26,804
Expected future benefit payments 2030 through 2034	128,836
Employer contributions	$ 479	$ 235	$ 3,082
Expected long term rate of return on plan assets (as a percent)	6%	5.70%	5.20%
Other Post-Retirement Benefits | Scenario, Plan
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets (as a percent)	5.40%
Other Post-Retirement Benefits | Other Actuarial Experience
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ 1,200	$ (12,900)	$ (22,500)
Other Post-Retirement Benefits | Discount Rate Change
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	28,100	(10,700)	(98,900)
Other Post-Retirement Benefits | Mortality Improvement Projection Scale
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation		(400)	$ 1,100
Other Post-Retirement Benefits | Health Care Cost Trend Rates
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	25,200	$ 3,200
Other Than VEBA Trust And 401(h) Accounts
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	500
VEBA Trust
Defined Benefit Plan Disclosure [Line Items]
Annual contribution expected for next fiscal year	0
Employer contributions	$ 0

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, 2024	Sep. 30, 2023	Sep. 30, 2022
Change in Benefit Obligation
Benefit Obligation at Beginning of Period		$ 69,500	$ 77,200
Benefit Obligation at End of Period		66,000	69,500	$ 77,200
Amounts Recognized in the Balance Sheets Consist of:
Non-Current Assets		180,230	200,301
Accumulated Benefit Obligation		$ 57,500	$ 58,500	$ 64,900
Weighted Average Assumptions Used to Determine Benefit Obligation
Discount rate (as a percent)		4.71%	5.91%	5.49%
Rate of compensation increase (as a percent)		8%	8%	8%
Components of Net Periodic Benefit Cost
Net Periodic Benefit Cost (Income)		$ 9,500	$ 8,300	$ 8,900
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		$ 768,750	$ 813,828	$ 1,098,456
Service Cost		4,197	5,187	8,758
Interest Cost		43,558	42,516	22,827
Plan Participants’ Contributions		0	0	0
Retiree Drug Subsidy Receipts		0	0	0
Actuarial (Gain) Loss		72,016	(27,313)	(251,173)
Benefits Paid		(66,215)	(65,468)	(65,040)
Benefit Obligation at End of Period		822,306	768,750	813,828
Change in Plan Assets
Fair Value of Assets at Beginning of Period		784,712	845,205	1,095,729
Actual Return on Plan Assets		105,488	4,975	(205,884)
Employer Contributions		0	0	20,400
Plan Participants’ Contributions		0	0	0
Benefits Paid		(66,215)	(65,468)	(65,040)
Fair Value of Assets at End of Period		823,985	784,712	845,205
Net Amount Recognized at End of Period (Funded Status)		1,679	15,962	31,377
Amounts Recognized in the Balance Sheets Consist of:
Non-Current Liabilities		0	0	0
Non-Current Assets		1,679	15,962	31,377
Net Amount Recognized at End of Period		1,679	15,962	31,377
Accumulated Benefit Obligation		$ 804,916	$ 751,912	$ 793,555
Weighted Average Assumptions Used to Determine Benefit Obligation
Discount rate (as a percent)		4.97%	5.99%	5.57%
Rate of compensation increase (as a percent)		4.60%	4.60%	4.60%
Components of Net Periodic Benefit Cost
Service Cost		$ 4,197	$ 5,187	$ 8,758
Interest Cost		43,558	42,516	22,827
Expected Return on Plan Assets		(68,343)	(66,593)	(52,294)
Amortization of Prior Service Cost (Credit)		362	436	537
Recognition of Actuarial (Gain) Loss	[1]	(1,339)	(7,680)	26,405
Net Amortization and Deferral for Regulatory Purposes		16,231	21,512	16,854
Net Periodic Benefit Cost (Income)		$ (5,334)	$ (4,622)	$ 23,087
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Effective Discount Rate for Benefit Obligations (as a percent)		5.99%	5.57%	2.75%
Effective Rate for Interest on Benefit Obligations (as a percent)		5.93%	5.45%	2.14%
Effective Discount Rate for Service Cost (as a percent)		6.01%	5.49%	2.95%
Effective Rate for Interest on Service Cost (as a percent)		5.98%	5.53%	2.70%
Expected Return on Plan Assets (as a percent)		7.40%	6.90%	5.20%
Rate of Compensation Increase (as a percent)		4.60%	4.60%	4.70%
Other Post-Retirement Benefits
Change in Benefit Obligation
Benefit Obligation at Beginning of Period		$ 274,278	$ 299,283	$ 431,213
Service Cost		434	587	1,328
Interest Cost		15,561	15,648	9,066
Plan Participants’ Contributions		3,401	3,297	3,271
Retiree Drug Subsidy Receipts		1,208	2,969	312
Actuarial (Gain) Loss		54,443	(20,789)	(120,276)
Benefits Paid		(28,300)	(26,717)	(25,631)
Benefit Obligation at End of Period		321,025	274,278	299,283
Change in Plan Assets
Fair Value of Assets at Beginning of Period		455,702	461,438	575,565
Actual Return on Plan Assets		64,783	17,449	(94,849)
Employer Contributions		479	235	3,082
Plan Participants’ Contributions		3,401	3,297	3,271
Benefits Paid		(28,300)	(26,717)	(25,631)
Fair Value of Assets at End of Period		496,065	455,702	461,438
Net Amount Recognized at End of Period (Funded Status)		175,040	181,424	162,155
Amounts Recognized in the Balance Sheets Consist of:
Non-Current Liabilities		(3,511)	(2,915)	(3,065)
Non-Current Assets		178,551	184,339	165,220
Net Amount Recognized at End of Period		$ 175,040	$ 181,424	$ 162,155
Weighted Average Assumptions Used to Determine Benefit Obligation
Discount rate (as a percent)		4.98%	5.99%	5.56%
Rate of compensation increase (as a percent)		4.60%	4.60%	4.60%
Components of Net Periodic Benefit Cost
Service Cost		$ 434	$ 587	$ 1,328
Interest Cost		15,561	15,648	9,066
Expected Return on Plan Assets		(26,642)	(25,612)	(29,359)
Amortization of Prior Service Cost (Credit)		(429)	(429)	(429)
Recognition of Actuarial (Gain) Loss	[1]	(2,266)	(8,755)	(7,610)
Net Amortization and Deferral for Regulatory Purposes		8,759	15,157	21,340
Net Periodic Benefit Cost (Income)		$ (4,583)	$ (3,404)	$ (5,664)
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
Effective Discount Rate for Benefit Obligations (as a percent)		5.99%	5.56%	2.76%
Effective Rate for Interest on Benefit Obligations (as a percent)		5.93%	5.45%	2.17%
Effective Discount Rate for Service Cost (as a percent)		5.99%	5.35%	3%
Effective Rate for Interest on Service Cost (as a percent)		6.01%	5.47%	2.93%
Expected Return on Plan Assets (as a percent)		6%	5.70%	5.20%
Rate of Compensation Increase (as a percent)		4.60%	4.60%	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, 2024 USD ($)	[1]
Non-Qualified Benefit Plans
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities
Net Actuarial Loss	$ (13,394)
Prior Service (Cost) Credit	0
Net Amount Recognized	(13,394)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities
Increase in Actuarial Loss, excluding amortization	(880)	[2]
Change due to Amortization of Actuarial (Gain) Loss	4,772
Prior Service (Cost) Credit	0
Net Change	3,892
Retirement Plan | Qualified Plan
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities
Net Actuarial Loss	(164,328)
Prior Service (Cost) Credit	(1,674)
Net Amount Recognized	(166,002)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities
Increase in Actuarial Loss, excluding amortization	(34,871)	[2]
Change due to Amortization of Actuarial (Gain) Loss	(1,339)
Prior Service (Cost) Credit	362
Net Change	(35,848)
Other Post-Retirement Benefits | Qualified Plan
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities
Net Actuarial Loss	(128)
Prior Service (Cost) Credit	686
Net Amount Recognized	558
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities
Increase in Actuarial Loss, excluding amortization	(16,302)	[2]
Change due to Amortization of Actuarial (Gain) Loss	(2,266)
Prior Service (Cost) Credit	(429)
Net Change	$ (18,997)
[1] Amounts presented are shown before recognizing deferred taxes. 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, 2024 USD ($)
Benefit Payments
2025	$ 25,736
2026	26,193
2027	26,534
2028	26,775
2029	26,804
2030 through 2034	128,836
Subsidy Receipts
2025	(1,696)
2026	(1,745)
2027	(1,782)
2028	(1,806)
2029	(1,829)
2030 through 2034	$ (9,197)

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, 2024		Sep. 30, 2023		Sep. 30, 2022
Retirement Benefits [Abstract]
Rate of Medical Cost Increase for Pre Age 65 Participants	6.25%	[1]	6.25%	[2]	5.30%	[3]
Rate of Medical Cost Increase for Post Age 65 Participants	5.75%	[1]	5%	[2]	4.84%	[3]
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	10.25%	[1]	6.85%	[2]	6.29%	[3]
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	5.75%	[1]	5%	[2]	4.84%	[3]
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	4%	[1]	6.60%	[2]	5.96%	[3]
Ultimate health care trend rate	4%		4%		4%
[1] It was assumed that this rate would gradually decline to 4% by 2049. It was assumed that this rate would gradually decline to 4% by 2048. 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, 2024		Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash		$ (9,985)		$ 3,075
Total plan assets		(823,985)		(784,712)	$ (845,205)	$ (1,095,729)
Retirement Plan | Total Retirement Plan Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		917,652		854,956
Retirement Plan | Domestic Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[1]	37,984		37,611
Retirement Plan | Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[2]	38,234		36,088
Retirement Plan | Domestic Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[3]	681,755	[4]	612,820
Retirement Plan | Domestic Fixed Income | Derivative
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		8,500
Retirement Plan | International Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[5]	8,587		7,778
Retirement Plan | Real Estate
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[6]	109,383		123,859
Retirement Plan | Cash Held in Collective Trust Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		41,709		36,800
Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments)
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		833,970		781,637
Retirement Plan | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		83,682		73,319
Other Post-Retirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash		1,243		10,795
Total plan assets		(496,065)		(455,702)	$ (461,438)	$ (575,565)
Other Post-Retirement Benefits | Cash Held in Collective Trust Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		14,274		9,637
Other Post-Retirement Benefits | Total Investments (including 401(h) Investments)
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		494,822		444,907
Other Post-Retirement Benefits | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		83,682		73,319
Other Post-Retirement Benefits | Total VEBA Trust Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		411,140		371,588
Other Post-Retirement Benefits | Collective Trust Funds — Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		82,814		72,285
Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		314,052		289,666
Level 1 | Retirement Plan | Total Retirement Plan Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		37,984		37,611
Level 1 | Retirement Plan | Domestic Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[1]	37,984		37,611
Level 1 | Retirement Plan | Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[2]	0		0
Level 1 | Retirement Plan | Domestic Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[3]	0	[4]	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		34,484		34,399
Level 1 | Retirement Plan | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		3,500		3,212
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 Investments (including 401(h) Investments)
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		317,552		292,878
Level 1 | Other Post-Retirement Benefits | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		3,500		3,212
Level 1 | Other Post-Retirement Benefits | Total VEBA Trust Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		314,052		289,666
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		314,052		289,666
Level 2 | Retirement Plan | Total Retirement Plan Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		642,187		564,282
Level 2 | Retirement Plan | Domestic Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[1]	0		0
Level 2 | Retirement Plan | Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[2]	0		0
Level 2 | Retirement Plan | Domestic Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[3]	633,600	[4]	556,504
Level 2 | Retirement Plan | International Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[5]	8,587		7,778
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		583,021		516,098
Level 2 | Retirement Plan | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		59,166		48,184
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 Investments (including 401(h) Investments)
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		59,166		48,184
Level 2 | Other Post-Retirement Benefits | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals		59,166		48,184
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 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 | Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[2]	0		0
Level 3 | Retirement Plan | Domestic Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[3]	0	[4]	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 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
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
Measured at NAV | Retirement Plan | Total Retirement Plan Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	237,481		253,063
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 | Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[2],[7]	38,234		36,088
Measured at NAV | Retirement Plan | Domestic Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[3],[7]	48,155	[4]	56,316
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]	109,383		123,859
Measured at NAV | Retirement Plan | Cash Held in Collective Trust Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	41,709		36,800
Measured at NAV | Retirement Plan | Total Retirement Plan Investments (excluding 401(h) Investments)
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	216,465		231,140
Measured at NAV | Retirement Plan | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	21,016		21,923
Measured at NAV | Other Post-Retirement Benefits | Cash Held in Collective Trust Funds
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	14,274		9,637
Measured at NAV | Other Post-Retirement Benefits | Total Investments (including 401(h) Investments)
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	118,104		103,845
Measured at NAV | Other Post-Retirement Benefits | 401(h) Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	21,016		21,923
Measured at NAV | Other Post-Retirement Benefits | Total VEBA Trust Investments
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	97,088		81,922
Measured at NAV | Other Post-Retirement Benefits | Collective Trust Funds — Global Equities
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	82,814		72,285
Measured at NAV | Other Post-Retirement Benefits | Exchange Traded Funds — Fixed Income
Defined Benefit Plan Disclosure [Line Items]
Plan assets, subtotals	[7]	$ 0		$ 0
[1] Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. Global Equities are comprised of collective trust funds. Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. International Fixed Income securities are comprised mostly of corporate/government bonds. Real Estate consists of investments held in a collective trust fund and a partnership. Reflects the authoritative guidance related to investments measured at net asset value (NAV).

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023
Recorded Unconditional Purchase Obligation [Line Items]
Estimate minimum liability for environmental remediation	$ 2,400
Other regulatory liabilities	749,574	$ 711,697
Future purchase obligation first year	215,600
Future purchase obligation second year	88,400
Future purchase obligation third year	93,200
Future purchase obligation fourth year	113,100
Future purchase obligation fifth year	116,400
Future purchase obligation thereafter	663,200
Environmental Site Remediation Costs
Recorded Unconditional Purchase Obligation [Line Items]
Other regulatory liabilities	5,400
Pipeline and Storage, Gathering and Utility Segments
Recorded Unconditional Purchase Obligation [Line Items]
Contract commitments first year	86,300
Contract commitments second year	8,700
Contract commitments third year	6,500
Contract commitments fourth year	3,800
Contract commitments fifth year	3,800
Contract commitments thereafter	3,900
Exploration and Production
Recorded Unconditional Purchase Obligation [Line Items]
Contract commitments first year	218,600
Contract commitments second year	73,600
Contract commitments third year	$ 13,900

Business Segment Information -

Business Segment Information - Narrative (Details)	12 Months Ended
	Sep. 30, 2024 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, 2024		Sep. 30, 2023		Sep. 30, 2022
Segment Reporting Information [Line Items]
Revenues From External Customers	[1]	$ 1,944,810	[2]	$ 2,173,771	[3]	$ 2,186,046
Intersegment Revenues		0		0		0
Interest Income		8,727		11,479		6,111
Interest Expense		138,695		131,886		130,357
Depreciation, Depletion and Amortization		457,026		409,573		369,790
Significant Non-Cash Item: Impairment of Assets		519,129		0		0
Income Tax Expense (Benefit)		9,742		164,533		116,629
Significant Item: Gain on Sale of Assets		0		0		12,736
Segment Profit: Net Income (Loss)		77,513		476,866		566,021
Expenditures for Additions to Long-Lived Assets		942,015		1,123,573		829,388
Segment Assets		8,319,770		8,280,260		7,896,262
Operating Revenues		1,944,810		2,173,771		2,186,046
Total Reportable Segments
Segment Reporting Information [Line Items]
Operating Revenues		2,315,058		2,510,323		2,500,572
All Other
Segment Reporting Information [Line Items]
Operating Revenues		0		0		6
Corporate
Segment Reporting Information [Line Items]
Revenues From External Customers	[1]	0	[2]	0	[3]	165
Corporate and Intersegment Eliminations
Segment Reporting Information [Line Items]
Intersegment Revenues		(370,248)		(336,552)		(314,697)
Interest Income		(8,703)		(5,662)		(1,024)
Interest Expense		(17,839)		(15,309)		(6,143)
Depreciation, Depletion and Amortization		473		429		183
Significant Non-Cash Item: Impairment of Assets		0
Income Tax Expense (Benefit)		145		(983)		(4,429)
Significant Item: Gain on Sale of Assets						0
Segment Profit: Net Income (Loss)		(1,588)		(3,498)		(12,650)
Expenditures for Additions to Long-Lived Assets		970		754		1,212
Segment Assets		(163,332)		(126,633)		(186,281)
Operating Revenues		(370,248)		(336,552)		(314,532)
Total Reportable Segments | Total Reportable Segments
Segment Reporting Information [Line Items]
Revenues From External Customers	[1]	1,944,810	[2]	2,173,771	[3]	2,185,881
Intersegment Revenues		370,248		336,552		314,691
Interest Income		17,430		17,141		7,132
Interest Expense		156,160		147,038		136,496
Depreciation, Depletion and Amortization		456,553		409,144		369,607
Significant Non-Cash Item: Impairment of Assets		519,129
Income Tax Expense (Benefit)		9,783		165,680		121,055
Significant Item: Gain on Sale of Assets						12,736
Segment Profit: Net Income (Loss)		79,718		480,895		578,680
Expenditures for Additions to Long-Lived Assets		941,045		1,122,819		828,176
Segment Assets		8,476,875		8,402,098		8,080,507
Exploration and Production
Segment Reporting Information [Line Items]
Significant Non-Cash Item: Impairment of Assets		473,054
Exploration and Production | Total Reportable Segments
Segment Reporting Information [Line Items]
Revenues From External Customers	[1]	961,078	[2]	958,455	[3]	1,010,464
Intersegment Revenues		0		0		0
Interest Income		2,729		3,259		1,929
Interest Expense		59,799		54,317		53,401
Depreciation, Depletion and Amortization		277,945		241,142		208,148
Income Tax Expense (Benefit)		(58,430)		87,796		43,898
Significant Item: Gain on Sale of Assets						12,736
Segment Profit: Net Income (Loss)		(163,954)		232,275		306,064
Expenditures for Additions to Long-Lived Assets		536,349		737,725		565,791
Segment Assets		2,644,820		2,814,218		2,507,541
Operating Revenues		961,078		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]	271,388	[2]	259,646	[3]	265,415
Intersegment Revenues		141,005		119,545		111,629
Interest Income		8,632		7,052		2,275
Interest Expense		47,428		43,499		42,492
Depreciation, Depletion and Amortization		74,530		70,827		67,701
Significant Non-Cash Item: Impairment of Assets		46,075
Income Tax Expense (Benefit)		26,045		34,489		35,043
Significant Item: Gain on Sale of Assets						0
Segment Profit: Net Income (Loss)		79,670		100,501		102,557
Expenditures for Additions to Long-Lived Assets		110,830		141,877		95,806
Segment Assets		2,446,243		2,427,214		2,394,697
Operating Revenues		412,393		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]	15,537	[2]	13,891	[3]	12,086
Intersegment Revenues		228,688		216,426		202,757
Interest Income		333		534		198
Interest Expense		14,206		14,989		16,488
Depreciation, Depletion and Amortization		38,817		35,725		33,998
Significant Non-Cash Item: Impairment of Assets		0
Income Tax Expense (Benefit)		38,217		36,128		24,949
Significant Item: Gain on Sale of Assets						0
Segment Profit: Net Income (Loss)		106,913		99,724		101,111
Expenditures for Additions to Long-Lived Assets		109,251		103,295		55,546
Segment Assets		987,103		912,923		878,796
Operating Revenues		244,225		230,317		214,843
Utility | Total Reportable Segments
Segment Reporting Information [Line Items]
Revenues From External Customers	[1]	696,807	[2]	941,779	[3]	897,916
Intersegment Revenues		555		581		305
Interest Income		5,736		6,296		2,730
Interest Expense		34,727		34,233		24,115
Depreciation, Depletion and Amortization		65,261		61,450		59,760
Significant Non-Cash Item: Impairment of Assets		0
Income Tax Expense (Benefit)		3,951		7,267		17,165
Significant Item: Gain on Sale of Assets						0
Segment Profit: Net Income (Loss)		57,089		48,395		68,948
Expenditures for Additions to Long-Lived Assets		184,615		139,922		111,033
Segment Assets		2,398,709		2,247,743		2,299,473
Operating Revenues		697,362		942,360		898,221
All Other | All Other
Segment Reporting Information [Line Items]
Revenues From External Customers	[1]	0	[2]	0	[3]	0
Intersegment Revenues		0		0		6
Interest Income		0		0		3
Interest Expense		374		157		4
Depreciation, Depletion and Amortization		0		0		0
Significant Non-Cash Item: Impairment of Assets		0
Income Tax Expense (Benefit)		(186)		(164)		3
Significant Item: Gain on Sale of Assets						0
Segment Profit: Net Income (Loss)		(617)		(531)		(9)
Expenditures for Additions to Long-Lived Assets		0		0		0
Segment Assets		$ 6,227		$ 4,795		$ 2,036
[1] All Revenue from External Customers originated in the United States. 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. 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, 2024	Sep. 30, 2023	Sep. 30, 2022
United States
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-lived assets	$ 7,963,851	$ 7,865,832	$ 7,135,131

Supplementary Information for_3

Supplementary Information for Exploration and Production Activities - Capitalized Costs Relating to Exploration and Production Activities (Details) - USD ($) $ in Thousands		Sep. 30, 2024	Sep. 30, 2023
Supplementary Information for Exploration and Production Activities Unaudited [Abstract]
Proved Properties	[1]	$ 7,079,903	$ 6,555,088
Unproved Properties		200,986	161,097
Capitalized costs relating to exploration and production activities, gross		7,280,889	6,716,185
Less — Accumulated Depreciation, Depletion and Amortization		5,004,299	4,269,959
Capitalized costs relating to exploration and production activities, net		2,276,590	2,446,226
Asset retirement costs		$ 175,200	$ 129,200
[1] Includes asset retirement costs of $175.2 million and $129.2 million at September 30, 2024 and 2023, respectively.

Supplementary Information for_4

Supplementary Information for Exploration and Production Activities - Summary of Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	$ 8,136	$ 104,858	$ 2,072
Development Costs	46,597	1,821	185
Exploration Costs	10,813	0	0
Capitalized Interest	778	0	0
Capitalized costs of unproved properties excluded from amortization, total	66,324	$ 106,679	$ 2,257
Capitalized Costs of Unproved Properties Cumulative Balance
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	140,753
Development Costs	48,642
Exploration Costs	10,813
Capitalized Interest	778
Capitalized costs of unproved properties excluded from amortization, total	$ 200,986
Costs Incurred Prior to Fiscal 2022
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs				$ 25,687
Development Costs				39
Exploration Costs				0
Capitalized Interest				0
Capitalized costs of unproved properties excluded from amortization, total				$ 25,726

Supplementary Information for_5

Supplementary Information for Exploration and Production Activities - Costs Incurred in Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Property Acquisition Costs:
Proved		$ 17,069	$ 33,190	$ 2,491
Unproved		19,526	129,061	10,665
Exploration Costs	[1]	53,519	10,055	9,631
Development Costs	[2]	429,151	553,469	528,684
Asset Retirement Costs		46,017	8,363	9,768
Total Property Acquisition Costs		565,282	734,138	561,239
Capitalized interest included in exploration costs		100	0	0
Capitalized interest included in development costs		$ 700	$ 100	$ 600
[1] Amounts for 2024, 2023 and 2022 include capitalized interest of $0.1 million, zero and zero respectively. Amounts for 2024, 2023 and 2022 include capitalized interest of $0.7 million, $0.1 million and $0.6 million, respectively.

Supplementary Information for_6

Supplementary Information for Exploration and Production Activities - Narrative (Details) $ in Millions, Bcf in Billions	12 Months Ended
	Sep. 30, 2024 USD ($) pUDLocation Bcf	Sep. 30, 2023 USD ($) pUDLocation Bcf	Sep. 30, 2022 USD ($) Bcf	Sep. 30, 2021	Sep. 30, 2020
Reserve Quantities [Line Items]
Amount spent for developing proved undeveloped reserves | $	$ 305.6	$ 342	$ 154.3
Proved undeveloped reserve volume (in Bcfe)	1,267	985	858
Percentage of PUD reserves to the total proved reserves	26.70%	21.70%	20.60%
Increase in PUD reserves (in Bcfe)	282	127
New PUD reserve additions (in Bcfe)	602	554
PUD reserves added back (in Bcfe)		14
Number of PUD wells added back | pUDLocation		1
PUD upward revisions (in Bcfe)	76	23
PUD conversions to developed reserves (in Bcfe)	291	402
Proved undeveloped reserves removed (in Bcfe)	105	62
Number of PUD well locations removed | pUDLocation	9	7
Investment made to convert proved undeveloped reserves to developed reserves | $	$ 306	$ 342
Conversion of undeveloped proved reserves to developed proved reserves after revisions (in Bcfe)	374	440
Conversion of PUD to developed to PUD reserves booked at end of prior year (as a percent)	30%	47%	45%	34%	36%
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 | $	$ 300
Utica Shale
Reserve Quantities [Line Items]
Proved undeveloped reserve volume (in Bcfe)	925	873	503
PUD conversions to developed reserves (in Bcfe)		127
Marcellus Shale Fields
Reserve Quantities [Line Items]
Proved undeveloped reserve volume (in Bcfe)	342	112	355
PUD conversions to developed reserves (in Bcfe)		275
Appalachian Region
Reserve Quantities [Line Items]
Number of well locations developed with net PUD reserves | pUDLocation	20	39
Number of well locations to be developed with net PUD reserves | pUDLocation	73	77

Supplementary Information for_7

Supplementary Information for Exploration and Production Activities - Results of Operations for Producing Activities (Details) - USD ($)		12 Months Ended
		Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Reserve Quantities [Line Items]
Operating Revenues	[1]	$ 741,076,000	$ 1,038,760,000	$ 1,881,680,000
Production/Lifting Costs		270,927,000	253,555,000	283,914,000
Franchise/Ad Valorem Taxes		13,468,000	17,532,000	25,112,000
Purchased Emission Allowance Expense		0	0	1,305,000
Accretion Expense		5,992,000	5,673,000	7,530,000
Depreciation, Depletion and Amortization ($0.69, $0.63 and $0.57 per Mcfe of production, respectively)		270,648,000	235,694,000	202,418,000
Impairment of Exploration and Production Properties		463,692,000	0	0
Income Tax Expense (Benefit)		(76,983,000)	145,574,000	368,925,000
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)		(206,668,000)	380,732,000	992,476,000
Revenues from sales to affiliates		0	0	0
Transfers to operations		1,557,000	1,957,000	5,696,000
Depreciation, Depletion and Amortization (per Mcfe of production)		0.69	0.63	0.57
Gas
Reserve Quantities [Line Items]
Gas (includes transfers to operations of $1,557, $1,957, and $5,696, respectively)	[2]	738,778,000	1,036,499,000	1,730,723,000
Oil, Condensate and Other Liquids
Reserve Quantities [Line Items]
Operating Revenues		$ 2,298,000	$ 2,261,000	$ 150,957,000
[1] Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments. There were no revenues from sales to affiliates for all years presented.

Supplementary Information for_8

Supplementary Information for Exploration and Production Activities - Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Details) Bcf in Thousands		12 Months Ended
		Sep. 30, 2024 MBbls MMcf Bcf	Sep. 30, 2023 MMcf MBbls Bcf	Sep. 30, 2022 MBbls MMcf Bcf	Sep. 30, 2021 MMcf MBbls
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved undeveloped reserve volume | Bcf		1,267,000,000	985,000,000	858,000,000
Gas MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning of Period		4,535,084	4,170,662	3,723,433
Extensions and Discoveries		601,679	670,438	837,510
Revisions of Previous Estimates		7,046	32,379	2,953
Production		(392,047)	(372,271)	(342,911)
Sale of Minerals in Place				(50,323)
Purchases of Minerals in Place			33,876
Proved Developed and Undeveloped Reserves, End of Period		4,751,762	4,535,084	4,170,662
Proved developed reserves volume		3,484,852	3,550,034	3,312,568	3,091,463
Proved undeveloped reserve volume		1,266,910	985,050	858,094	631,970
Oil Mbbl
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning of Period | MBbls		216	250	21,537
Extensions and Discoveries | MBbls				296
Revisions of Previous Estimates | MBbls		8	(4)	787
Production		(31)	(30)	(1,604)
Sale of Minerals in Place | MBbls				(20,766)
Proved Developed and Undeveloped Reserves, End of Period | MBbls		193	216	250
Proved developed reserves volume | MBbls		193	216	250	20,941
Proved undeveloped reserve volume | MBbls		0	0	0	596
Appalachian Region | Gas MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning of Period		4,535,084	4,170,662	3,693,148
Extensions and Discoveries	[1]	601,679	670,438	837,510
Revisions of Previous Estimates		7,046	32,379	2,882
Production	[2]	(392,047)	(372,271)	(341,700)
Sale of Minerals in Place				(21,178)
Purchases of Minerals in Place			33,876
Proved Developed and Undeveloped Reserves, End of Period		4,751,762	4,535,084	4,170,662
Proved developed reserves volume		3,484,852	3,550,034	3,312,568	3,061,178
Proved undeveloped reserve volume		1,266,910	985,050	858,094	631,970
Appalachian Region | Oil Mbbl
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning of Period | MBbls		216	250	11
Extensions and Discoveries | MBbls				0
Revisions of Previous Estimates | MBbls		8	(4)	255
Production		(31)	(30)	(16)
Sale of Minerals in Place | MBbls				0
Proved Developed and Undeveloped Reserves, End of Period | MBbls		193	216	250
Proved developed reserves volume | MBbls		193	216	250	11
Proved undeveloped reserve volume | MBbls		0	0	0	0
West Coast Region | Gas MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Developed and Undeveloped Reserves, Beginning of Period		0	0	30,285
Extensions and Discoveries		0	0	0
Revisions of Previous Estimates		0	0	71
Production		0	0	(1,211)
Sale of Minerals in Place				(29,145)
Purchases of Minerals in Place			0
Proved Developed and Undeveloped Reserves, End of Period		0	0	0
Proved developed reserves volume		0	0	0	30,285
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	0	21,526
Extensions and Discoveries | MBbls				296
Revisions of Previous Estimates | MBbls		0	0	532
Production		0	0	(1,588)
Sale of Minerals in Place | MBbls				(20,766)
Proved Developed and Undeveloped Reserves, End of Period | MBbls		0	0	0
Proved developed reserves volume | MBbls		0	0	0	20,930
Proved undeveloped reserve volume | MBbls		0	0	0	596
Marcellus Shale Fields
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved undeveloped reserve volume | Bcf		342,000,000	112,000,000	355,000,000
Marcellus Shale Fields | Gas MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Extensions and Discoveries | Bcf		230	163	301
Production		(235,955)	(190,290)	(209,463)
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		925,000,000	873,000,000	503,000,000
Utica Shale | Gas MMcf
Proved Developed and Undeveloped Reserves [Roll Forward]
Extensions and Discoveries | Bcf		372	507	537
Production		(154,701)	(180,750)	(130,240)
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15%
[1] Extensions and discoveries include 301 Bcf (during 2022), 163 Bcf (during 2023) and 230 Bcf (during 2024), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 537 Bcf (during 2022), 507 Bcf (during 2023) and 372 Bcf (during 2024), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. Production includes 209,463 MMcf (during 2022), 190,290 MMcf (during 2023) and 235,955 MMcf (during 2024), from Marcellus Shale fields. Production includes 130,240 MMcf (during 2022), 180,750 MMcf (during 2023) and 154,701 MMcf (during 2024), from Utica Shale fields.

Supplementary Information for_9

Supplementary Information for Exploration and Production Activities - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Details) - USD ($) $ in Thousands	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2021
Supplementary Information for Exploration and Production Activities Unaudited [Abstract]
Future Cash Inflows	$ 8,514,126	$ 11,947,345	$ 19,209,099
Less:
Future Production Costs	3,672,901	3,538,389	3,138,226
Future Development Costs	1,191,708	1,095,096	781,847
Future Income Tax Expense at Applicable Statutory Rate	826,094	1,867,457	3,876,272
Future Net Cash Flows	2,823,423	5,446,403	11,412,754
Less:
10% Annual Discount for Estimated Timing of Cash Flows	1,486,968	2,874,295	5,964,424
Standardized Measure of Discounted Future Net Cash Flows	$ 1,336,455	$ 2,572,108	$ 5,448,330	$ 2,353,572

Supplementary Information fo_10

Supplementary Information for Exploration and Production Activities - Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2024	Sep. 30, 2023	Sep. 30, 2022
Standardized Measure of Discounted Future Net Cash Flows [Roll Forward]
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$ 2,572,108	$ 5,448,330	$ 2,353,572
Sales, Net of Production Costs	(456,506)	(767,487)	(1,572,402)
Net Changes in Prices, Net of Production Costs	(1,829,714)	(3,918,392)	4,132,889
Extensions and Discoveries	(11,007)	237,057	1,355,257
Changes in Estimated Future Development Costs	32,990	(222,233)	(32,160)
Purchases of Minerals in Place	0	34,346	0
Sales of Minerals in Place	0	0	(311,308)
Previously Estimated Development Costs Incurred	305,602	342,024	154,253
Net Change in Income Taxes at Applicable Statutory Rate	462,075	959,728	(1,180,349)
Revisions of Previous Quantity Estimates	19,216	33,192	3,316
Accretion of Discount and Other	241,691	425,543	545,262
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$ 1,336,455	$ 2,572,108	$ 5,448,330