National Fuel Gas (NFG) 10-K 20 Nov 20 2020 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2020	Oct. 31, 2020	Mar. 31, 2020
Cover [Abstract]
Amendment Flag	false
Current Fiscal Year End Date	--09-30
Document Annual Report	true
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2020
Document Period End Date	Sep. 30, 2020
Documents Incorporated by Reference	Portions of the registrant’s definitive Proxy Statement for its 2021 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2020, are incorporated by reference into Part III of this report.
Document Transition Report	false
Document Type	10-K
Entity Address, Address Line One	6363 Main Street
Entity Address, City or Town	Williamsville,
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	14221
Entity Central Index Key	0000070145
Entity Common Stock, Shares Outstanding		90,965,576
Entity Current Reporting Status	Yes
Entity Emerging Growth Company	false
Entity File Number	1-3880
Entity Filer Category	Large Accelerated Filer
Entity Incorporation, State or Country Code	NJ
Entity Interactive Data Current	Yes
Entity Public Float			$ 3,219,563,000
Entity Listing, Par Value Per Share	$ 1
Entity Registrant Name	National Fuel Gas Company
Entity Shell Company	false
Entity Small Business	false
Entity Tax Identification Number	13-1086010
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
City Area Code	716
Local Phone Number	857-7000
Title of 12(b) Security	Common Stock, par value $1.00 per share
Security Exchange Name	NYSE
Trading Symbol	NFG
ICFR Auditor Attestation Flag	true

Consolidated Statements Of Inco

Consolidated Statements Of Income And Earnings Reinvested In The Business - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
INCOME
Operating Revenues	$ 1,546,291	$ 1,693,332	$ 1,592,668
Operating Expenses:
Purchased Gas	233,890	386,265	337,822
Property, Franchise and Other Taxes	88,400	88,886	84,393
Depreciation, Depletion and Amortization	306,158	275,660	240,961
Impairment of Oil and Gas Producing Properties	449,438	0	0
Total Operating Expenses	1,516,433	1,181,523	1,072,945
Operating Income	29,858	511,809	519,723
Other Income (Expense):
Other Income (Deductions)	(17,814)	(15,542)	(21,174)
Interest Expense on Long-Term Debt	(110,012)	(101,614)	(110,946)
Other Interest Expense	(7,065)	(5,142)	(3,576)
Income (Loss) Before Income Taxes	(105,033)	389,511	384,027
Income Tax Expense (Benefit)	18,739	85,221	(7,494)
Net Income (Loss) Available for Common Stock	(123,772)	304,290	391,521
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	1,272,601	1,098,900	851,669
Beginning Retained Earnings Unappropriated And Current Period Net Income	1,148,829	1,403,190	1,243,190
Dividends on Common Stock	(156,249)	(148,432)	(144,290)
Balance at End of Year	$ 991,630	$ 1,272,601	$ 1,098,900
Earnings (Loss) Per Common Share, Basic:
Net Income (Loss) Available for Common Stock (in dollars per share)	$ (1.41)	$ 3.53	$ 4.56
Earnings (Loss) Per Common Share, Diluted:
Net Income (Loss) Available for Common Stock (in dollars per share)	$ (1.41)	$ 3.51	$ 4.53
Weighted Average Number of Shares Outstanding:
Used in Basic Calculation	87,968,895	86,235,550	85,830,597
Used in Diluted Calculation	87,968,895	86,773,259	86,439,698
Utility and Energy Marketing [Member]
INCOME
Operating Revenues	$ 728,336	$ 860,985	$ 812,474
Operating Expenses:
Operation and Maintenance	181,051	171,472	168,885
Exploration and Production and Other [Member]
INCOME
Operating Revenues	611,885	636,528	569,808
Operating Expenses:
Operation and Maintenance	148,856	147,457	139,546
Pipeline and Storage and Gathering [Member]
INCOME
Operating Revenues	206,070	195,819	210,386
Operating Expenses:
Operation and Maintenance	108,640	111,783	101,338
Guidance for Hedging [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	(950)	0	0
Balance at End of Year		(950)	0
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	0	7,437	0
Balance at End of Year		0	7,437
Guidance for Reclassification of Stranded Tax Effects [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	$ 0	10,406	0
Balance at End of Year		$ 0	$ 10,406

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Statement of Comprehensive Income [Abstract]
Net Income (Loss) Available for Common Stock	$ (123,772)	$ 304,290	$ 391,521
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(19,214)	(44,089)	6,225
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	15,361	7,332	9,704
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	0	0	132
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss)	9,862
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss)		79,301	(74,103)
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	0	0	(430)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(93,295)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income		5,464	1,189
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	1,313	0	0
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	0	(11,738)	0
Other Comprehensive Income (Loss), Before Tax	(85,973)	36,270	(57,283)
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(4,357)	(10,473)	1,582
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	3,566	1,698	2,437
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	0	0	(15)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	2,578
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		20,619	(22,547)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	0	0	(158)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(25,521)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income		2,726	(955)
Income Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging	363	0	0
Reclassification Adjustment for Income Tax Benefit (Expense) on the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	0	(4,301)	0
Reclassification Adjustment for Stranded Tax Effects Related to the 2017 Tax Reform Act to Earnings Reinvested in the Business	0	10,406	0
Income Taxes - Net	(23,371)	20,675	(19,656)
Other Comprehensive Income (Loss)	(62,602)	15,595	(37,627)
Comprehensive Income (Loss)	$ (186,374)	$ 319,885	$ 353,894

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2020	Sep. 30, 2019
ASSETS
Property, Plant and Equipment		$ 12,351,852	$ 11,204,838
Less - Accumulated Depreciation, Depletion and Amortization		6,353,785	5,695,328
Property, Plant and Equipment, Net, Total		5,998,067	5,509,510
Assets Held for Sale, Net		53,424	0
Current Assets
Cash and Temporary Cash Investments		20,541	20,428
Hedging Collateral Deposits		0	6,832	[1]
Receivables - Net of Allowance for Uncollectible Accounts of $22,810 and $25,788, Respectively		143,583	139,956
Unbilled Revenue		17,302	18,758
Gas Stored Underground		33,338	36,632
Materials, Supplies and Emission Allowances		51,877	40,717
Unrecovered Purchased Gas Costs		0	2,246
Other Current Assets		47,557	97,054
Total Current Assets		314,198	362,623
Other Assets
Recoverable Future Taxes		118,310	115,197
Unamortized Debt Expense		12,297	14,005
Other Regulatory Assets		156,106	167,320
Deferred Charges		67,131	33,843
Other Investments		154,502	144,917
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		76,035	60,517
Fair Value of Derivative Financial Instruments		9,308	48,669
Other		81	80
Total Other Assets		599,246	590,024
Total Assets		6,964,935	6,462,157
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 90,954,696 Shares and 86,315,287 Shares, Respectively		90,955	86,315
Paid In Capital		1,004,158	832,264
Earnings Reinvested in the Business		991,630	1,272,601
Accumulated Other Comprehensive Loss		(114,757)	(52,155)
Total Comprehensive Shareholders' Equity		1,971,986	2,139,025
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,629,576	2,133,718
Total Capitalization		4,601,562	4,272,743
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		30,000	55,200
Current Portion of Long-Term Debt	[2]	0	0
Accounts Payable		134,126	132,208
Amounts Payable to Customers		10,788	4,017
Dividends Payable		40,475	37,547
Interest Payable on Long-Term Debt		27,521	18,508
Customer Advances		15,319	13,044
Customer Security Deposits		17,199	16,210
Other Accruals and Current Liabilities		140,176	139,600
Fair Value of Derivative Financial Instruments		43,969	5,574
Total Current and Accrued Liabilities		459,573	421,908
Deferred Credits
Deferred Income Taxes		696,054	653,382
Taxes Refundable to Customers		357,508	366,503
Cost of Removal Regulatory Liability		230,079	221,699
Other Regulatory Liabilities		161,573	142,367
Pension and Other Post-Retirement Liabilities		127,181	133,729
Asset Retirement Obligations		192,228	127,458
Other Deferred Credits		139,177	122,368
Total Deferred Credits		1,903,800	1,767,506
Commitments and Contingencies (Note L)		0	0
Total Capitalization and Liabilities		$ 6,964,935	$ 6,462,157
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
[2]	None of the Company's long-term debt at September 30, 2020 and 2019 will mature within the following twelve-month period.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 22,810	$ 25,788
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	90,954,696	86,315,287
Common Stock, Shares Outstanding	90,954,696	86,315,287

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Operating Activities
Net Income (Loss) Available for Common Stock	$ (123,772)	$ 304,290	$ 391,521
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	449,438	0	0
Depreciation, Depletion and Amortization	306,158	275,660	240,961
Deferred Income Taxes	54,313	122,265	(18,153)
Stock-Based Compensation	14,931	21,186	15,762
Other	6,527	8,608	16,133
Change in:
Receivables and Unbilled Revenue	(2,578)	6,379	(30,882)
Gas Stored Underground and Materials, Supplies and Emission Allowances	(6,625)	(3,713)	(4,021)
Unrecovered Purchased Gas Costs	2,246	1,958	419
Other Current Assets	49,367	(29,030)	(16,519)
Accounts Payable	(4,657)	(24,770)	17,962
Amounts Payable to Customers	6,771	623	3,394
Customer Advances	2,275	(565)	(2,092)
Customer Security Deposits	989	(9,493)	5,331
Other Accruals and Current Liabilities	5,001	10,992	3,865
Other Assets	(24,203)	5,115	(9,556)
Other Liabilities	4,628	4,978	1,178
Net Cash Provided by Operating Activities	740,809	694,483	615,303
Investing Activities
Capital Expenditures	(716,153)	(788,938)	(584,004)
Acquisition of Upstream Assets and Midstream Gathering Assets	(506,258)	0	0
Net Proceeds from Sale of Oil and Gas Producing Properties	0	0	55,506
Other	(1,205)	(10,237)	(389)
Net Cash Used in Investing Activities	(1,223,616)	(799,175)	(528,887)
Financing Activities
Change in Notes Payable to Banks and Commercial Paper	(25,200)	55,200	0
Net Proceeds from Issuance of Long-Term Debt	493,007	0	295,020
Reduction of Long-Term Debt	0	0	(566,512)
Net Repurchases of Common Stock		(8,877)
Net Proceeds from Issuance of Common Stock	161,603		4,110
Dividends Paid on Common Stock	(153,322)	(147,418)	(143,258)
Net Cash Provided by (Used in) Financing Activities	476,088	(101,095)	(410,640)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash	(6,719)	(205,787)	(324,224)
Cash, Cash Equivalents and Restricted Cash At Beginning of Year	27,260	233,047	557,271
Cash, Cash Equivalents and Restricted Cash At End of Year	20,541	27,260	233,047
Supplemental Disclosure of Cash Flow Information
Cash Paid for Interest	103,479	102,920	126,079
Cash Refunded for Income Taxes	(82,876)	(17,342)
Cash Paid for Income Taxes			31,771
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities
Non-Cash Capital Expenditures	$ 87,328	$ 81,121	$ 88,813

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2020
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulation The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note F — Regulatory Matters for further discussion. Allowance for Uncollectible Accounts The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic environment. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. In response to the COVID-19 pandemic, the Company has suspended collection and termination activity for non-payments in its Utility service territories. To date, despite the economic conditions that have arisen as a result of the COVID-19 pandemic, the Company has not experienced any meaningful change in the rate at which its customers pay their bills. To the extent the economic impacts of the COVID-19 pandemic continue into the winter heating season, the Company is anticipating that customer non-payments may increase as seasonally higher natural gas prices and usage will lead to higher costs for customers. Regulatory Mechanisms The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year. Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note F — Regulatory Matters for further discussion. The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues. The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending March 31st, and applied to customer bills annually, beginning July 1st. In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire. Asset Acquisition and Business Combination Accounting In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business. If the initial screening test is not met, the Company evaluates whether the set is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance. When the Company acquires assets and liabilities deemed to be an asset acquisition, the fair value of the purchase consideration, including the transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to the individual assets and liabilities assumed based on their relative fair values. Transaction costs associated with asset acquisitions are capitalized as part of the costs of the group of assets acquired. When the Company acquires assets and liabilities deemed to be a business combination, the acquisition method is applied. Goodwill is measured as the fair value of the consideration transferred less the net recognized fair value of the identifiable assets acquired and the liabilities assumed, all measured at the acquisition date. Transaction costs that the Company incurs in connection with a business combination, such as finders’ fees, legal fees, due diligence fees and other professional and consulting fees are expensed as incurred. Variable Interest Entity Accounting In accordance with authoritative guidance issued by the FASB concerning a variable interest entity (VIE), the Company will evaluate a VIE to determine whether it is the primary beneficiary and therefore is considered to have a controlling financial interest. If the Company has the power to direct the activities of a VIE and the obligation to absorb significant losses of that entity or the right to receive significant benefits from that entity, the Company is considered to be the primary beneficiary and therefore consolidates that VIE into the Company’s consolidated financial statements. Property, Plant and Equipment In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.8 billion and $1.7 billion at September 30, 2020 and 2019, respectively. For further discussion of capitalized costs, refer to Note O — Supplementary Information for Oil and Gas Producing Activities. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The book value of the oil and gas properties exceeded the ceiling at September 30, 2020 as well as at June 30, 2020 and March 31, 2020. As such, the Company recognized pre-tax impairment charges of $449.4 million for the year ended September 30, 2020. Deferred income tax benefits of $123.1 million related to the impairment charges were also recognized for the year ended September 30, 2020. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2020, 2019 and 2018, estimated future net cash flows were increased by $180.0 million, decreased by $17.7 million and decreased by $25.1 million, respectively. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service. Despite the economic conditions arising from the COVID-19 pandemic, there were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2020. Management will continue to monitor the situation on a quarterly basis. Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation. Depreciation, Depletion and Amortization For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. Depreciation, depletion and amortization expense for oil and gas properties was $166.8 million, $149.9 million and $119.9 million for the years ended September 30, 2020, 2019 and 2018, respectively. In the All Other category, for timber properties, depletion, determined on a property by property basis, has historically been charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. However, as discussed below in Note B — Asset Acquisitions and Divestitures, most of the Company's timber properties have been reclassified to Assets Held for Sale. The impact of that reclassification is reflected in the tables below. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment: As of September 30 2020 2019 (Thousands) Exploration and Production $ 6,384,086 $ 5,747,731 Pipeline and Storage 2,418,265 2,191,166 Gathering 849,204 577,021 Utility 2,234,433 2,159,841 All Other and Corporate 20,372 112,857 $ 11,906,360 $ 10,788,616 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2020 2019 2018 Exploration and Production, per Mcfe(1) $ 0.71 $ 0.73 $ 0.70 Pipeline and Storage 2.4 % 2.2 % 2.2 % Gathering 3.2 % 3.6 % 3.4 % Utility 2.7 % 2.7 % 2.8 % All Other and Corporate 3.6 % 1.8 % 2.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note O — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.69, $0.71 and $0.67 per Mcfe of production in 2020, 2019 and 2018, respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2020 and 2019 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, 2020, 2019 and 2018, 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 gas and oil 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, crude oil price swap agreements, 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 or purchased gas expense on the Consolidated Statements of Income. Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges. Accumulated Other Comprehensive Income (Loss) The components of Accumulated Other Comprehensive Income (Loss) and changes for the years ended September 30, 2020 and 2019, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Year Ended September 30, 2020 Balance at October 1, 2019 $ 34,675 $ — $ (86,830) $ (52,155) Other Comprehensive Gains and Losses Before Reclassifications 7,284 — (14,857) (7,573) Amounts Reclassified From Other Comprehensive Loss (67,774) — 11,795 (55,979) Cumulative Effect of Adoption of Authoritative Guidance for Hedging 950 — — 950 Balance at September 30, 2020 $ (24,865) $ — $ (89,892) $ (114,757) Year Ended September 30, 2019 Balance at October 1, 2018 $ (28,611) $ 7,437 $ (46,576) $ (67,750) Other Comprehensive Gains and Losses Before Reclassifications 58,682 — (33,616) 25,066 Amounts Reclassified From Other Comprehensive Income 2,738 — 5,634 8,372 Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities — (7,437) — (7,437) Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act 1,866 — (12,272) (10,406) Balance at September 30, 2019 $ 34,675 $ — $ (86,830) $ (52,155) The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $0.9 million and $1.0 million at September 30, 2020 and 2019, respectively. The total amount for accumulated losses was $89.0 million and $85.8 million at September 30, 2020 and 2019, respectively. In August 2017, the FASB issued authoritative guidance which changes the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities and to simplify the application of hedge accounting. The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million and increased accumulated other comprehensive income by the same amount. In February 2018, the FASB issued authoritative guidance that allows an entity to elect a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the 2017 Tax Reform Act and requires certain disclosures about stranded tax effects. The Company adopted this authoritative guidance effective January 1, 2019 and recorded a cumulative effect adjustment related to deferred income taxes associated with hedging activities and pension and post-retirement benefit obligations during the quarter ended March 31, 2019 to increase retained earnings by $10.4 million and decrease accumulated other comprehensive income by the same amount. In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through accumulated other comprehensive income. The Company adopted this authoritative guidance effective October 1, 2018 and, as called for by the modified retrospective method of adoption, recorded a cumulative effect adjustment during the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount. Reclassifications Out of Accumulated Other Comprehensive Income (Loss) The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the years ended September 30, 2020 and 2019 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 Income (Loss) for the Affected Line Item in the Statement Where Net Income is Presented 2020 2019 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $93,691 ($3,460) Operating Revenues Commodity Contracts 661 (1,182) Purchased Gas Foreign Currency Contracts (1,057) (822) Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (237) (264) (1) Net Actuarial Loss (15,124) (7,068) (1) 77,934 (12,796) Total Before Income Tax (21,955) 4,424 Income Tax Expense $55,979 ($8,372) Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details. Gas Stored Underground In the Utility segment, gas stored underground in the amount of $33.2 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 2020, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $6.6 million at September 30, 2020. Materials, Supplies and Emission Allowances The components of the Company's materials, supplies and emission allowances are as follows: Year Ended September 30 2020 2019 (Thousands) Materials and Supplies — at average cost $ 33,859 $ 29,819 Emission Allowances 18,018 10,898 $ 51,877 $ 40,717 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, 2020, the remaining weighted average amortization period for such costs was approximately 6 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 2020 2019 2018 2017 Cash and Temporary Cash Investments $ 20,541 $ 20,428 $ 229,606 $ 555,530 Hedging Collateral Deposits — 6,832 3,441 1,741 Cash, Cash Equivalents, and Restricted Cash $ 20,541 $ 27,260 $ 233,047 $ 557,271 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 hedging positions. 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 2020 2019 (Thousands) Prepayments $ 12,851 $ 12,728 Prepaid Property and Other Taxes 14,269 14,361 Federal Income Taxes Receivable — 42,388 State Income Taxes Receivable 3,828 8,579 Fair Values of Firm Commitments — 7,538 Regulatory Assets 16,609 11,460 $ 47,557 $ 97,054 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2020 2019 (Thousands) Accrued Capital Expenditures $ 33,344 $ 33,713 Regulatory Liabilities 44,890 50,332 Federal Income Taxes Payable 163 — Liability for Royalty and Working Interests 15,665 18,057 Non-Qualified Benefit Plan Liability 14,460 13,194 Other 31,654 24,304 $ 140,176 $ 139,600 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, 2020 and 2019, customers in the balanced billing programs had advanced excess funds of $15.3 million and $13.0 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, 2020 and 2019, the Company had received customer security deposits amounting to $17.2 million and $16.2 million, respectively. Earnings Per Common Share Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares. As the Company recognized a net loss for the year ended September 30, 2020, the aforementioned securities, amounting to 411,890 securities, were not recognized in the diluted earnings per share calculation for 2020. For the years ended September 30, 2019 and 2018, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 242,302 securities and 317,899 securities excluded as being antidilutive for the years ended September 30, 2019 and 2018, respectively. Stock-Based Compensation The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. SARs and stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no SAR or stock option is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs and stock options. For all Company stock awards, forfeitures are recognized as they occur. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also 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 accounting for restricted stock units is the same as the accounting for restricted stock awards, except that 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, 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, 2020
Business Combinations [Abstract]
Asset Acquisitions and Divestitures	Asset Acquisitions and Divestitures On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $506.3 million. The purchase price, which reflects an effective date of January 1, 2020, was reduced for production revenues less expenses that were retained by Shell from the effective date to the closing date. As part of the transaction, the Company acquired over 400,000 net acres in Appalachia, including approximately 200,000 net acres in Tioga County, Pennsylvania. The proved developed and undeveloped natural gas reserves associated with this acquisition amounted to 684,141 MMcf. In addition, the Company acquired gathering pipelines and related compression, water pipelines, and associated water handling infrastructure, all of which support the acquired Tioga County production operations. These gathering facilities are interconnected with various interstate pipelines, including the Company’s Empire pipeline system, with the potential to tie into the Company’s existing Covington gathering system. Post-closing, the Company has integrated the assets into its existing operations in Tioga County, which has resulted in cost synergies. This transaction was accounted for as an asset acquisition as substantially all the fair value of the gross assets acquired is concentrated in a single asset under the screen test comprised of Proved Developed Producing Reserves and the attached Gathering Property, Plant and Equipment. The purchase consideration, including the transaction costs, has been allocated to the individual assets acquired based on their relative fair values. The following is a summary of the asset acquisition (in thousands): Purchase Price $ 503,908 Transaction Costs 2,350 Total Consideration $ 506,258 Allocation of Cost of Asset Acquisition: Exploration and Production Reporting Segment Gathering Reporting Segment Total Property, Plant and Equipment $ 281,648 (1)(2) $ 223,369 (2) $ 505,017 Inventory 1,132 109 1,241 Total Accounting $ 282,780 $ 223,478 $ 506,258 (1) Includes $241,134 in Proved Developed Producing Properties and $277,832 capitalized in the full cost pool. (2) The Company utilized an income approach and market based approach to determine the fair value of the acquired property, plant and equipment in the Exploration and Production reporting segment. The Company utilized a cost approach and an income approach to determine the fair value of the acquired property, plant and equipment in the Gathering reporting segment. The acquisition of the upstream assets and midstream gathering assets from Shell was financed with a combination of debt and equity, as discussed in Note H — Capitalization and Short-Term Borrowings. The purchase and sale agreement with Shell was structured, in part, as a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). In connection with the Reverse 1031 Exchange, the Company, through a subsidiary, assigned the rights to acquire legal title to certain oil and natural gas properties to a VIE formed by an exchange accommodation titleholder. A subsidiary of the Company operates the properties pursuant to a lease agreement with the VIE. As the Company is deemed to be the primary beneficiary of the VIE, it has been included in the consolidated financial statements of the Company since its formation. Once the timber sale (discussed below) is completed, the affected properties will be conveyed to the Company and the VIE structure will be terminated. On August 5, 2020, the Company entered into a purchase and sale agreement to sell substantially all timber and other assets in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for $115.7 million, subject to closing adjustments. The transaction is expected to close before the end of calendar 2020. The Company intends to use the proceeds from this sale to complete the Reverse 1031 Exchange discussed above. At September 30, 2020, these assets, amounting to $53.4 million and consisting entirely of timber and other assets net of accumulated depletion, have been presented as Assets Held for Sale, Net on the Consolidated Balance Sheet. They previously were recorded as Net Property, Plant and Equipment. These assets are a component of the Company’s All Other category and do not have a major impact on the Company’s operations or financial results. Accordingly, the planned sale does not represent a strategic shift in focus for the Company and the financial results associated with operating these assets has not been reported as discontinued operations. On August 1, 2020, the Company completed the sale of NFR’s commercial and industrial gas contracts in New York and Pennsylvania and certain other assets to Marathon Power LLC. The sale did not have a material impact to the Company’s financial statements. The divestiture reflects the Company’s decision to focus on other strategic areas of the energy market. On May 1, 2018, the Company completed the sale of its oil and gas properties in the Sespe Field area of Ventura County, California, receiving net proceeds of $38.2 million (included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows). The divestiture of the Company’s oil and gas properties in the Sespe Field reflects continuing efforts to focus West Coast development activities in the San Joaquin basin, particularly at the Midway Sunset field in Kern County, California. Under the full cost method of accounting for oil and gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale. The Company also sold certain properties under a joint development agreement with IOG CRV - Marcellus, LLC that provided proceeds of $17.3 million in fiscal 2018. These proceeds were accounted for as a reduction of capitalized costs and are included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows for fiscal 2018.

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Sep. 30, 2020
Revenue from Contract with Customer [Abstract]
Revenue from Contracts with Customers	Revenue from Contracts with Customers The Company adopted authoritative guidance regarding revenue recognition on October 1, 2018 using the modified retrospective method of adoption for open contracts as of October 1, 2018. A cumulative effect adjustment to retained earnings was not necessary since no revenue recognition differences were identified when comparing the revenue recognition criteria under the new authoritative guidance to the previous guidance. The Company records revenue related to its derivative financial instruments in the Exploration and Production segment as well as in its NFR operations (included in the All Other category). The Company discontinued use of derivative financial instruments in its NFR operations upon completing the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. 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 new authoritative guidance since they are accounted for under other existing accounting guidance. The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2020 and 2019, presented by type of service from each reportable segment. Year Ended September 30, 2020 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 402,447 $ — $ — $ — $ 402,447 $ — $ — $ 402,447 Production of Crude Oil 107,844 — — — 107,844 — — 107,844 Natural Gas Processing 2,374 — — — 2,374 — — 2,374 Natural Gas Gathering Service — — 142,893 — 142,893 — (142,821) 72 Natural Gas Transportation Service — 229,391 — 109,214 338,605 — (77,699) 260,906 Natural Gas Storage Service — 79,073 — — 79,073 — (34,579) 44,494 Natural Gas Residential Sales — — — 475,846 475,846 — — 475,846 Natural Gas Commercial Sales — — — 61,239 61,239 — — 61,239 Natural Gas Industrial Sales — — — 3,291 3,291 — — 3,291 Natural Gas Marketing — — — — — 95,727 (835) 94,892 Other 1,097 1,140 — (5,281) (3,044) 5,174 (294) 1,836 Total Revenues from Contracts with Customers 513,762 309,604 142,893 644,309 1,610,568 100,901 (256,228) 1,455,241 Alternative Revenue Programs — — — 7,989 7,989 — — 7,989 Derivative Financial Instruments 93,691 — — — 93,691 (10,630) — 83,061 Total Revenues $ 607,453 $ 309,604 $ 142,893 $ 652,298 $ 1,712,248 $ 90,271 $ (256,228) $ 1,546,291 Year Ended September 30, 2019 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 481,048 $ — $ — $ — $ 481,048 $ — $ — $ 481,048 Production of Crude Oil 149,078 — — — 149,078 — — 149,078 Natural Gas Processing 3,277 — — — 3,277 — — 3,277 Natural Gas Gathering Service — — 127,064 — 127,064 — (127,064) — Natural Gas Transportation Service — 209,184 — 119,253 328,437 — (70,689) 257,748 Natural Gas Storage Service — 75,484 — — 75,484 — (32,488) 42,996 Natural Gas Residential Sales — — — 539,962 539,962 — — 539,962 Natural Gas Commercial Sales — — — 73,331 73,331 — — 73,331 Natural Gas Industrial Sales — — — 4,830 4,830 — — 4,830 Natural Gas Marketing — — — — — 143,627 (1,127) 142,500 Other 1,609 3,615 11 (8,630) (3,395) 3,424 (549) (520) Total Revenues from Contracts with Customers 635,012 288,283 127,075 728,746 1,779,116 147,051 (231,917) 1,694,250 Alternative Revenue Programs — — — (1,304) (1,304) — — (1,304) Derivative Financial Instruments (2,272) — — — (2,272) 2,658 — 386 Total Revenues $ 632,740 $ 288,283 $ 127,075 $ 727,442 $ 1,775,540 $ 149,709 $ (231,917) $ 1,693,332 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. Natural gas production occurs primarily in the Appalachian region of the United States and crude oil production occurs primarily in the West Coast 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 and oil 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: $185.2 million for fiscal 2021; $163.7 million for fiscal 2022; $132.4 million for fiscal 2023; $123.0 million for fiscal 2024; $116.7 million for fiscal 2025; and $517.4 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 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. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment. The Utility segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Utility segment’s tariffs allow customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year. Utility Segment Alternative Revenue Programs As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the new authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and conservation have on margin. The NYPSC has also authorized additional alternative revenue programs that adjust billings for the effects of broad external factors or to compensate the Company for demand-side management initiatives. These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to customers within 24 months of the annual reconciliation period. Energy Marketing Revenue The Company’s energy marketing subsidiary, NFR (included in the All Other category), which records revenue from natural gas sales in western and central New York and northwestern Pennsylvania, completed the sale of its commercial and industrial contracts and certain other assets on August 1, 2020 and is winding down its operations. The Company does not report NFR's energy marketing operations as a separate reportable segment. NFR's sales have been provided largely to industrial, wholesale, commercial, public authority and residential customers. NFR’s performance obligation to its customers has been 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 NFR. NFR 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 contracted or market based rate, indicates the value to the customer, and is used for revenue recognition purposes by NFR as specified by the “invoice practical expedient” (the amount that NFR has the right to invoice) under the authoritative guidance for revenue recognition. The Company used derivative financial instruments through August 1, 2020 to manage commodity price risk in its NFR operations related to the sale of natural gas to its customers. Gains or losses on such derivative financial instruments were recorded as adjustments to revenue; however, they were not considered to be revenue from contracts with customers.

Leases

Leases	12 Months Ended
	Sep. 30, 2020
Leases [Abstract]
Leases	Leases On October 1, 2019, the Company adopted authoritative guidance regarding lease accounting, which requires entities that lease the use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, including leases classified as operating leases. The Company implemented the new standard using the optional transition method and elected to apply the following practical expedients provided in the authoritative guidance: 1. For contracts that commenced prior to and existed as of October 1, 2019, a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification, and initial direct costs under the new authoritative guidance; 2. An election not to apply the recognition requirements in the new authoritative guidance to short-term leases (a lease that at commencement date has a lease term of one year or less); 3. A practical expedient to not reassess certain land easements that existed prior to October 1, 2019 and were not previously accounted for as leases under the prior authoritative guidance; and 4. A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset-class). Upon adoption, the Company increased assets and liabilities on its Consolidated Balance Sheet by $19.7 million. The adoption did not result in a cumulative effect adjustment to earnings reinvested in the business or have a material impact on the Company’s Consolidated Statement of Income or Consolidated Statement of Cash Flows. Comparative periods, including disclosures relating to those periods, were not restated. Nature of Leases The Company primarily leases building space and drilling rigs, and on a limited basis compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the authoritative guidance. As of September 30, 2020, the Company did not have any material finance leases. Aside from a sublease of office space at the Company’s corporate headquarters, the Company does not have any material arrangements where the Company is the lessor. Buildings and Property The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range from one month to ten 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 fourteen 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. In March 2020, the Company entered into a lease agreement that commenced in November 2020. This lease agreement is a building and property lease for a term of ten years. Total estimated base rent payments over the lease term are approximately $8.4 million. There is also an option to extend the term of the lease for one additional period of eighteen months. Drilling Rigs The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania and California. 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 the contract with amended terms and conditions, including a renegotiated day rate fee. The Company has strategically entered into shorter-term drilling rig arrangements to allow for operational and financial flexibility to respond to changes in its operating and economic environment. The Company uses discretion in choosing to extend or not extend drilling rig contracts on a rig by rig basis depending on market and operating conditions present at the time the contract expires, including prices for natural gas and oil and other performance indicators. Due to these considerations, the Company concluded that it is not reasonably certain that it will elect to extend any of its drilling rig arrangements beyond their primary non-cancelable terms of one year or less. Consequently, the Company’s drilling rig leases are deemed to be short-term leases subject to the exemption for balance sheet recognition. These costs are capitalized as part of oil and natural gas properties on the Consolidated Balance Sheet when incurred. 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 non-affiliated entities do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance. Oil and Gas Leases The new authoritative guidance does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. As such, the Company has concluded that its oil and 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 short-term drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the Company’s total operating lease costs (in thousands): Year Ended September 30, 2020 Operating Lease Expense $ 4,129 Variable Lease Expense(1) 525 Short-Term Lease Expense(2) 918 Sublease Income (297) Total Lease Expense $ 5,275 Short-Term Lease Costs Recorded to Property, Plant and Equipment(3) $ 19,232 (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) Short-term lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting. 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. As of September 30, 2020, the weighted average remaining lease term was 7.4 years and the weighted average discount rate was 3.39%. 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 Deferred Credits (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): At September 30, 2020 Assets: Deferred Charges $ 19,850 Liabilities: Other Accruals and Current Liabilities $ 4,943 Other Deferred Credits $ 14,777 For the year ended September 30, 2020, cash paid for lease liabilities, and reported in cash flows provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $5.3 million. During the year ended September 30, 2020, the Company did not record any right-of-use assets in exchange for new lease liabilities. 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, 2020 (in thousands): At September 30, 2020 2021 $ 4,968 2022 3,045 2023 2,507 2024 2,238 2025 2,086 Thereafter 7,631 Total Lease Payments 22,475 Less: Interest (2,755) Total Lease Liability $ 19,720 The future minimum operating lease payments as of September 30, 2019, as reported in the Company's 2019 Form 10-K, under the prior authoritative guidance are as follows (in thousands): At September 30, 2019 2020(1) $ 12,356 2021 2,813 2022 2,264 2023 2,270 2024 2,237 Thereafter 9,717 Total Operating Lease Obligations $ 31,657 (1) The future minimum operating lease payment amount for 2020 includes short-term leases, including drilling rigs, that are not included in the schedule of operating lease liability maturities above under the new authoritative guidance.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Sep. 30, 2020
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 crude oil and 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. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains, services and other components of the pipeline system in the Utility segment, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment. The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe. As discussed in Note B — Asset Acquisitions and Divestitures, on July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell. With the acquisition of these assets, the Company recorded an additional $57.2 million to its Asset Retirement Obligations at September 30, 2020, which is reflected in Liabilities Incurred in the table below. The following is a reconciliation of the change in the Company’s asset retirement obligations: Year Ended September 30 2020 2019 2018 (Thousands) Balance at Beginning of Year $ 127,458 $ 108,235 $ 106,395 Liabilities Incurred 61,246 4,122 5,597 Revisions of Estimates 3,267 16,693 (419) Liabilities Settled (7,268) (7,670) (12,858) Accretion Expense 7,525 6,078 9,520 Balance at End of Year $ 192,228 $ 127,458 $ 108,235

Regulatory Matters

Regulatory Matters	12 Months Ended
	Sep. 30, 2020
Regulatory Assets and Liabilities, Other Disclosures [Abstract]
Regulatory Matters	Regulatory Matters Regulatory Assets and Liabilities The Company has recorded the following regulatory assets and liabilities: At September 30 2020 2019 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note K) $ 107,010 $ 114,509 Post-Retirement Benefit Costs(2) (Note K) 18,863 18,236 Recoverable Future Taxes (Note G) 118,310 115,197 Environmental Site Remediation Costs(2) (Note L) 10,479 15,317 Asset Retirement Obligations(2) (Note E) 16,245 15,696 Unamortized Debt Expense (Note A) 12,297 14,005 Other(3) 20,118 15,022 Total Regulatory Assets 303,322 307,982 Less: Amounts Included in Other Current Assets (16,609) (11,460) Total Long-Term Regulatory Assets $ 286,713 $ 296,522 At September 30 2020 2019 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 230,079 $ 221,699 Taxes Refundable to Customers (Note G) 357,508 366,503 Post-Retirement Benefit Costs(4) (Note K) 146,474 126,577 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 10,788 4,017 Other(5) 59,989 66,122 Total Regulatory Liabilities 804,838 784,918 Less: Amounts included in Current and Accrued Liabilities (55,678) (54,349) Total Long-Term Regulatory Liabilities $ 749,160 $ 730,569 (1) The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates. (2) Included in Other Regulatory Assets on the Consolidated Balance Sheets. (3) $16,609 and $11,460 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,509 and $3,562 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $44,890 and $50,332 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,099 and $15,790 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2020 and 2019, 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 the customer that will be used in the future to fund asset retirement costs. New York Jurisdiction Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7%. The order also directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. Pennsylvania Jurisdiction Distribution Corporation’s Pennsylvania jurisdiction delivery rates are being charged to customers in accordance with a rate settlement approved by the PaPUC. The rate settlement does not specify any requirement to file a future rate case. FERC Jurisdiction Supply Corporation’s recent rate settlement, approved June 1, 2020, provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the corporate income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025. Supply has no rate case currently on file. Empire’s 2019 rate settlement provides that no party may make a filing for new rates before March 31, 2021. If no rate case has been filed, Empire must make a rate case filing no later than May 1, 2025.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes On December 22, 2017, federal tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changed the taxation of business entities and includes a reduction in the corporate federal income tax rate from 35% to 21% for fiscal 2019 and beyond. Since the Company is a fiscal year taxpayer, the Company was subject to a blended rate of 24.5% for fiscal 2018. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds or surcharges of other deferred income taxes will be determined by the federal and state regulatory agencies. The 2017 Tax Reform Act also repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are refundable, if not utilized to reduce tax, beginning in fiscal 2019. As of September 30, 2018, the Company had $85.0 million of AMT credit carryovers. The Company received the first installment for $42.5 million of AMT credit refunds related to fiscal 2019 in January 2020. On March 27, 2020, the “Coronavirus Aid, Relief and Economic Security (CARES) Act” was signed into law. The CARES Act, among other things, includes provisions relating to AMT credit refunds discussed above, refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, and modifications to the net interest deduction limitation. The Company filed for the acceleration of the remaining AMT credit refunds (under CARES) of $42.5 million, which were received in June 2020. The components of federal and state income taxes included in the Consolidated Statements of Income are as follows: Year Ended September 30 2020 2019 2018 (Thousands) Current Income Taxes — Federal $ (42,548) $ (41,645) $ 2,025 State 6,974 4,601 8,634 Deferred Income Taxes — Federal 4,538 98,514 (38,927) State 49,775 23,751 20,774 18,739 85,221 (7,494) Deferred Investment Tax Credit (13) (91) (105) Total Income Taxes $ 18,726 $ 85,130 $ (7,599) Presented as Follows: Other (Income) Deductions $ (13) $ (91) $ (105) Income Tax Expense (Benefit) 18,739 85,221 (7,494) Total Income Taxes $ 18,726 $ 85,130 $ (7,599) 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 2020 2019 2018 (Thousands) U.S. Income (Loss) Before Income Taxes $ (105,046) $ 389,420 $ 383,922 Income Tax Expense, Computed at U.S. Federal Statutory Rate(1) $ (22,060) $ 81,778 $ 94,061 State Valuation Allowance(2) 63,205 — — State Income Tax (3) (18,374) 22,397 22,203 Amortization of Excess Deferred Federal Income Taxes(4) (4,749) (3,185) (1,336) Plant Flow Through Items (2,848) (1,544) (872) Stock Compensation 3,867 (1,491) (321) Federal Tax Credits (217) (7,361) (6,576) Impact of 2017 Tax Reform Act(5) — (5,000) (112,598) Miscellaneous (98) (464) (2,160) Total Income Taxes $ 18,726 $ 85,130 $ (7,599) (1) For fiscal 2020 and 2019, the statutory rate of 21% was utilized. For fiscal 2018, a blended rate of 24.5% was utilized, calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters. (2) During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets, as discussed below. (3) The state income tax expense (benefit) shown above includes the impact of state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes. (4) Represents amortization of net excess deferred federal income taxes under the 2017 Tax Reform Act. (5) The $5.0 million benefit in fiscal 2019 represents the reversal of the estimated sequestration of AMT credit refunds. The amount for fiscal 2018 represents the remeasurement of deferred income taxes as a result of the lower U.S. corporate income tax rate, including a $5.0 million estimate for the potential sequestration of AMT credit refunds and the benefit of $9.1 million as a result of the blended tax rate. Significant components of the Company’s deferred tax liabilities and assets were as follows: At September 30 2020 2019 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 874,607 $ 861,278 Pension and Other Post-Retirement Benefit Costs 54,066 55,795 Other 23,377 54,486 Total Deferred Tax Liabilities 952,050 971,559 Deferred Tax Assets: Tax Loss and Credit Carryforwards (179,363) (175,542) Pension and Other Post-Retirement Benefit Costs (95,599) (87,280) Other (44,239) (55,355) Total Gross Deferred Tax Assets (319,201) (318,177) Valuation Allowance 63,205 — Total Deferred Tax Assets (255,996) (318,177) Total Net Deferred Income Taxes $ 696,054 $ 653,382 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 continually assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to the likelihood of the realization of the deferred tax assets. As of March 31, 2020, the Company recorded a valuation allowance against certain state deferred tax assets in the amount of $56.8 million based on its conclusion, considering all available objective evidence and the Company’s history of subsidiary state tax losses, that it was more likely than not that the deferred tax assets would not be realized. The valuation allowance increased to $63.2 million as of September 30, 2020 as a result of certain current year state net operating loss and tax credit activity. Changes in judgment regarding future realization of these deferred tax assets may result in a reversal of all or a portion of the valuation allowance. The Company will continue to re-assess this position each quarter. 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 $357.5 million and $366.5 million at September 30, 2020 and 2019, 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 $118.3 million and $115.2 million at September 30, 2020 and 2019, respectively. The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2020 2019 2018 (Thousands) Balance at Beginning of Year $ — $ — $ 1,251 Additions for Tax Positions of Prior Years — — — Reductions for Tax Positions of Prior Years — — (788) Reductions Related to Settlements with Taxing Authorities — — (463) Balance at End of Year $ — $ — $ — The IRS is currently conducting an examination of the Company for fiscal 2020 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. The federal statute of limitations remains open for fiscal 2017 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries operate mainly in four states which have 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. During fiscal 2009, preliminary consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property, subject to final guidance. The Company is awaiting the issuance of IRS guidance addressing the issue for natural gas utilities. Tax carryforwards available, prior to valuation allowance, at September 30, 2020, were as follows: Jurisdiction Tax Attribute Amount Expires Federal Pre-Fiscal 2019 Net Operating Loss $ 205,918 2032-2038 Federal Post-Fiscal 2018 Net Operating Loss 185,779 Unlimited Pennsylvania Net Operating Loss 428,672 2031-2041 California Net Operating Loss 224,159 2031-2041 Federal Enhanced Oil Recovery Credit 26,790 2029-2039 California Enhanced Oil Recovery Credit 8,502 2037-2039 California Alternative Minimum Tax Credit 8,864 Unlimited Federal R&D Tax Credit 6,550 2031-2040 Federal Charitable Contributions 1,559 2025

Capitalization And Short-Term B

Capitalization And Short-Term Borrowings	12 Months Ended
	Sep. 30, 2020
Capitalization And Short-Term Borrowings [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, 2017 85,543 $ 85,543 $ 796,646 $ 851,669 $ (30,123) Net Income Available for Common Stock 391,521 Dividends Declared on Common Stock ($1.68 Per Share) (144,290) Other Comprehensive Loss, Net of Tax (37,627) Share-Based Payment Expense(1) 14,235 Common Stock Issued Under Stock and Benefit Plans 414 414 9,342 Balance at September 30, 2018 85,957 85,957 820,223 1,098,900 (67,750) Net Income Available for Common Stock 304,290 Dividends Declared on Common Stock ($1.72 Per Share) (148,432) Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities 7,437 Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects 10,406 Other Comprehensive Income, Net of Tax 15,595 Share-Based Payment Expense(1) 19,613 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 358 358 (7,572) Balance at September 30, 2019 86,315 86,315 832,264 1,272,601 (52,155) Net Loss Available for Common Stock (123,772) Dividends Declared on Common Stock ($1.76 Per Share) (156,249) Cumulative Effect of Adoption of Authoritative Guidance for Hedging (950) Other Comprehensive Loss, Net of Tax (62,602) Share-Based Payment Expense(1) 13,180 Common Stock Issued from Sale of Common Stock 4,370 4,370 161,399 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 270 270 (2,685) Balance at September 30, 2020 90,955 $ 90,955 $ 1,004,158 $ 991,630 (2) $ (114,757) (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, 2020, $848.4 million of accumulated earnings was free of such limitations. Common Stock On June 2, 2020, the Company completed a public offering and sale of 4,370,000 shares of the Company's common stock, par value $1.00 per share, at a price of $39.50 per share. After deducting fees, commissions and other issuance costs, the net proceeds to the Company amounted to $165.8 million. The proceeds of this issuance were used to fund a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020. Refer to Note B – Asset Acquisitions and Divestitures for further discussion. 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 2020, 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 2020, the Company issued 87,835 original issue shares of common stock for restricted stock units that vested and 231,246 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 2020, 91,545 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, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 41,873 original issue shares of common stock during 2020. 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, 2020, 2019 and 2018 was approximately $13.1 million, $19.5 million and $14.2 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2020, 2019 and 2018 was approximately $2.1 million, $3.8 million and $3.4 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million was capitalized under these rules during each of the years ended September 30, 2020, 2019 and 2018. The tax expense related to stock-based compensation exercises and vestings was $3.2 million for the year ended September 30, 2020. SARs Transactions for 2020 involving SARs for all plans are summarized as follows: Number of Weighted Weighted Aggregate Outstanding at September 30, 2019 733,132 $ 54.90 Granted in 2020 — $ — Exercised in 2020 — $ — Forfeited in 2020 — $ — Expired in 2020 (219,952) $ 52.18 Outstanding at September 30, 2020 513,180 $ 56.07 1.28 $ — SARs exercisable at September 30, 2020 513,180 $ 56.07 1.28 $ — Shares available for future grant at September 30, 2020(1) 3,220,528 (1) Includes shares available for options, SARs, restricted stock and performance share grants. The Company did not grant any SARs during the years ended September 30, 2019 and 2018. The Company’s SARs include both performance based and nonperformance-based SARs, but the performance conditions associated with the performance based SARs at the time of grant have all been subsequently met. The SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for SARs is the same as the accounting for stock options. The total intrinsic value of SARs exercised during the years ended September 30, 2019 and 2018 totaled approximately $7.2 million, and $4.4 million, respectively. There were no SARs that became fully vested during the years ended September 30, 2020, 2019 and 2018, and all SARs outstanding have been fully vested since fiscal 2017. Restricted Share Awards Transactions for 2020 involving restricted share awards for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2019 20,000 $ 47.46 Granted in 2020 — $ — Vested in 2020 — $ — Forfeited in 2020 — $ — Outstanding at September 30, 2020 20,000 $ 47.46 The Company did not grant any restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2019 and 2018. As of September 30, 2020, unrecognized compensation expense related to restricted share awards totaled less than $0.1 million, which will be recognized over a weighted average period of 0.1 years. Vesting restrictions for the 20,000 outstanding shares of non-vested restricted stock at September 30, 2020 will lapse in 2021. Restricted Stock Units Transactions for 2020 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2019 281,607 $ 48.88 Granted in 2020 150,839 $ 40.38 Vested in 2020 (87,835) $ 50.26 Forfeited in 2020 (8,838) $ 46.72 Outstanding at September 30, 2020 335,773 $ 44.76 The Company also granted 123,939 and 89,672 nonperformance-based restricted stock units during the years ended September 30, 2019 and 2018, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2019 and 2018 was $49.40 per share and $51.23 per share, respectively. As of September 30, 2020, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $6.3 million, which will be recognized over a weighted average period of 2.1 years. Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2020 will lapse as follows: 2021 — 105,960 units; 2022 — 97,870 units; 2023 — 82,373 units; 2024 - 32,570 units; and 2025 - 17,000 units. Performance Shares Transactions for 2020 involving performance shares for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2019 522,514 $ 54.37 Granted in 2020 254,608 $ 43.32 Vested in 2020 (231,246) $ 55.33 Forfeited in 2020 (11,040) $ 46.40 Change in Units Based on Performance Achieved 57,792 $ 52.13 Outstanding at September 30, 2020 592,628 $ 49.18 The Company also granted 244,734 and 208,588 performance shares during the years ended September 30, 2019 and 2018, respectively. The weighted average grant date fair value of such performance shares granted in 2019 and 2018 was $55.67 per share and $50.95 per share, respectively. As of September 30, 2020, unrecognized compensation expense related to performance shares totaled approximately $10.6 million, which will be recognized over a weighted average period of 1.7 years. Vesting restrictions for the outstanding performance shares at September 30, 2020 will lapse as follows: 2021 — 169,912 shares; 2022 — 176,160 shares; and 2023 — 246,556 shares. Half of the performance shares granted during the years ended September 30, 2020, 2019 and 2018 must meet a performance goal related to relative return on capital over a three-year performance cycle. The performance goal over the respective performance cycles for the performance shares granted during 2020, 2019 and 2018 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 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 these 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 other half of the performance shares granted during the years ended September 30, 2020, 2019 and 2018 must meet a performance goal related to relative total shareholder return over a three-year performance cycle. The performance goal over the respective performance cycles for the total shareholder return performance shares ("TSR performance shares") granted during 2020, 2019 and 2018 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. In calculating the fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR performance shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant: Year Ended September 30 2020 2019 2018 Risk-Free Interest Rate 1.63 % 2.61 % 1.96 % Remaining Term at Date of Grant (Years) 2.81 2.78 2.78 Expected Volatility 19.3 % 20.2 % 22.0 % Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2020, 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 2020 2019 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(2)(3): 3.75% to 5.50% due December 2021 to September 2028 2,550,000 2,050,000 Total Long-Term Debt 2,649,000 2,149,000 Less Unamortized Discount and Debt Issuance Costs 19,424 15,282 Less Current Portion(4) — — $ 2,629,576 $ 2,133,718 (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 and $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to a maximum adjustment of 2.00% such that the coupon will not exceed 7.5% if there is a downgrade of the credit rating assigned to the notes. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded . (4) None of the Company's long-term debt at September 30, 2020 and 2019 will mature within the following twelve-month period. On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.0 million. The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt. On August 17, 2018, the Company issued $300.0 million of 4.75% notes due September 1, 2028. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $295.0 million. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $250.0 million of 8.75% notes on September 7, 2018 that were scheduled to mature in May 2019. The Company redeemed those notes for $259.5 million, plus accrued interest. In the Utility and Pipeline and Storage segments, the call premium of $8.5 million was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet as of September 30, 2018, and in the Exploration and Production segment, the call premium of $1.0 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the year ended September 30, 2018. The Company redeemed $300.0 million of 6.50% notes in October 2017 that were scheduled to mature in April 2018. The Company redeemed these notes for $307.0 million, plus accrued interest. The early redemption premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017. The Company financed this redemption with proceeds from its September 27, 2017 issuance of $300.0 million of 3.95% notes due September 15, 2027. As of September 30, 2020, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2021, $500.0 million in 2022, $549.0 million in 2023, zero in 2024, $500.0 million in 2025, and $1,100.0 million thereafter. Short-Term Borrowings The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. Due to the impacts from COVID-19 on availability of commercial paper, the Company also utilized its revolving committed credit facilities to meet funding needs. On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of 12 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. On May 4, 2020, the Company entered into a 364-Day Credit Agreement with a syndicate of 10 banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $200.0 million unsecured committed revolving credit facility. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. At September 30, 2020, the commercial paper program is backed by the Credit Agreement. At September 30, 2020, the Company had outstanding short-term notes payable to banks of $15.0 million, all of which was issued under the Credit Agreement. The Company had outstanding commercial paper of $15.0 million at September 30, 2020. At September 30, 2020, the weighted average interest rate on the short-term notes payable to banks was 1.51% and the weighted average interest rate on the commercial paper was 0.25%. At September 30, 2019, the Company had outstanding commercial paper of $55.2 million with a weighted average interest rate on the commercial paper of 2.50%. The Company did not have any outstanding short-term notes payable to banks at September 30, 2019. Debt Restrictions The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. This provision also applies to the Company's 364-Day Credit Agreement. Since July 1, 2018, the Company recorded after-tax ceiling test impairments totaling $326.3 million. As a result, at September 30, 2020, $163.1 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .55. The constraints specified in both the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $1.30 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65. On March 27, 2020, the Company was downgraded by S&P to a rating of BBB- with a negative outlook. S&P subsequently improved the Company's outlook to stable during the quarter ended June 30, 2020. Combined with current ratings from other credit rating agencies, the downgrade increased the Company's short-term borrowing costs under its Credit Agreement. A further downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources. The Credit Agreement and 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and the 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a 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. Under the Company’s existing indenture covenants at September 30, 2020, the Company is precluded from issuing incremental long-term unsecured indebtedness beginning in January 2021 as a result of impairments of its oil and gas properties recognized during the year ended September 30, 2020. The Company expects this restriction to extend for several quarters in fiscal 2021. Depending on the magnitude of any future impairments, it is possible that the Company's indenture covenants could restrict the Company's ability to issue additional long-term unsecured indebtedness beyond that period. The covenants would not preclude the Company from issuing long-term debt to replace maturing long-term debt, including the Company's 4.90% notes, in the principal amount of $500 million, maturing in December 2021. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of September 30, 2020) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Sep. 30, 2020
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, 2020 and 2019. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company. At Fair Value as of September 30, 2020 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 12,285 $ — $ — $ — $ 12,285 Derivative Financial Instruments: Over the Counter Swaps — Gas and Oil — 36,418 — (26,400) 10,018 Over the Counter No Cost Collars — Gas — — — (720) (720) Foreign Currency Contracts — 259 — (338) (79) Other Investments: Balanced Equity Mutual Fund 39,618 — — — 39,618 Fixed Income Mutual Fund 72,253 — — — 72,253 Common Stock — Financial Services Industry 639 — — — 639 Total $ 124,795 $ 36,677 $ — $ (27,458) $ 134,014 Liabilities: Derivative Financial Instruments: Over the Counter Swaps — Gas and Oil $ — $ 61,280 $ — $ (26,400) $ 34,880 Over the Counter No Cost Collars — Gas — 8,171 — (720) 7,451 Foreign Currency Contracts — 1,976 — (338) 1,638 Total $ — $ 71,427 $ — $ (27,458) $ 43,969 Total Net Assets/(Liabilities) $ 124,795 $ (34,750) $ — $ — $ 90,045 At Fair Value as of September 30, 2019 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 10,521 $ — $ — $ — $ 10,521 Derivative Financial Instruments: Commodity Futures Contracts — Gas 2,055 — — (2,055) — Over the Counter Swaps — Gas and Oil — 52,076 — (1,483) 50,593 Foreign Currency Contracts — 5 — (2,052) (2,047) Other Investments: Balanced Equity Mutual Fund 40,660 — — — 40,660 Fixed Income Mutual Fund 62,339 — — — 62,339 Common Stock — Financial Services Industry 844 — — — 844 Hedging Collateral Deposits 6,832 — — — 6,832 Total $ 123,251 $ 52,081 $ — $ (5,590) $ 169,742 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 7,149 $ — $ — $ (2,055) $ 5,094 Over the Counter Swaps — Gas and Oil — 1,671 — (1,483) 188 Foreign Currency Contracts — 2,344 — (2,052) 292 Total $ 7,149 $ 4,015 $ — $ (5,590) $ 5,574 Total Net Assets/(Liabilities) $ 116,102 $ 48,066 $ — $ — $ 164,168 (1) Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet. Derivative Financial Instruments At September 30, 2020, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements, natural gas no cost collars, crude oil price swap agreements, and foreign currency contracts, all of which are used in the Company's Exploration and Production segment. At September 30, 2019, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used by NFR (included in the All Other category). Hedging collateral deposits of $6.8 million at September 30, 2019, which are associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at September 30, 2019 consist of natural gas price swap agreements used in the Company’s Exploration and Production segment and in its NFR operations, crude oil price swap agreements used in the Company’s Exploration and Production segment, basis hedge swap agreements used by NFR and foreign currency contracts 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, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts at September 30, 2020 and September 30, 2019 are determined using the market approach based on observable market transactions of forward Canadian currency rates. The accounting rules 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, 2020, the Company determined that nonperformance risk 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.

Financial Instruments

Financial Instruments	12 Months Ended
	Sep. 30, 2020
Financial Instruments, Owned, at Fair Value [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 2020 2020 2019 Carrying 2019 (Thousands) Long-Term Debt $ 2,629,576 $ 2,778,556 $ 2,133,718 $ 2,257,085 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/LIBOR 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 2020 2019 (Thousands) Life Insurance Contracts $ 41,992 $ 41,074 Equity Mutual Fund 39,618 40,660 Fixed Income Mutual Fund 72,253 62,339 Marketable Equity Securities 639 844 $ 154,502 $ 144,917 Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities) are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and marketable equity and fixed income securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. Derivative Financial Instruments The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment. The Company enters into over-the-counter no cost collars and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. 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 10 years. 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, 2020 and September 30, 2019. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts. Cash Flow Hedges For derivative 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. Prior to October 1, 2019, gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness were recognized in current earnings rather than as a component of other comprehensive income (loss). For the year ended September 30, 2019, the Company recorded $2.1 million of hedging ineffectiveness gains that impacted operating revenue. With the October 1, 2019 adoption of the authoritative guidance that changes the financial reporting of hedging relationships and simplifies the application of hedge accounting, derivative instruments that are designated and qualify as a cash flow hedge will no longer have hedge ineffectiveness or a component excluded from the assessment of the effectiveness. As of September 30, 2020, the Company had the following commodity derivative contracts (swaps and no cost collars) outstanding: Commodity Units Natural Gas 286.7 Bcf Crude Oil 1,548,000 Bbls As of September 30, 2020, the Company was hedging a total of $78.0 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts. As of September 30, 2020, the Company had $34.8 million ($24.9 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $26.7 million ($19.1 million after tax) of such unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Derivatives in Cash Amount of Location of Amount of 2020 2019 2020 2019 Commodity Contracts $ 9,905 $ 82,984 Operating Revenue $ 93,691 $ (3,460) Commodity Contracts 391 (1,037) Purchased Gas 661 (1,182) Foreign Currency Contracts (434) (2,646) Operating Revenue (1,057) (822) Total $ 9,862 $ 79,301 $ 93,295 $ (5,464) 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 seventeen counterparties of which eight are in a net gain position. On average, the Company had $1.2 million of credit exposure per counterparty in a gain position at September 30, 2020. The maximum credit exposure per counterparty in a gain position at September 30, 2020 was $3.9 million. As of September 2020, 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, 2020, fifteen of the seventeen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to 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 instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At September 30, 2020, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $8.6 million according to the Company’s internal model (discussed in Note I — Fair Value Measurements). At September 30, 2020, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $44.0 million according to the Company's internal model. For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at September 30, 2020. 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, 2020
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 $4.2 million, $3.9 million and $3.5 million for the years ended September 30, 2020, 2019 and 2018, 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 $6.7 million, $6.4 million, and $6.2 million for the years ended September 30, 2020, 2019 and 2018, 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) on the Consolidated Statements of Income. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2020, 2019 and 2018. Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2020 2019 2018 2020 2019 2018 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 1,097,625 $ 985,690 $ 1,054,826 $ 468,163 $ 435,986 $ 462,619 Service Cost 9,318 8,482 9,921 1,609 1,519 1,830 Interest Cost 29,930 38,378 33,006 12,913 17,145 14,801 Plan Participants’ Contributions — — — 3,058 2,930 2,894 Retiree Drug Subsidy Receipts — — — 1,411 1,855 1,545 Actuarial (Gain) Loss 65,908 127,748 (50,218) 16,396 34,401 (21,039) Benefits Paid (63,676) (62,673) (61,845) (26,828) (25,673) (26,664) Benefit Obligation at End of Period $ 1,139,105 $ 1,097,625 $ 985,690 $ 476,722 $ 468,163 $ 435,986 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 968,449 $ 924,506 $ 910,719 $ 524,127 $ 513,800 $ 514,017 Actual Return on Plan Assets 87,402 77,401 42,652 44,448 30,006 20,657 Employer Contributions 24,621 29,215 32,980 3,080 3,064 2,896 Plan Participants’ Contributions — — — 3,058 2,930 2,894 Benefits Paid (63,676) (62,673) (61,845) (26,828) (25,673) (26,664) Fair Value of Assets at End of Period $ 1,016,796 $ 968,449 $ 924,506 $ 547,885 $ 524,127 $ 513,800 Net Amount Recognized at End of Period (Funded Status) $ (122,309) $ (129,176) $ (61,184) $ 71,163 $ 55,964 $ 77,814 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (122,309) $ (129,176) $ (61,184) $ (4,872) $ (4,553) $ (4,919) Non-Current Assets — — — 76,035 60,517 82,733 Net Amount Recognized at End of Period $ (122,309) $ (129,176) $ (61,184) $ 71,163 $ 55,964 $ 77,814 Accumulated Benefit Obligation $ 1,096,427 $ 1,053,914 $ 946,763 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 2.66 % 3.15 % 4.30 % 2.71 % 3.17 % 4.31 % Rate of Compensation Increase 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2020 2019 2018 2020 2019 2018 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 9,318 $ 8,482 $ 9,921 $ 1,609 $ 1,519 $ 1,830 Interest Cost 29,930 38,378 33,006 12,913 17,145 14,801 Expected Return on Plan Assets (60,063) (62,368) (61,715) (29,232) (30,157) (31,482) Amortization of Prior Service Cost (Credit) 729 826 938 (429) (429) (429) Recognition of Actuarial Loss(1) 39,384 32,096 37,205 535 5,962 10,558 Net Amortization and Deferral for Regulatory Purposes 5,359 2,493 9,027 25,596 16,481 15,028 Net Periodic Benefit Cost $ 24,657 $ 19,907 $ 28,382 $ 10,992 $ 10,521 $ 10,306 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 3.15 % 4.30 % 3.77 % 3.17 % 4.31 % 3.81 % Effective Rate for Interest on Benefit Obligations 2.81 % 4.03 % 3.23 % 2.84 % 4.05 % 3.29 % Effective Discount Rate for Service Cost 3.31 % 4.40 % 4.00 % 3.39 % 4.43 % 4.10 % Effective Rate for Interest on Service Cost 3.12 % 4.29 % 3.73 % 3.30 % 4.39 % 3.98 % Expected Return on Plan Assets 6.40 % 6.75 % 7.00 % 5.70 % 6.00 % 6.25 % Rate of Compensation Increase 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % (1) Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach. The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above. In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were $8.9 million, $7.6 million and $6.8 million in 2020, 2019 and 2018, 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 $78.7 million, $79.8 million and $70.6 million at September 30, 2020, 2019 and 2018, respectively. The projected benefit obligations for the plans were $98.1 million, $99.5 million and $86.1 million at September 30, 2020, 2019 and 2018, respectively. At September 30, 2020, $14.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $83.6 million is recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2019, $13.2 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $86.3 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2018, $11.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $74.6 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 1.92%, 2.77% and 4.02% as of September 30, 2020, 2019 and 2018, respectively and the weighted average rates of compensation increase for these plans were 8.00%, 8.00% and 7.75% as of September 30, 2020, 2019 and 2018, respectively. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2020, the changes in such amounts during 2020, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2021 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 $ (215,330) $ (28,044) $ (34,065) Prior Service (Cost) Credit (3,641) 2,401 — Net Amount Recognized $ (218,971) $ (25,643) $ (34,065) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2020(1) Increase in Actuarial Loss, excluding amortization(2) $ (38,568) $ (1,180) $ (5,929) Change due to Amortization of Actuarial Loss 39,384 535 5,341 Prior Service (Cost) Credit 729 (429) — Net Change $ 1,545 $ (1,074) $ (588) Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (36,814) $ (849) $ (5,852) Prior Service (Cost) Credit (631) 429 — Net Amount Expected to be Recognized $ (37,445) $ (420) $ (5,852) (1) Amounts presented are shown before recognizing deferred taxes. (2) Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation. In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, 2020, the Company recorded a $3.8 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $3.9 million (pre-tax) decrease to Accumulated Other Comprehensive Income. The effect of the discount rate change for the Retirement Plan in 2020 was to increase the projected benefit obligation of the Retirement Plan by $61.3 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2020 by $3.3 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2020 by $7.9 million. The effect of the discount rate change for the Retirement Plan in 2019 was to increase the projected benefit obligation of the Retirement Plan by $128.4 million. The effect of the discount rate change for the Retirement Plan in 2018 was to decrease the projected benefit obligation of the Retirement Plan by $58.1 million. The Company made cash contributions totaling $24.6 million to the Retirement Plan during the year ended September 30, 2020. The Company expects that the annual contribution to the Retirement Plan in 2021 will be in the range of $15.0 million to $25.0 million. The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: $66.8 million in 2021; $67.2 million in 2022; $67.4 million in 2023; $67.4 million in 2024; $67.1 million in 2025; and $326.8 million in the five years thereafter. The effect of the discount rate change in 2020 was to increase the other post-retirement benefit obligation by $25.4 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2020 by $2.5 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2020 by $6.5 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience. The effect of the discount rate change in 2019 was to increase the other post-retirement benefit obligation by $57.2 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2019 by $3.9 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2019 by $18.9 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 2018 was to decrease the other post-retirement benefit obligation by $25.8 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2018 by $2.4 million. Other actuarial experience increased the other post-retirement benefit obligation in 2018 by $7.3 million primarily attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and 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 2021 $ 28,361 $ (1,950) 2022 $ 28,820 $ (2,064) 2023 $ 29,085 $ (2,172) 2024 $ 29,192 $ (2,273) 2025 $ 29,231 $ (2,356) 2026 through 2030 $ 143,696 $ (12,763) Assumed health care cost trend rates as of September 30 were: 2020 2019 2018 Rate of Medical Cost Increase for Pre Age 65 Participants 5.42 % (1) 5.50 % (1) 5.59 % (1) Rate of Medical Cost Increase for Post Age 65 Participants 4.75 % (1) 4.75 % (1) 4.75 % (1) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 6.80 % (1) 7.35 % (1) 7.89 % (1) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 4.75 % (1) 4.75 % (1) 4.75 % (1) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 6.20 % (1) 6.84 % (1) 7.18 % (1) (1) It was assumed that this rate would gradually decline to 4.5% by 2039. The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2020 would increase by $61.7 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2020 by $2.5 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2020 would decrease by $51.5 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2020 by $1.8 million. The Company made cash contributions totaling $2.8 million to its VEBA trusts during the year ended September 30, 2020. In addition, the Company made direct payments of $0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2020. The Company expects that the annual contribution to its VEBA trusts in 2021 will be in the range of $2.5 million to $3.0 million. 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, 2020 and 2019, 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, 2020 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 188,939 $ 118,124 $ — $ — $ 70,815 International Equities(2) 94,603 — — — 94,603 Global Equities(3) 77,736 — — — 77,736 Domestic Fixed Income(4) 512,693 2,000 457,381 — 53,312 International Fixed Income(5) 20,201 — 20,201 — — Global Fixed Income(6) 79,595 — — — 79,595 Real Estate 106,167 — — 471 105,696 Cash Held in Collective Trust Funds 18,023 — — — 18,023 Total Retirement Plan Investments 1,097,957 120,124 477,582 471 499,780 401(h) Investments (80,511) (8,809) (35,021) (35) (36,646) Total Retirement Plan Investments (excluding 401(h) Investments) $ 1,017,446 $ 111,315 $ 442,561 $ 436 $ 463,134 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (650) Total Retirement Plan Assets $ 1,016,796 At September 30, 2019 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 175,812 $ 114,324 $ — $ — $ 61,488 International Equities(2) 81,631 — — — 81,631 Global Equities(3) 70,095 — — — 70,095 Domestic Fixed Income(4) 493,839 1,784 439,255 — 52,800 International Fixed Income(5) 17,744 — 17,744 — — Global Fixed Income(6) 75,329 — — — 75,329 Real Estate 107,764 — — 3,154 104,610 Cash Held in Collective Trust Funds 18,310 — — — 18,310 Total Retirement Plan Investments 1,040,524 116,108 456,999 3,154 464,263 401(h) Investments (73,688) (8,205) (32,295) (223) (32,965) Total Retirement Plan Investments (excluding 401(h) Investments) $ 966,836 $ 107,903 $ 424,704 $ 2,931 $ 431,298 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash 1,613 Total Retirement Plan Assets $ 968,449 (1) Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. (2) International Equities are comprised of collective trust funds. (3) Global Equities are comprised of collective trust funds. (4) Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. (5) International Fixed Income securities are comprised mostly of corporate/government bonds. (6) Global Fixed Income securities are comprised of a collective trust fund. (7) Reflects the authoritative guidance related to investments measured at net asset value (NAV). At September 30, 2020 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 153,923 $ — $ — $ — $ 153,923 Exchange Traded Funds — Fixed Income 301,290 301,290 — — — Cash Held in Collective Trust Funds 13,841 — — — 13,841 Total VEBA Trust Investments 469,054 301,290 — — 167,764 401(h) Investments 80,511 8,809 35,021 35 36,646 Total Investments (including 401(h) Investments) $ 549,565 $ 310,099 $ 35,021 $ 35 $ 204,410 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (1,680) Total Other Post-Retirement Benefit Assets $ 547,885 At September 30, 2019 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 167,966 $ — $ — $ — $ 167,966 Exchange Traded Funds — Fixed Income 275,296 275,296 — — — Cash Held in Collective Trust Funds 8,229 — — — 8,229 Total VEBA Trust Investments 451,491 275,296 — — 176,195 401(h) Investments 73,688 8,205 32,295 223 32,965 Total Investments (including 401(h) Investments) $ 525,179 $ 283,501 $ 32,295 $ 223 $ 209,160 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (1,052) Total Other Post-Retirement Benefit Assets $ 524,127 (1) Reflects the authoritative guidance related to investments measured at net asset value (NAV). The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date. The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3). For the years ended September 30, 2020 and September 30, 2019, there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3. Retirement Plan Level 3 Assets Real Excluding Total Balance at September 30, 2018 $ 3,194 $ (218) $ 2,976 Unrealized Gains/(Losses) (37) (5) (42) Sales (3) — (3) Balance at September 30, 2019 3,154 (223) 2,931 Unrealized Gains/(Losses) (2,683) 188 (2,495) Sales — — — Balance at September 30, 2020 $ 471 $ (35) $ 436 Other Post-Retirement Benefit Level 3 Assets 401(h) Balance at September 30, 2018 $ 218 Unrealized Gains/(Losses) 5 Sales — Balance at September 30, 2019 223 Unrealized Gains/(Losses) (188) Sales — Balance at September 30, 2020 $ 35 The Company’s assumption regarding the expected long-term rate of return on plan assets is 6.00% (Retirement Plan) and 5.40% (other post-retirement benefits), effective for fiscal 2021. 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). The target allocation for the Retirement Plan and the VEBA trusts (including 401(h) accounts) is 30-50% equity securities, 50-70% fixed income securities (including return-seeking investments) and 0-15% other (including return-seeking investments). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, 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. Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis. The Company determines the service and interest cost components of net periodic benefit cost using the spot rate approach, which uses individual spot rates along the yield curve that correspond to the timing of each benefit payment in order to determine the discount rate. The individual spot rates along the yield curve are determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Sep. 30, 2020
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, 2020, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $6.4 million, which includes a $3.4 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2020. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 2 years and the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company. Northern Access Project On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Appeals, the FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. 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: $181.9 million in 2021, $111.3 million in 2022, $120.9 million in 2023, $129.3 million in 2024, $146.3 million in 2025 and $1,128.2 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, 2020, the future contractual commitments related to the system modernization and expansion projects are $98.3 million in 2021, $6.4 million in 2022, $3.4 million in 2023, $3.3 million in 2024, $3.3 million in 2025 and $10.3 million thereafter. The Company, in its Exploration and Production segment, has entered into contractual obligations to support its development activities and operations in Pennsylvania and California, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing, production equipment, contracts for drilling rig services and fuel purchases for steam generation. The future contractual commitments are $109.3 million in 2021, $15.2 million in 2022 and $0.7 million in 2023. There are no contractual commitments extending beyond 2023. The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Business Segment Information

Business Segment Information	12 Months Ended
	Sep. 30, 2020
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 and oil reserves in the Appalachian region of the United States and in California. The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers, exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for natural gas marketers and exploration and production companies (including Seneca) from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points with access to additional markets in the northeastern United States and Canada. The Gathering segment is comprised of Midstream Company’s operations. Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region and currently provides gathering services 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, 2020 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 607,453 $ 205,998 $ 72 $ 642,855 $ 1,456,378 $ 89,435 $ 478 $ 1,546,291 Intersegment Revenues $ — $ 103,606 $ 142,821 $ 9,443 $ 255,870 $ 836 $ (256,706) $ — Interest Income $ 698 $ 1,475 $ 545 $ 2,262 $ 4,980 $ 860 $ (833) $ 5,007 Interest Expense $ 58,098 $ 32,731 $ 10,877 $ 22,150 $ 123,856 $ 66 $ (6,845) $ 117,077 Depreciation, Depletion and Amortization $ 172,124 $ 53,951 $ 22,440 $ 55,248 $ 303,763 $ 1,716 $ 679 $ 306,158 Income Tax Expense (Benefit) $ (41,472) $ 28,613 $ 18,191 $ 13,274 $ 18,606 $ 210 $ (77) $ 18,739 Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ 449,438 $ — $ — $ — $ 449,438 $ — $ — $ 449,438 Segment Profit: Net Income (Loss) $ (326,904) $ 78,860 $ 68,631 $ 57,366 $ (122,047) $ (269) $ (1,456) $ (123,772) Expenditures for Additions to Long-Lived Assets $ 670,455 $ 166,652 $ 297,806 $ 94,273 $ 1,229,186 $ 39 $ (608) $ 1,228,617 At September 30, 2020 (Thousands) Segment Assets $ 1,979,028 $ 2,204,971 $ 945,199 $ 2,067,852 $ 7,197,050 $ 113,571 $ (345,686) $ 6,964,935 Year Ended September 30, 2019 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 632,740 $ 195,808 $ 11 $ 715,813 $ 1,544,372 $ 148,582 $ 378 $ 1,693,332 Intersegment Revenues $ — $ 92,475 $ 127,064 $ 11,629 $ 231,168 $ 1,127 $ (232,295) $ — Interest Income $ 1,107 $ 2,982 $ 546 $ 1,809 $ 6,444 $ 1,291 $ (1,670) $ 6,065 Interest Expense $ 54,777 $ 29,142 $ 9,406 $ 23,443 $ 116,768 $ 21 $ (10,033) $ 106,756 Depreciation, Depletion and Amortization $ 154,784 $ 44,947 $ 20,038 $ 53,832 $ 273,601 $ 1,291 $ 768 $ 275,660 Income Tax Expense (Benefit) $ 32,978 $ 23,238 $ 20,895 $ 13,967 $ 91,078 $ (955) $ (4,902) $ 85,221 Segment Profit: Net Income (Loss) $ 111,807 $ 74,011 $ 58,413 $ 60,871 $ 305,102 $ (1,811) $ 999 $ 304,290 Expenditures for Additions to Long-Lived Assets $ 491,889 $ 143,005 $ 49,650 $ 95,847 $ 780,391 $ 128 $ 727 $ 781,246 At September 30, 2019 (Thousands) Segment Assets $ 1,972,776 $ 1,893,514 $ 547,995 $ 1,991,338 $ 6,405,623 $ 122,241 $ (65,707) $ 6,462,157 Year Ended September 30, 2018 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 564,547 $ 210,345 $ 41 $ 674,726 $ 1,449,659 $ 142,349 $ 660 $ 1,592,668 Intersegment Revenues $ — $ 89,981 $ 107,856 $ 12,800 $ 210,637 $ 826 $ (211,463) $ — Interest Income $ 1,479 $ 2,748 $ 1,106 $ 1,591 $ 6,924 $ 1,073 $ (1,231) $ 6,766 Interest Expense $ 54,288 $ 31,383 $ 9,560 $ 26,753 $ 121,984 $ 22 $ (7,484) $ 114,522 Depreciation, Depletion and Amortization $ 124,274 $ 43,463 $ 17,313 $ 53,253 $ 238,303 $ 1,902 $ 756 $ 240,961 Income Tax Expense (Benefit) $ (41,962) $ 17,806 $ (17,677) $ 15,258 $ (26,575) $ 2,125 $ 16,956 $ (7,494) Segment Profit: Net Income (Loss) $ 180,632 $ 97,246 $ 83,519 $ 51,217 $ 412,614 $ 261 $ (21,354) $ 391,521 Expenditures for Additions to Long-Lived Assets $ 380,677 $ 92,832 $ 61,728 $ 85,648 $ 620,885 $ 41 $ (20,324) $ 600,602 At September 30, 2018 (Thousands) Segment Assets $ 1,568,563 $ 1,848,180 $ 533,608 $ 1,921,971 $ 5,872,322 $ 129,080 $ 35,084 $ 6,036,486 (1) All Revenue from External Customers originated in the United States. Geographic Information At September 30 2020 2019 2018 (Thousands) Long-Lived Assets: United States $ 6,597,313 $ 6,099,534 $ 5,491,895

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Sep. 30, 2020
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data	Quarterly Financial Data (unaudited) In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis. Quarter Ended Operating Operating Net Income (Loss) Earnings (Loss) per Basic Diluted (Thousands, except per common share amounts) 2020 9/30/2020 $ 287,989 $ (173,979) $ (145,545) (1) $ (1.60) $ (1.60) 6/30/2020 $ 323,019 $ 80,397 $ 41,250 (2) $ 0.47 $ 0.47 3/31/2020 $ 491,095 $ (24,580) $ (106,068) (3) $ (1.23) $ (1.23) 12/31/2019 $ 444,188 $ 148,020 $ 86,591 $ 1.00 $ 1.00 2019 9/30/2019 $ 293,341 $ 83,940 $ 47,282 $ 0.55 $ 0.54 6/30/2019 $ 357,200 $ 112,827 $ 63,753 $ 0.74 $ 0.73 3/31/2019 $ 552,544 $ 153,359 $ 90,595 $ 1.05 $ 1.04 12/31/2018 $ 490,247 $ 161,683 $ 102,660 (4) $ 1.19 $ 1.18 (1) Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (2) Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (3) Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.

Supplementary Information For O

Supplementary Information For Oil And Gas Producing Activities	12 Months Ended
	Sep. 30, 2020
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)	Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities) The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve month period prior to the end of the reporting period. The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars. Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 2020 2019 (Thousands) Proved Properties(1) $ 6,238,830 $ 5,623,623 Unproved Properties 148,075 53,498 6,386,905 5,677,121 Less — Accumulated Depreciation, Depletion and Amortization 4,628,765 4,012,568 $ 1,758,140 $ 1,664,553 (1) Includes asset retirement costs of $132.6 million and $70.5 million at September 30, 2020 and 2019, 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 2025. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2023. Following is a summary of costs excluded from amortization at September 30, 2020: Total as of Year Costs Incurred 2020 2019 2018 Prior (Thousands) Acquisition Costs $ 64,218 $ 39,953 $ — $ — $ 24,265 Development Costs 75,138 54,761 17,326 403 2,648 Exploration Costs 7,606 — — — 7,606 Capitalized Interest 1,113 969 41 — 103 $ 148,075 $ 95,683 $ 17,367 $ 403 $ 34,622 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2020 2019 2018 (Thousands) United States Property Acquisition Costs: Proved $ 245,976 $ 3,136 $ 1,544 Unproved 42,922 3,679 4,286 Exploration Costs 3,891 2,060 29,365 Development Costs(1) 355,742 468,498 332,496 Asset Retirement Costs 62,080 26,192 (10,107) $ 710,611 $ 503,565 $ 357,584 (1) Amounts for 2020, 2019 and 2018 include capitalized interest of $1.0 million, $0.2 million and $0.3 million, respectively. For the years ended September 30, 2020, 2019 and 2018, the Company spent $219.9 million, $246.0 million and $182.3 million, respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2020 2019 2018 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of 1,921, 2,532 and 2,134, respectively)(1) $ 402,447 $ 481,048 $ 390,642 Oil, Condensate and Other Liquids 107,844 149,078 168,254 Total Operating Revenues(2) 510,291 630,126 558,896 Production/Lifting Costs 203,670 186,626 162,721 Franchise/Ad Valorem Taxes 15,582 17,673 14,355 Purchased Emission Allowance Expense 2,930 2,527 1,883 Accretion Expense 5,237 3,723 4,266 Depreciation, Depletion and Amortization ($0.69, $0.71 and $0.67 per Mcfe of production, respectively) 166,759 149,881 119,946 Impairment of Oil and Gas Producing Properties 449,438 — — Income Tax Expense (92,820) 64,652 72,723 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ (240,505) $ 205,044 $ 183,002 (1) There were no revenues from sales to affiliates for all years presented. (2) Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments. Reserve Quantity Information The Company's proved oil and gas reserve estimates are prepared by the Company's reservoir engineers who meet the qualifications of Reserve Estimator per the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance. The Company's 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 30 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company's reserve estimation process since 2003. He is a member of the Society of Petroleum Evaluation Engineers and a Registered Professional Engineer in the State of Texas. 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 and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since 2011 and with over 4 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, 2020 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, 2017 1,926,614 46,506 1,973,120 Extensions and Discoveries 521,694 (1) — 521,694 Revisions of Previous Estimates 90,113 3,322 93,435 Production (160,499) (2) (2,407) (162,906) Sale of Minerals in Place (57,420) (10,581) (68,001) September 30, 2018 2,320,502 36,840 2,357,342 Extensions and Discoveries 686,549 (1) — 686,549 Revisions of Previous Estimates 104,741 (1,233) 103,508 Production (195,906) (2) (1,974) (197,880) September 30, 2019 2,915,886 33,633 2,949,519 Extensions and Discoveries 7,246 (1) — 7,246 Revisions of Previous Estimates (85,647) (2,772) (88,419) Production (225,513) (2) (1,889) (227,402) Purchases of Minerals in Place 684,141 — 684,141 September 30, 2020 3,296,113 28,972 3,325,085 Proved Developed Reserves: September 30, 2017 1,316,596 46,506 1,363,102 September 30, 2018 1,569,692 36,840 1,606,532 September 30, 2019 1,901,162 33,633 1,934,795 September 30, 2020 2,744,851 28,972 2,773,823 Proved Undeveloped Reserves: September 30, 2017 610,018 — 610,018 September 30, 2018 750,810 — 750,810 September 30, 2019 1,014,724 — 1,014,724 September 30, 2020 551,262 — 551,262 (1) Extensions and discoveries include 274 Bcf (during 2018), 175 Bcf (during 2019) and 7 Bcf (during 2020), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 248 Bcf (during 2018), 512 Bcf (during 2019) and 0 Bcf (during 2020), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 150,196 MMcf (during 2018), 163,015 MMcf (during 2019) and 169,453 MMcf (during 2020), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018), 32,095 MMcf (during 2019) and 55,392 MMcf (during 2020), from Utica Shale fields. Oil Mbbl U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: September 30, 2017 28 30,179 30,207 Extensions and Discoveries — 2,301 2,301 Revisions of Previous Estimates (10) 2,487 2,477 Production (4) (2,531) (2,535) Sales of Minerals in Place — (4,787) (4,787) September 30, 2018 14 27,649 27,663 Extensions and Discoveries — 787 787 Revisions of Previous Estimates 2 (1,256) (1,254) Production (3) (2,320) (2,323) September 30, 2019 13 24,860 24,873 Extensions and Discoveries — 288 288 Revisions of Previous Estimates 2 (715) (713) Production (3) (2,345) (2,348) September 30, 2020 12 22,088 22,100 Proved Developed Reserves: September 30, 2017 28 29,771 29,799 September 30, 2018 14 26,689 26,703 September 30, 2019 13 24,246 24,259 September 30, 2020 12 22,088 22,100 Proved Undeveloped Reserves: September 30, 2017 — 408 408 September 30, 2018 — 960 960 September 30, 2019 — 614 614 September 30, 2020 — — — The Company’s proved undeveloped (PUD) reserves decreased from 1,018 Bcfe at September 30, 2019 to 551 Bcfe at September 30, 2020. PUD reserves in the Marcellus Shale decreased from 383 Bcfe at September 30, 2019 to 287 Bcfe at September 30, 2020. PUD reserves in the Utica Shale decreased from 632 Bcfe at September 30, 2019 to 265 Bcfe at September 30, 2020. The Company’s total PUD reserves were 16% of total proved reserves at September 30, 2020, down from 33% of total proved reserves at September 30, 2019. The Company’s PUD reserves increased from 757 Bcfe at September 30, 2018 to 1,018 Bcfe at September 30, 2019. PUD reserves in the Marcellus Shale decreased slightly from 394 Bcfe at September 30, 2018 to 383 Bcfe at September 30, 2019. PUD reserves in the Utica Shale increased from 357 Bcfe at September 30, 2018 to 632 Bcfe at September 30, 2019. The Company’s total PUD reserves were 33% of total proved reserves at September 30, 2019, up from 30% of total proved reserves at September 30, 2018. The decrease in PUD reserves in 2020 of 467 Bcfe is a result of 363 Bcfe in PUD conversions to developed reserves (146 Bcfe from the Marcellus Shale, 214 Bcfe from the Utica Shale and 3 Bcfe from the West Coast region), and 179 Bcfe in PUD reserves removed for seventeen PUD locations, all in the Western Development Area, due to development timing no longer scheduled to meet the five year requirement for proved reserves. Two of these wells removed were in the Marcellus Shale (14 Bcfe) and fifteen were in the Utica Shale (165 Bcfe). These decreases were offset by 7 Bcfe in new PUD reserve additions, 20 Bcfe in upward revisions to remaining PUD reserves and 48 Bcfe in revisions for five PUD locations added back in 2020 (after removing one in 2016 and four in 2017 due to scheduling delays beyond the five year requirement). The increase in PUD reserves in 2019 of 261 Bcfe is a result of 575 Bcfe in new PUD reserve additions (175 Bcfe from the Marcellus Shale, 398 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 38 Bcfe in upward revisions to remaining PUD reserves, partially offset by 297 Bcfe in PUD conversions to developed reserves (186 Bcfe from the Marcellus Shale, 106 Bcfe from the Utica Shale and 5 Bcfe from the West Coast region), and 55 Bcfe in PUD reserves removed for six PUD locations, two of these wells removed are in the Marcellus (13 Bcfe) and four are in the Utica (42 Bcfe). The Company invested $220 million during the year ended September 30, 2020 to convert 363 Bcfe (393 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 36% of the net PUD reserves recorded at September 30, 2019. The 30 Bcfe in upward revisions to PUD reserves converted to developed reserves in 2020 were primarily a result of longer completed laterals. In the Appalachian region, 35 of 99 PUD locations were developed and in the West Coast region, all 14 PUD locations were developed. The Company invested $246 million during the year ended September 30, 2019 to convert 297 Bcfe (380 Bcfe after positive revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 39% of the net PUD reserves recorded at September 30, 2018. In fiscal 2019, the Company developed 56 (or 50%) of its well locations with net PUD reserves recorded at September 30, 2018. The majority of these wells were in the Appalachian region. The 83 Bcfe in upward revisions to PUD reserves converted to developed reserves in 2019 were a result of longer completed laterals and improved well performance at PUD locations that were recorded at September 30, 2019. In 2021, the Company estimates that it will invest approximately $134 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, and over the last five years, the Company developed 25% of its beginning year PUD reserves in fiscal 2016, 27% of its beginning year PUD reserves in fiscal 2017, 51% of its beginning year PUD reserves in fiscal 2018, 39% of its beginning year PUD reserves in fiscal 2019 and 36% of its beginning year PUD reserves in fiscal 2020. At September 30, 2020, the Company does not have any proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions. The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities. Year Ended September 30 2020 2019 2018 (Thousands) United States Future Cash Inflows $ 6,493,362 $ 8,738,182 $ 7,822,855 Less: Future Production Costs 3,149,857 2,989,518 2,606,411 Future Development Costs 501,678 797,640 559,707 Future Income Tax Expense at Applicable Statutory Rate 454,553 1,159,882 1,125,910 Future Net Cash Flows 2,387,274 3,791,142 3,530,827 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,164,804 2,054,823 1,810,522 Standardized Measure of Discounted Future Net Cash Flows $ 1,222,470 $ 1,736,319 $ 1,720,305 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2020 2019 2018 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,736,319 $ 1,720,305 $ 1,113,046 Sales, Net of Production Costs (290,975) (425,773) (381,775) Net Changes in Prices, Net of Production Costs (1,109,101) (164,428) 541,021 Extensions and Discoveries 4,236 202,683 212,494 Changes in Estimated Future Development Costs 99,884 (69,254) (43,771) Purchases of Minerals in Place 170,363 — — Sales of Minerals in Place — — (100,816) Previously Estimated Development Costs Incurred 219,938 245,964 182,348 Net Change in Income Taxes at Applicable Statutory Rate 248,182 21,370 55,558 Revisions of Previous Quantity Estimates (28,337) 53,777 61,363 Accretion of Discount and Other 171,961 151,675 80,837 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,222,470 $ 1,736,319 $ 1,720,305

Valuation And Qualifying Accoun

Valuation And Qualifying Accounts	12 Months Ended
	Sep. 30, 2020
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Valuation And Qualifying Accounts	Schedule II — Valuation and Qualifying Accounts Description Balance at Beginning of Period Additions Charged to Costs and Expenses Additions Charged to Other Accounts(1) Deductions (2) Balance at End of Period Year Ended September 30, 2020 Allowance for Uncollectible Accounts $ 25,788 $ 12,339 $ 1,353 $ 16,670 $ 22,810 Valuation Allowance for Deferred Tax Assets (3) $ — $ 63,205 $ — $ — $ 63,205 Year Ended September 30, 2019 Allowance for Uncollectible Accounts $ 24,537 $ 10,184 $ 1,707 $ 10,640 $ 25,788 Valuation Allowance for Deferred Tax Assets (3) $ 5,000 $ — $ — $ 5,000 $ — Year Ended September 30, 2018 Allowance for Uncollectible Accounts $ 22,526 $ 10,905 $ 1,967 $ 10,861 $ 24,537 Valuation Allowance for Deferred Tax Assets (3) $ — $ 5,000 $ — $ — $ 5,000 (1) Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement. (2) Amounts represent net accounts receivable written-off, as well as a reversal of a valuation allowance, as discussed in footnote (3) below.

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Sep. 30, 2020
Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation	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	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 is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic environment. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. In response to the COVID-19 pandemic, the Company has suspended collection and termination activity for non-payments in its Utility service territories. To date, despite the economic conditions that have arisen as a result of the COVID-19 pandemic, the Company has not experienced any meaningful change in the rate at which its customers pay their bills. To the extent the economic impacts of the COVID-19 pandemic continue into the winter heating season, the Company is anticipating that customer non-payments may increase as seasonally higher natural gas prices and usage will lead to higher costs for customers.
Regulatory Mechanisms	Regulatory Mechanisms The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year. Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note F — Regulatory Matters for further discussion. The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues. The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending March 31st, and applied to customer bills annually, beginning July 1st. In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.
Asset Acquisition and Business Combination Accounting	Asset Acquisition and Business Combination Accounting In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business. If the initial screening test is not met, the Company evaluates whether the set is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance. When the Company acquires assets and liabilities deemed to be an asset acquisition, the fair value of the purchase consideration, including the transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to the individual assets and liabilities assumed based on their relative fair values. Transaction costs associated with asset acquisitions are capitalized as part of the costs of the group of assets acquired.
Variable Interest Entity Accounting	Variable Interest Entity AccountingIn accordance with authoritative guidance issued by the FASB concerning a variable interest entity (VIE), the Company will evaluate a VIE to determine whether it is the primary beneficiary and therefore is considered to have a controlling financial interest. If the Company has the power to direct the activities of a VIE and the obligation to absorb significant losses of that entity or the right to receive significant benefits from that entity, the Company is considered to be the primary beneficiary and therefore consolidates that VIE into the Company’s consolidated financial statements.
Property, Plant And Equipment	Property, Plant and Equipment In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.8 billion and $1.7 billion at September 30, 2020 and 2019, respectively. For further discussion of capitalized costs, refer to Note O — Supplementary Information for Oil and Gas Producing Activities. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The book value of the oil and gas properties exceeded the ceiling at September 30, 2020 as well as at June 30, 2020 and March 31, 2020. As such, the Company recognized pre-tax impairment charges of $449.4 million for the year ended September 30, 2020. Deferred income tax benefits of $123.1 million related to the impairment charges were also recognized for the year ended September 30, 2020. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2020, 2019 and 2018, estimated future net cash flows were increased by $180.0 million, decreased by $17.7 million and decreased by $25.1 million, respectively. The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service. Despite the economic conditions arising from the COVID-19 pandemic, there were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2020. Management will continue to monitor the situation on a quarterly basis. Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.
Depreciation, Depletion And Amortization	Depreciation, Depletion and AmortizationFor oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. Depreciation, depletion and amortization expense for oil and gas properties was $166.8 million, $149.9 million and $119.9 million for the years ended September 30, 2020, 2019 and 2018, respectively. In the All Other category, for timber properties, depletion, determined on a property by property basis, has historically been charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. However, as discussed below in Note B — Asset Acquisitions and Divestitures, most of the Company's timber properties have been reclassified to Assets Held for Sale. The impact of that reclassification is reflected in the tables below. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment: As of September 30 2020 2019 (Thousands) Exploration and Production $ 6,384,086 $ 5,747,731 Pipeline and Storage 2,418,265 2,191,166 Gathering 849,204 577,021 Utility 2,234,433 2,159,841 All Other and Corporate 20,372 112,857 $ 11,906,360 $ 10,788,616 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2020 2019 2018 Exploration and Production, per Mcfe(1) $ 0.71 $ 0.73 $ 0.70 Pipeline and Storage 2.4 % 2.2 % 2.2 % Gathering 3.2 % 3.6 % 3.4 % Utility 2.7 % 2.7 % 2.8 % All Other and Corporate 3.6 % 1.8 % 2.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note O — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.69, $0.71 and $0.67 per Mcfe of production in 2020, 2019 and 2018, respectively.
Goodwill	Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2020 and 2019 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, 2020, 2019 and 2018, 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 gas and oil 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, crude oil price swap agreements, 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 or purchased gas expense on the Consolidated Statements of Income. Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges.
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) The components of Accumulated Other Comprehensive Income (Loss) and changes for the years ended September 30, 2020 and 2019, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Year Ended September 30, 2020 Balance at October 1, 2019 $ 34,675 $ — $ (86,830) $ (52,155) Other Comprehensive Gains and Losses Before Reclassifications 7,284 — (14,857) (7,573) Amounts Reclassified From Other Comprehensive Loss (67,774) — 11,795 (55,979) Cumulative Effect of Adoption of Authoritative Guidance for Hedging 950 — — 950 Balance at September 30, 2020 $ (24,865) $ — $ (89,892) $ (114,757) Year Ended September 30, 2019 Balance at October 1, 2018 $ (28,611) $ 7,437 $ (46,576) $ (67,750) Other Comprehensive Gains and Losses Before Reclassifications 58,682 — (33,616) 25,066 Amounts Reclassified From Other Comprehensive Income 2,738 — 5,634 8,372 Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities — (7,437) — (7,437) Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act 1,866 — (12,272) (10,406) Balance at September 30, 2019 $ 34,675 $ — $ (86,830) $ (52,155) The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $0.9 million and $1.0 million at September 30, 2020 and 2019, respectively. The total amount for accumulated losses was $89.0 million and $85.8 million at September 30, 2020 and 2019, respectively. In August 2017, the FASB issued authoritative guidance which changes the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities and to simplify the application of hedge accounting. The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million and increased accumulated other comprehensive income by the same amount. In February 2018, the FASB issued authoritative guidance that allows an entity to elect a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the 2017 Tax Reform Act and requires certain disclosures about stranded tax effects. The Company adopted this authoritative guidance effective January 1, 2019 and recorded a cumulative effect adjustment related to deferred income taxes associated with hedging activities and pension and post-retirement benefit obligations during the quarter ended March 31, 2019 to increase retained earnings by $10.4 million and decrease accumulated other comprehensive income by the same amount. In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through accumulated other comprehensive income. The Company adopted this authoritative guidance effective October 1, 2018 and, as called for by the modified retrospective method of adoption, recorded a cumulative effect adjustment during the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount.
Reclassifications Out Of Accumulated Other Comprehensive Income (Loss)	Reclassifications Out of Accumulated Other Comprehensive Income (Loss) The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the years ended September 30, 2020 and 2019 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 Income (Loss) for the Affected Line Item in the Statement Where Net Income is Presented 2020 2019 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $93,691 ($3,460) Operating Revenues Commodity Contracts 661 (1,182) Purchased Gas Foreign Currency Contracts (1,057) (822) Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (237) (264) (1) Net Actuarial Loss (15,124) (7,068) (1) 77,934 (12,796) Total Before Income Tax (21,955) 4,424 Income Tax Expense $55,979 ($8,372) Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.
Gas Stored Underground	Gas Stored Underground In the Utility segment, gas stored underground in the amount of $33.2 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 2020, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $6.6 million at September 30, 2020.
Materials, Supplies and Emission Allowances	Materials, Supplies and Emission Allowances The components of the Company's materials, supplies and emission allowances are as follows: Year Ended September 30 2020 2019 (Thousands) Materials and Supplies — at average cost $ 33,859 $ 29,819 Emission Allowances 18,018 10,898 $ 51,877 $ 40,717
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, 2020, the remaining weighted average amortization period for such costs was approximately 6 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	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 2020 2019 2018 2017 Cash and Temporary Cash Investments $ 20,541 $ 20,428 $ 229,606 $ 555,530 Hedging Collateral Deposits — 6,832 3,441 1,741 Cash, Cash Equivalents, and Restricted Cash $ 20,541 $ 27,260 $ 233,047 $ 557,271 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 hedging positions. 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	Other Current Assets The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2020 2019 (Thousands) Prepayments $ 12,851 $ 12,728 Prepaid Property and Other Taxes 14,269 14,361 Federal Income Taxes Receivable — 42,388 State Income Taxes Receivable 3,828 8,579 Fair Values of Firm Commitments — 7,538 Regulatory Assets 16,609 11,460 $ 47,557 $ 97,054
Other Accruals And Current Liabilities	Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2020 2019 (Thousands) Accrued Capital Expenditures $ 33,344 $ 33,713 Regulatory Liabilities 44,890 50,332 Federal Income Taxes Payable 163 — Liability for Royalty and Working Interests 15,665 18,057 Non-Qualified Benefit Plan Liability 14,460 13,194 Other 31,654 24,304 $ 140,176 $ 139,600
Customer Advances	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, 2020 and 2019, customers in the balanced billing programs had advanced excess funds of $15.3 million and $13.0 million, respectively.
Customer Security Deposits	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, 2020 and 2019, the Company had received customer security deposits amounting to $17.2 million and $16.2 million, respectively.
Earnings Per Common Share	Earnings Per Common Share Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares. As the Company recognized a net loss for the year ended September 30, 2020, the aforementioned securities, amounting to
Stock-Based Compensation	Stock-Based Compensation The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. SARs and stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no SAR or stock option is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs and stock options. For all Company stock awards, forfeitures are recognized as they occur. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant. Restricted stock units also 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 accounting for restricted stock units is the same as the accounting for restricted stock awards, except that 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, 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.

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2020
Accounting Policies [Abstract]
Schedule Of Depreciable Plant By Segment	The following is a summary of depreciable plant by segment: As of September 30 2020 2019 (Thousands) Exploration and Production $ 6,384,086 $ 5,747,731 Pipeline and Storage 2,418,265 2,191,166 Gathering 849,204 577,021 Utility 2,234,433 2,159,841 All Other and Corporate 20,372 112,857 $ 11,906,360 $ 10,788,616
Average Depreciation Depletion And Amortization Rates	Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2020 2019 2018 Exploration and Production, per Mcfe(1) $ 0.71 $ 0.73 $ 0.70 Pipeline and Storage 2.4 % 2.2 % 2.2 % Gathering 3.2 % 3.6 % 3.4 % Utility 2.7 % 2.7 % 2.8 % All Other and Corporate 3.6 % 1.8 % 2.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note O — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.69, $0.71 and $0.67 per Mcfe of production in 2020, 2019 and 2018, respectively.
Components Of Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) and changes for the years ended September 30, 2020 and 2019, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Year Ended September 30, 2020 Balance at October 1, 2019 $ 34,675 $ — $ (86,830) $ (52,155) Other Comprehensive Gains and Losses Before Reclassifications 7,284 — (14,857) (7,573) Amounts Reclassified From Other Comprehensive Loss (67,774) — 11,795 (55,979) Cumulative Effect of Adoption of Authoritative Guidance for Hedging 950 — — 950 Balance at September 30, 2020 $ (24,865) $ — $ (89,892) $ (114,757) Year Ended September 30, 2019 Balance at October 1, 2018 $ (28,611) $ 7,437 $ (46,576) $ (67,750) Other Comprehensive Gains and Losses Before Reclassifications 58,682 — (33,616) 25,066 Amounts Reclassified From Other Comprehensive Income 2,738 — 5,634 8,372 Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities — (7,437) — (7,437) Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act 1,866 — (12,272) (10,406) Balance at September 30, 2019 $ 34,675 $ — $ (86,830) $ (52,155)
Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Income (Loss)	The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the years ended September 30, 2020 and 2019 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 Income (Loss) for the Affected Line Item in the Statement Where Net Income is Presented 2020 2019 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $93,691 ($3,460) Operating Revenues Commodity Contracts 661 (1,182) Purchased Gas Foreign Currency Contracts (1,057) (822) Operating Revenues Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (237) (264) (1) Net Actuarial Loss (15,124) (7,068) (1) 77,934 (12,796) Total Before Income Tax (21,955) 4,424 Income Tax Expense $55,979 ($8,372) Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.
Schedule of Materials, Supplies and Emission Allowances	The components of the Company's materials, supplies and emission allowances are as follows: Year Ended September 30 2020 2019 (Thousands) Materials and Supplies — at average cost $ 33,859 $ 29,819 Emission Allowances 18,018 10,898 $ 51,877 $ 40,717
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 2020 2019 2018 2017 Cash and Temporary Cash Investments $ 20,541 $ 20,428 $ 229,606 $ 555,530 Hedging Collateral Deposits — 6,832 3,441 1,741 Cash, Cash Equivalents, and Restricted Cash $ 20,541 $ 27,260 $ 233,047 $ 557,271
Schedule Of Other Current Assets	The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2020 2019 (Thousands) Prepayments $ 12,851 $ 12,728 Prepaid Property and Other Taxes 14,269 14,361 Federal Income Taxes Receivable — 42,388 State Income Taxes Receivable 3,828 8,579 Fair Values of Firm Commitments — 7,538 Regulatory Assets 16,609 11,460 $ 47,557 $ 97,054
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 2020 2019 (Thousands) Accrued Capital Expenditures $ 33,344 $ 33,713 Regulatory Liabilities 44,890 50,332 Federal Income Taxes Payable 163 — Liability for Royalty and Working Interests 15,665 18,057 Non-Qualified Benefit Plan Liability 14,460 13,194 Other 31,654 24,304 $ 140,176 $ 139,600

Asset Acquisitions and Divest_2

Asset Acquisitions and Divestitures (Tables)	12 Months Ended
	Sep. 30, 2020
Business Combinations [Abstract]
Summary of Asset Acquisition	The following is a summary of the asset acquisition (in thousands): Purchase Price $ 503,908 Transaction Costs 2,350 Total Consideration $ 506,258 Allocation of Cost of Asset Acquisition: Exploration and Production Reporting Segment Gathering Reporting Segment Total Property, Plant and Equipment $ 281,648 (1)(2) $ 223,369 (2) $ 505,017 Inventory 1,132 109 1,241 Total Accounting $ 282,780 $ 223,478 $ 506,258 (1) Includes $241,134 in Proved Developed Producing Properties and $277,832 capitalized in the full cost pool.

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Sep. 30, 2020
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, 2020 and 2019, presented by type of service from each reportable segment. Year Ended September 30, 2020 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 402,447 $ — $ — $ — $ 402,447 $ — $ — $ 402,447 Production of Crude Oil 107,844 — — — 107,844 — — 107,844 Natural Gas Processing 2,374 — — — 2,374 — — 2,374 Natural Gas Gathering Service — — 142,893 — 142,893 — (142,821) 72 Natural Gas Transportation Service — 229,391 — 109,214 338,605 — (77,699) 260,906 Natural Gas Storage Service — 79,073 — — 79,073 — (34,579) 44,494 Natural Gas Residential Sales — — — 475,846 475,846 — — 475,846 Natural Gas Commercial Sales — — — 61,239 61,239 — — 61,239 Natural Gas Industrial Sales — — — 3,291 3,291 — — 3,291 Natural Gas Marketing — — — — — 95,727 (835) 94,892 Other 1,097 1,140 — (5,281) (3,044) 5,174 (294) 1,836 Total Revenues from Contracts with Customers 513,762 309,604 142,893 644,309 1,610,568 100,901 (256,228) 1,455,241 Alternative Revenue Programs — — — 7,989 7,989 — — 7,989 Derivative Financial Instruments 93,691 — — — 93,691 (10,630) — 83,061 Total Revenues $ 607,453 $ 309,604 $ 142,893 $ 652,298 $ 1,712,248 $ 90,271 $ (256,228) $ 1,546,291 Year Ended September 30, 2019 Revenues by Type of Service Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Production of Natural Gas $ 481,048 $ — $ — $ — $ 481,048 $ — $ — $ 481,048 Production of Crude Oil 149,078 — — — 149,078 — — 149,078 Natural Gas Processing 3,277 — — — 3,277 — — 3,277 Natural Gas Gathering Service — — 127,064 — 127,064 — (127,064) — Natural Gas Transportation Service — 209,184 — 119,253 328,437 — (70,689) 257,748 Natural Gas Storage Service — 75,484 — — 75,484 — (32,488) 42,996 Natural Gas Residential Sales — — — 539,962 539,962 — — 539,962 Natural Gas Commercial Sales — — — 73,331 73,331 — — 73,331 Natural Gas Industrial Sales — — — 4,830 4,830 — — 4,830 Natural Gas Marketing — — — — — 143,627 (1,127) 142,500 Other 1,609 3,615 11 (8,630) (3,395) 3,424 (549) (520) Total Revenues from Contracts with Customers 635,012 288,283 127,075 728,746 1,779,116 147,051 (231,917) 1,694,250 Alternative Revenue Programs — — — (1,304) (1,304) — — (1,304) Derivative Financial Instruments (2,272) — — — (2,272) 2,658 — 386 Total Revenues $ 632,740 $ 288,283 $ 127,075 $ 727,442 $ 1,775,540 $ 149,709 $ (231,917) $ 1,693,332

Leases (Tables)

Leases (Tables)	12 Months Ended
	Sep. 30, 2020
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, 2020 Operating Lease Expense $ 4,129 Variable Lease Expense(1) 525 Short-Term Lease Expense(2) 918 Sublease Income (297) Total Lease Expense $ 5,275 Short-Term Lease Costs Recorded to Property, Plant and Equipment(3) $ 19,232 (1) Variable lease payments that are not dependent on an index or rate are not included in the lease liability. (2) Short-term lease costs exclude expenses related to leases with a lease term of one month or less.
Balance Sheet Information Related to Operating Leases	The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands): At September 30, 2020 Assets: Deferred Charges $ 19,850 Liabilities: Other Accruals and Current Liabilities $ 4,943 Other Deferred Credits $ 14,777
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, 2020 (in thousands): At September 30, 2020 2021 $ 4,968 2022 3,045 2023 2,507 2024 2,238 2025 2,086 Thereafter 7,631 Total Lease Payments 22,475 Less: Interest (2,755) Total Lease Liability $ 19,720
Schedule of Future Minimum Operating Lease Payments	The future minimum operating lease payments as of September 30, 2019, as reported in the Company's 2019 Form 10-K, under the prior authoritative guidance are as follows (in thousands): At September 30, 2019 2020(1) $ 12,356 2021 2,813 2022 2,264 2023 2,270 2024 2,237 Thereafter 9,717 Total Operating Lease Obligations $ 31,657 (1) The future minimum operating lease payment amount for 2020 includes short-term leases, including drilling rigs, that are not included in the schedule of operating lease liability maturities above under the new authoritative guidance.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Sep. 30, 2020
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 2020 2019 2018 (Thousands) Balance at Beginning of Year $ 127,458 $ 108,235 $ 106,395 Liabilities Incurred 61,246 4,122 5,597 Revisions of Estimates 3,267 16,693 (419) Liabilities Settled (7,268) (7,670) (12,858) Accretion Expense 7,525 6,078 9,520 Balance at End of Year $ 192,228 $ 127,458 $ 108,235

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2020
Regulatory Assets and Liabilities, Other Disclosures [Abstract]
Schedule Of Regulatory Assets And Liabilities	The Company has recorded the following regulatory assets and liabilities: At September 30 2020 2019 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note K) $ 107,010 $ 114,509 Post-Retirement Benefit Costs(2) (Note K) 18,863 18,236 Recoverable Future Taxes (Note G) 118,310 115,197 Environmental Site Remediation Costs(2) (Note L) 10,479 15,317 Asset Retirement Obligations(2) (Note E) 16,245 15,696 Unamortized Debt Expense (Note A) 12,297 14,005 Other(3) 20,118 15,022 Total Regulatory Assets 303,322 307,982 Less: Amounts Included in Other Current Assets (16,609) (11,460) Total Long-Term Regulatory Assets $ 286,713 $ 296,522 At September 30 2020 2019 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 230,079 $ 221,699 Taxes Refundable to Customers (Note G) 357,508 366,503 Post-Retirement Benefit Costs(4) (Note K) 146,474 126,577 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 10,788 4,017 Other(5) 59,989 66,122 Total Regulatory Liabilities 804,838 784,918 Less: Amounts included in Current and Accrued Liabilities (55,678) (54,349) Total Long-Term Regulatory Liabilities $ 749,160 $ 730,569 (1) The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates. (2) Included in Other Regulatory Assets on the Consolidated Balance Sheets. (3) $16,609 and $11,460 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,509 and $3,562 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $44,890 and $50,332 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,099 and $15,790 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2020
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 2020 2019 2018 (Thousands) Current Income Taxes — Federal $ (42,548) $ (41,645) $ 2,025 State 6,974 4,601 8,634 Deferred Income Taxes — Federal 4,538 98,514 (38,927) State 49,775 23,751 20,774 18,739 85,221 (7,494) Deferred Investment Tax Credit (13) (91) (105) Total Income Taxes $ 18,726 $ 85,130 $ (7,599) Presented as Follows: Other (Income) Deductions $ (13) $ (91) $ (105) Income Tax Expense (Benefit) 18,739 85,221 (7,494) Total Income Taxes $ 18,726 $ 85,130 $ (7,599)
Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate	The following is a reconciliation of this difference: Year Ended September 30 2020 2019 2018 (Thousands) U.S. Income (Loss) Before Income Taxes $ (105,046) $ 389,420 $ 383,922 Income Tax Expense, Computed at U.S. Federal Statutory Rate(1) $ (22,060) $ 81,778 $ 94,061 State Valuation Allowance(2) 63,205 — — State Income Tax (3) (18,374) 22,397 22,203 Amortization of Excess Deferred Federal Income Taxes(4) (4,749) (3,185) (1,336) Plant Flow Through Items (2,848) (1,544) (872) Stock Compensation 3,867 (1,491) (321) Federal Tax Credits (217) (7,361) (6,576) Impact of 2017 Tax Reform Act(5) — (5,000) (112,598) Miscellaneous (98) (464) (2,160) Total Income Taxes $ 18,726 $ 85,130 $ (7,599) (1) For fiscal 2020 and 2019, the statutory rate of 21% was utilized. For fiscal 2018, a blended rate of 24.5% was utilized, calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters. (2) During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets, as discussed below. (3) The state income tax expense (benefit) shown above includes the impact of state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes. (4) Represents amortization of net excess deferred federal income taxes under the 2017 Tax Reform Act.
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 2020 2019 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 874,607 $ 861,278 Pension and Other Post-Retirement Benefit Costs 54,066 55,795 Other 23,377 54,486 Total Deferred Tax Liabilities 952,050 971,559 Deferred Tax Assets: Tax Loss and Credit Carryforwards (179,363) (175,542) Pension and Other Post-Retirement Benefit Costs (95,599) (87,280) Other (44,239) (55,355) Total Gross Deferred Tax Assets (319,201) (318,177) Valuation Allowance 63,205 — Total Deferred Tax Assets (255,996) (318,177) Total Net Deferred Income Taxes $ 696,054 $ 653,382
Reconciliation Of The Change In Unrecognized Tax Benefits	The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2020 2019 2018 (Thousands) Balance at Beginning of Year $ — $ — $ 1,251 Additions for Tax Positions of Prior Years — — — Reductions for Tax Positions of Prior Years — — (788) Reductions Related to Settlements with Taxing Authorities — — (463) Balance at End of Year $ — $ — $ —
Summary of Operating Loss and Tax Credit Carryforwards	Tax carryforwards available, prior to valuation allowance, at September 30, 2020, were as follows: Jurisdiction Tax Attribute Amount Expires Federal Pre-Fiscal 2019 Net Operating Loss $ 205,918 2032-2038 Federal Post-Fiscal 2018 Net Operating Loss 185,779 Unlimited Pennsylvania Net Operating Loss 428,672 2031-2041 California Net Operating Loss 224,159 2031-2041 Federal Enhanced Oil Recovery Credit 26,790 2029-2039 California Enhanced Oil Recovery Credit 8,502 2037-2039 California Alternative Minimum Tax Credit 8,864 Unlimited Federal R&D Tax Credit 6,550 2031-2040 Federal Charitable Contributions 1,559 2025

Capitalization And Short-Term_2

Capitalization And Short-Term Borrowings (Tables)	12 Months Ended
	Sep. 30, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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, 2017 85,543 $ 85,543 $ 796,646 $ 851,669 $ (30,123) Net Income Available for Common Stock 391,521 Dividends Declared on Common Stock ($1.68 Per Share) (144,290) Other Comprehensive Loss, Net of Tax (37,627) Share-Based Payment Expense(1) 14,235 Common Stock Issued Under Stock and Benefit Plans 414 414 9,342 Balance at September 30, 2018 85,957 85,957 820,223 1,098,900 (67,750) Net Income Available for Common Stock 304,290 Dividends Declared on Common Stock ($1.72 Per Share) (148,432) Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities 7,437 Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects 10,406 Other Comprehensive Income, Net of Tax 15,595 Share-Based Payment Expense(1) 19,613 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 358 358 (7,572) Balance at September 30, 2019 86,315 86,315 832,264 1,272,601 (52,155) Net Loss Available for Common Stock (123,772) Dividends Declared on Common Stock ($1.76 Per Share) (156,249) Cumulative Effect of Adoption of Authoritative Guidance for Hedging (950) Other Comprehensive Loss, Net of Tax (62,602) Share-Based Payment Expense(1) 13,180 Common Stock Issued from Sale of Common Stock 4,370 4,370 161,399 Common Stock Issued (Repurchased) Under Stock and Benefit Plans 270 270 (2,685) Balance at September 30, 2020 90,955 $ 90,955 $ 1,004,158 $ 991,630 (2) $ (114,757) (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, 2020, $848.4 million of accumulated earnings was free of such limitations.
Schedule Of Share-Based Compensation For SARs	Transactions for 2020 involving SARs for all plans are summarized as follows: Number of Weighted Weighted Aggregate Outstanding at September 30, 2019 733,132 $ 54.90 Granted in 2020 — $ — Exercised in 2020 — $ — Forfeited in 2020 — $ — Expired in 2020 (219,952) $ 52.18 Outstanding at September 30, 2020 513,180 $ 56.07 1.28 $ — SARs exercisable at September 30, 2020 513,180 $ 56.07 1.28 $ — Shares available for future grant at September 30, 2020(1) 3,220,528 (1) Includes shares available for options, SARs, restricted stock and performance share grants.
Schedule Of Share-Based Compensation For Restricted Share Awards	Transactions for 2020 involving restricted share awards for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2019 20,000 $ 47.46 Granted in 2020 — $ — Vested in 2020 — $ — Forfeited in 2020 — $ — Outstanding at September 30, 2020 20,000 $ 47.46
Schedule Of Share-Based Compensation For Non-Performance Based Restricted Stock Units	Transactions for 2020 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2019 281,607 $ 48.88 Granted in 2020 150,839 $ 40.38 Vested in 2020 (87,835) $ 50.26 Forfeited in 2020 (8,838) $ 46.72 Outstanding at September 30, 2020 335,773 $ 44.76
Schedule of Share-based Compensation for Performance Shares	Transactions for 2020 involving performance shares for all plans are summarized as follows: Number of Weighted Average Outstanding at September 30, 2019 522,514 $ 54.37 Granted in 2020 254,608 $ 43.32 Vested in 2020 (231,246) $ 55.33 Forfeited in 2020 (11,040) $ 46.40 Change in Units Based on Performance Achieved 57,792 $ 52.13 Outstanding at September 30, 2020 592,628 $ 49.18
Schedule Of Long-Term Debt	The outstanding long-term debt is as follows: At September 30 2020 2019 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(2)(3): 3.75% to 5.50% due December 2021 to September 2028 2,550,000 2,050,000 Total Long-Term Debt 2,649,000 2,149,000 Less Unamortized Discount and Debt Issuance Costs 19,424 15,282 Less Current Portion(4) — — $ 2,629,576 $ 2,133,718 (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 and $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to a maximum adjustment of 2.00% such that the coupon will not exceed 7.5% if there is a downgrade of the credit rating assigned to the notes. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded . (4) None of the Company's long-term debt at September 30, 2020 and 2019 will mature within the following twelve-month period.	[1],[2],[3],[4]
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Weighted Average Assumptions Used in Estimating Fair Value	The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant: Year Ended September 30 2020 2019 2018 Risk-Free Interest Rate 1.63 % 2.61 % 1.96 % Remaining Term at Date of Grant (Years) 2.81 2.78 2.78 Expected Volatility 19.3 % 20.2 % 22.0 % Expected Dividend Yield (Quarterly) N/A N/A N/A
[1]	The interest rate payable on $300.0 million of 4.75% notes and $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to a maximum adjustment of 2.00% such that the coupon will not exceed 7.5% if there is a downgrade of the credit rating assigned to the notes. 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 .
[2]	None of the Company's long-term debt at September 30, 2020 and 2019 will mature within the following twelve-month period.
[3]	The Medium-Term Notes and Notes are unsecured.
[4]	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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2020
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, 2020 and 2019. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company. At Fair Value as of September 30, 2020 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 12,285 $ — $ — $ — $ 12,285 Derivative Financial Instruments: Over the Counter Swaps — Gas and Oil — 36,418 — (26,400) 10,018 Over the Counter No Cost Collars — Gas — — — (720) (720) Foreign Currency Contracts — 259 — (338) (79) Other Investments: Balanced Equity Mutual Fund 39,618 — — — 39,618 Fixed Income Mutual Fund 72,253 — — — 72,253 Common Stock — Financial Services Industry 639 — — — 639 Total $ 124,795 $ 36,677 $ — $ (27,458) $ 134,014 Liabilities: Derivative Financial Instruments: Over the Counter Swaps — Gas and Oil $ — $ 61,280 $ — $ (26,400) $ 34,880 Over the Counter No Cost Collars — Gas — 8,171 — (720) 7,451 Foreign Currency Contracts — 1,976 — (338) 1,638 Total $ — $ 71,427 $ — $ (27,458) $ 43,969 Total Net Assets/(Liabilities) $ 124,795 $ (34,750) $ — $ — $ 90,045 At Fair Value as of September 30, 2019 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 10,521 $ — $ — $ — $ 10,521 Derivative Financial Instruments: Commodity Futures Contracts — Gas 2,055 — — (2,055) — Over the Counter Swaps — Gas and Oil — 52,076 — (1,483) 50,593 Foreign Currency Contracts — 5 — (2,052) (2,047) Other Investments: Balanced Equity Mutual Fund 40,660 — — — 40,660 Fixed Income Mutual Fund 62,339 — — — 62,339 Common Stock — Financial Services Industry 844 — — — 844 Hedging Collateral Deposits 6,832 — — — 6,832 Total $ 123,251 $ 52,081 $ — $ (5,590) $ 169,742 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 7,149 $ — $ — $ (2,055) $ 5,094 Over the Counter Swaps — Gas and Oil — 1,671 — (1,483) 188 Foreign Currency Contracts — 2,344 — (2,052) 292 Total $ 7,149 $ 4,015 $ — $ (5,590) $ 5,574 Total Net Assets/(Liabilities) $ 116,102 $ 48,066 $ — $ — $ 164,168

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Sep. 30, 2020
Financial Instruments, Owned, at Fair Value [Abstract]
Long-Term Debt	Based on these criteria, the fair market value of long-term debt, including current portion, was as follows: At September 30 2020 2020 2019 Carrying 2019 (Thousands) Long-Term Debt $ 2,629,576 $ 2,778,556 $ 2,133,718 $ 2,257,085
Schedule of Other Investments	The components of the Company's Other Investments are as follows (in thousands): At September 30 2020 2019 (Thousands) Life Insurance Contracts $ 41,992 $ 41,074 Equity Mutual Fund 39,618 40,660 Fixed Income Mutual Fund 72,253 62,339 Marketable Equity Securities 639 844 $ 154,502 $ 144,917
Schedule Of Derivatives 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 Derivatives in Cash Amount of Location of Amount of 2020 2019 2020 2019 Commodity Contracts $ 9,905 $ 82,984 Operating Revenue $ 93,691 $ (3,460) Commodity Contracts 391 (1,037) Purchased Gas 661 (1,182) Foreign Currency Contracts (434) (2,646) Operating Revenue (1,057) (822) Total $ 9,862 $ 79,301 $ 93,295 $ (5,464)

Retirement Plan And Other Pos_2

Retirement Plan And Other Post-Retirement Benefits (Tables)	12 Months Ended
	Sep. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
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) on the Consolidated Statements of Income. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2020, 2019 and 2018. Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2020 2019 2018 2020 2019 2018 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 1,097,625 $ 985,690 $ 1,054,826 $ 468,163 $ 435,986 $ 462,619 Service Cost 9,318 8,482 9,921 1,609 1,519 1,830 Interest Cost 29,930 38,378 33,006 12,913 17,145 14,801 Plan Participants’ Contributions — — — 3,058 2,930 2,894 Retiree Drug Subsidy Receipts — — — 1,411 1,855 1,545 Actuarial (Gain) Loss 65,908 127,748 (50,218) 16,396 34,401 (21,039) Benefits Paid (63,676) (62,673) (61,845) (26,828) (25,673) (26,664) Benefit Obligation at End of Period $ 1,139,105 $ 1,097,625 $ 985,690 $ 476,722 $ 468,163 $ 435,986 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 968,449 $ 924,506 $ 910,719 $ 524,127 $ 513,800 $ 514,017 Actual Return on Plan Assets 87,402 77,401 42,652 44,448 30,006 20,657 Employer Contributions 24,621 29,215 32,980 3,080 3,064 2,896 Plan Participants’ Contributions — — — 3,058 2,930 2,894 Benefits Paid (63,676) (62,673) (61,845) (26,828) (25,673) (26,664) Fair Value of Assets at End of Period $ 1,016,796 $ 968,449 $ 924,506 $ 547,885 $ 524,127 $ 513,800 Net Amount Recognized at End of Period (Funded Status) $ (122,309) $ (129,176) $ (61,184) $ 71,163 $ 55,964 $ 77,814 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (122,309) $ (129,176) $ (61,184) $ (4,872) $ (4,553) $ (4,919) Non-Current Assets — — — 76,035 60,517 82,733 Net Amount Recognized at End of Period $ (122,309) $ (129,176) $ (61,184) $ 71,163 $ 55,964 $ 77,814 Accumulated Benefit Obligation $ 1,096,427 $ 1,053,914 $ 946,763 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 2.66 % 3.15 % 4.30 % 2.71 % 3.17 % 4.31 % Rate of Compensation Increase 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2020 2019 2018 2020 2019 2018 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 9,318 $ 8,482 $ 9,921 $ 1,609 $ 1,519 $ 1,830 Interest Cost 29,930 38,378 33,006 12,913 17,145 14,801 Expected Return on Plan Assets (60,063) (62,368) (61,715) (29,232) (30,157) (31,482) Amortization of Prior Service Cost (Credit) 729 826 938 (429) (429) (429) Recognition of Actuarial Loss(1) 39,384 32,096 37,205 535 5,962 10,558 Net Amortization and Deferral for Regulatory Purposes 5,359 2,493 9,027 25,596 16,481 15,028 Net Periodic Benefit Cost $ 24,657 $ 19,907 $ 28,382 $ 10,992 $ 10,521 $ 10,306 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 3.15 % 4.30 % 3.77 % 3.17 % 4.31 % 3.81 % Effective Rate for Interest on Benefit Obligations 2.81 % 4.03 % 3.23 % 2.84 % 4.05 % 3.29 % Effective Discount Rate for Service Cost 3.31 % 4.40 % 4.00 % 3.39 % 4.43 % 4.10 % Effective Rate for Interest on Service Cost 3.12 % 4.29 % 3.73 % 3.30 % 4.39 % 3.98 % Expected Return on Plan Assets 6.40 % 6.75 % 7.00 % 5.70 % 6.00 % 6.25 % Rate of Compensation Increase 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % (1) Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.
Schedule Of Cumulative Amounts Recognized In AOCI (Loss) And Regulatory Assets And Liabilities	The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2020, the changes in such amounts during 2020, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2021 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 $ (215,330) $ (28,044) $ (34,065) Prior Service (Cost) Credit (3,641) 2,401 — Net Amount Recognized $ (218,971) $ (25,643) $ (34,065) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2020(1) Increase in Actuarial Loss, excluding amortization(2) $ (38,568) $ (1,180) $ (5,929) Change due to Amortization of Actuarial Loss 39,384 535 5,341 Prior Service (Cost) Credit 729 (429) — Net Change $ 1,545 $ (1,074) $ (588) Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (36,814) $ (849) $ (5,852) Prior Service (Cost) Credit (631) 429 — Net Amount Expected to be Recognized $ (37,445) $ (420) $ (5,852) (1) Amounts presented are shown before recognizing deferred taxes. (2) Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.
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 2021 $ 28,361 $ (1,950) 2022 $ 28,820 $ (2,064) 2023 $ 29,085 $ (2,172) 2024 $ 29,192 $ (2,273) 2025 $ 29,231 $ (2,356) 2026 through 2030 $ 143,696 $ (12,763)
Schedule Of Health Care Cost Trend Rates	Assumed health care cost trend rates as of September 30 were: 2020 2019 2018 Rate of Medical Cost Increase for Pre Age 65 Participants 5.42 % (1) 5.50 % (1) 5.59 % (1) Rate of Medical Cost Increase for Post Age 65 Participants 4.75 % (1) 4.75 % (1) 4.75 % (1) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 6.80 % (1) 7.35 % (1) 7.89 % (1) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 4.75 % (1) 4.75 % (1) 4.75 % (1) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 6.20 % (1) 6.84 % (1) 7.18 % (1) (1) It was assumed that this rate would gradually decline to 4.5% by 2039.
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule Of Fair Value Of Plan Assets	At September 30, 2020 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 188,939 $ 118,124 $ — $ — $ 70,815 International Equities(2) 94,603 — — — 94,603 Global Equities(3) 77,736 — — — 77,736 Domestic Fixed Income(4) 512,693 2,000 457,381 — 53,312 International Fixed Income(5) 20,201 — 20,201 — — Global Fixed Income(6) 79,595 — — — 79,595 Real Estate 106,167 — — 471 105,696 Cash Held in Collective Trust Funds 18,023 — — — 18,023 Total Retirement Plan Investments 1,097,957 120,124 477,582 471 499,780 401(h) Investments (80,511) (8,809) (35,021) (35) (36,646) Total Retirement Plan Investments (excluding 401(h) Investments) $ 1,017,446 $ 111,315 $ 442,561 $ 436 $ 463,134 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (650) Total Retirement Plan Assets $ 1,016,796 At September 30, 2019 Total Level 1 Level 2 Level 3 Measured Retirement Plan Investments Domestic Equities(1) $ 175,812 $ 114,324 $ — $ — $ 61,488 International Equities(2) 81,631 — — — 81,631 Global Equities(3) 70,095 — — — 70,095 Domestic Fixed Income(4) 493,839 1,784 439,255 — 52,800 International Fixed Income(5) 17,744 — 17,744 — — Global Fixed Income(6) 75,329 — — — 75,329 Real Estate 107,764 — — 3,154 104,610 Cash Held in Collective Trust Funds 18,310 — — — 18,310 Total Retirement Plan Investments 1,040,524 116,108 456,999 3,154 464,263 401(h) Investments (73,688) (8,205) (32,295) (223) (32,965) Total Retirement Plan Investments (excluding 401(h) Investments) $ 966,836 $ 107,903 $ 424,704 $ 2,931 $ 431,298 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash 1,613 Total Retirement Plan Assets $ 968,449 (1) Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. (2) International Equities are comprised of collective trust funds. (3) Global Equities are comprised of collective trust funds. (4) Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds. (5) International Fixed Income securities are comprised mostly of corporate/government bonds. (6) Global Fixed Income securities are comprised of a collective trust fund.
Schedule Of Significant Unobservable Input Changes In Plan Assets	Retirement Plan Level 3 Assets Real Excluding Total Balance at September 30, 2018 $ 3,194 $ (218) $ 2,976 Unrealized Gains/(Losses) (37) (5) (42) Sales (3) — (3) Balance at September 30, 2019 3,154 (223) 2,931 Unrealized Gains/(Losses) (2,683) 188 (2,495) Sales — — — Balance at September 30, 2020 $ 471 $ (35) $ 436
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule Of Fair Value Of Plan Assets	At September 30, 2020 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 153,923 $ — $ — $ — $ 153,923 Exchange Traded Funds — Fixed Income 301,290 301,290 — — — Cash Held in Collective Trust Funds 13,841 — — — 13,841 Total VEBA Trust Investments 469,054 301,290 — — 167,764 401(h) Investments 80,511 8,809 35,021 35 36,646 Total Investments (including 401(h) Investments) $ 549,565 $ 310,099 $ 35,021 $ 35 $ 204,410 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (1,680) Total Other Post-Retirement Benefit Assets $ 547,885 At September 30, 2019 Total Level 1 Level 2 Level 3 Measured Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 167,966 $ — $ — $ — $ 167,966 Exchange Traded Funds — Fixed Income 275,296 275,296 — — — Cash Held in Collective Trust Funds 8,229 — — — 8,229 Total VEBA Trust Investments 451,491 275,296 — — 176,195 401(h) Investments 73,688 8,205 32,295 223 32,965 Total Investments (including 401(h) Investments) $ 525,179 $ 283,501 $ 32,295 $ 223 $ 209,160 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (1,052) Total Other Post-Retirement Benefit Assets $ 524,127 (1) Reflects the authoritative guidance related to investments measured at net asset value (NAV).
Schedule Of Significant Unobservable Input Changes In Plan Assets	Other Post-Retirement Benefit Level 3 Assets 401(h) Balance at September 30, 2018 $ 218 Unrealized Gains/(Losses) 5 Sales — Balance at September 30, 2019 223 Unrealized Gains/(Losses) (188) Sales — Balance at September 30, 2020 $ 35

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Sep. 30, 2020
Segment Reporting [Abstract]
Segment Information By Segment	Year Ended September 30, 2020 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 607,453 $ 205,998 $ 72 $ 642,855 $ 1,456,378 $ 89,435 $ 478 $ 1,546,291 Intersegment Revenues $ — $ 103,606 $ 142,821 $ 9,443 $ 255,870 $ 836 $ (256,706) $ — Interest Income $ 698 $ 1,475 $ 545 $ 2,262 $ 4,980 $ 860 $ (833) $ 5,007 Interest Expense $ 58,098 $ 32,731 $ 10,877 $ 22,150 $ 123,856 $ 66 $ (6,845) $ 117,077 Depreciation, Depletion and Amortization $ 172,124 $ 53,951 $ 22,440 $ 55,248 $ 303,763 $ 1,716 $ 679 $ 306,158 Income Tax Expense (Benefit) $ (41,472) $ 28,613 $ 18,191 $ 13,274 $ 18,606 $ 210 $ (77) $ 18,739 Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ 449,438 $ — $ — $ — $ 449,438 $ — $ — $ 449,438 Segment Profit: Net Income (Loss) $ (326,904) $ 78,860 $ 68,631 $ 57,366 $ (122,047) $ (269) $ (1,456) $ (123,772) Expenditures for Additions to Long-Lived Assets $ 670,455 $ 166,652 $ 297,806 $ 94,273 $ 1,229,186 $ 39 $ (608) $ 1,228,617 At September 30, 2020 (Thousands) Segment Assets $ 1,979,028 $ 2,204,971 $ 945,199 $ 2,067,852 $ 7,197,050 $ 113,571 $ (345,686) $ 6,964,935 Year Ended September 30, 2019 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 632,740 $ 195,808 $ 11 $ 715,813 $ 1,544,372 $ 148,582 $ 378 $ 1,693,332 Intersegment Revenues $ — $ 92,475 $ 127,064 $ 11,629 $ 231,168 $ 1,127 $ (232,295) $ — Interest Income $ 1,107 $ 2,982 $ 546 $ 1,809 $ 6,444 $ 1,291 $ (1,670) $ 6,065 Interest Expense $ 54,777 $ 29,142 $ 9,406 $ 23,443 $ 116,768 $ 21 $ (10,033) $ 106,756 Depreciation, Depletion and Amortization $ 154,784 $ 44,947 $ 20,038 $ 53,832 $ 273,601 $ 1,291 $ 768 $ 275,660 Income Tax Expense (Benefit) $ 32,978 $ 23,238 $ 20,895 $ 13,967 $ 91,078 $ (955) $ (4,902) $ 85,221 Segment Profit: Net Income (Loss) $ 111,807 $ 74,011 $ 58,413 $ 60,871 $ 305,102 $ (1,811) $ 999 $ 304,290 Expenditures for Additions to Long-Lived Assets $ 491,889 $ 143,005 $ 49,650 $ 95,847 $ 780,391 $ 128 $ 727 $ 781,246 At September 30, 2019 (Thousands) Segment Assets $ 1,972,776 $ 1,893,514 $ 547,995 $ 1,991,338 $ 6,405,623 $ 122,241 $ (65,707) $ 6,462,157 Year Ended September 30, 2018 Exploration Pipeline Gathering Utility Total All Corporate Total (Thousands) Revenue from External Customers(1) $ 564,547 $ 210,345 $ 41 $ 674,726 $ 1,449,659 $ 142,349 $ 660 $ 1,592,668 Intersegment Revenues $ — $ 89,981 $ 107,856 $ 12,800 $ 210,637 $ 826 $ (211,463) $ — Interest Income $ 1,479 $ 2,748 $ 1,106 $ 1,591 $ 6,924 $ 1,073 $ (1,231) $ 6,766 Interest Expense $ 54,288 $ 31,383 $ 9,560 $ 26,753 $ 121,984 $ 22 $ (7,484) $ 114,522 Depreciation, Depletion and Amortization $ 124,274 $ 43,463 $ 17,313 $ 53,253 $ 238,303 $ 1,902 $ 756 $ 240,961 Income Tax Expense (Benefit) $ (41,962) $ 17,806 $ (17,677) $ 15,258 $ (26,575) $ 2,125 $ 16,956 $ (7,494) Segment Profit: Net Income (Loss) $ 180,632 $ 97,246 $ 83,519 $ 51,217 $ 412,614 $ 261 $ (21,354) $ 391,521 Expenditures for Additions to Long-Lived Assets $ 380,677 $ 92,832 $ 61,728 $ 85,648 $ 620,885 $ 41 $ (20,324) $ 600,602 At September 30, 2018 (Thousands) Segment Assets $ 1,568,563 $ 1,848,180 $ 533,608 $ 1,921,971 $ 5,872,322 $ 129,080 $ 35,084 $ 6,036,486 (1) All Revenue from External Customers originated in the United States.
Schedule Of Long-Lived Assets, By Geographical Areas	Geographic Information At September 30 2020 2019 2018 (Thousands) Long-Lived Assets: United States $ 6,597,313 $ 6,099,534 $ 5,491,895

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Sep. 30, 2020
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	Quarter Ended Operating Operating Net Income (Loss) Earnings (Loss) per Basic Diluted (Thousands, except per common share amounts) 2020 9/30/2020 $ 287,989 $ (173,979) $ (145,545) (1) $ (1.60) $ (1.60) 6/30/2020 $ 323,019 $ 80,397 $ 41,250 (2) $ 0.47 $ 0.47 3/31/2020 $ 491,095 $ (24,580) $ (106,068) (3) $ (1.23) $ (1.23) 12/31/2019 $ 444,188 $ 148,020 $ 86,591 $ 1.00 $ 1.00 2019 9/30/2019 $ 293,341 $ 83,940 $ 47,282 $ 0.55 $ 0.54 6/30/2019 $ 357,200 $ 112,827 $ 63,753 $ 0.74 $ 0.73 3/31/2019 $ 552,544 $ 153,359 $ 90,595 $ 1.05 $ 1.04 12/31/2018 $ 490,247 $ 161,683 $ 102,660 (4) $ 1.19 $ 1.18 (1) Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (2) Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (3) Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.

Supplementary Information For_2

Supplementary Information For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Sep. 30, 2020
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Capitalized Costs Relating To Oil And Gas Producing Activities	Capitalized Costs Relating to Oil and Gas Producing Activities At September 30 2020 2019 (Thousands) Proved Properties(1) $ 6,238,830 $ 5,623,623 Unproved Properties 148,075 53,498 6,386,905 5,677,121 Less — Accumulated Depreciation, Depletion and Amortization 4,628,765 4,012,568 $ 1,758,140 $ 1,664,553 (1) Includes asset retirement costs of $132.6 million and $70.5 million at September 30, 2020 and 2019, respectively.
Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization	Following is a summary of costs excluded from amortization at September 30, 2020: Total as of Year Costs Incurred 2020 2019 2018 Prior (Thousands) Acquisition Costs $ 64,218 $ 39,953 $ — $ — $ 24,265 Development Costs 75,138 54,761 17,326 403 2,648 Exploration Costs 7,606 — — — 7,606 Capitalized Interest 1,113 969 41 — 103 $ 148,075 $ 95,683 $ 17,367 $ 403 $ 34,622
Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities	Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2020 2019 2018 (Thousands) United States Property Acquisition Costs: Proved $ 245,976 $ 3,136 $ 1,544 Unproved 42,922 3,679 4,286 Exploration Costs 3,891 2,060 29,365 Development Costs(1) 355,742 468,498 332,496 Asset Retirement Costs 62,080 26,192 (10,107) $ 710,611 $ 503,565 $ 357,584 (1) Amounts for 2020, 2019 and 2018 include capitalized interest of $1.0 million, $0.2 million and $0.3 million, respectively.
Results Of Operations For Producing Activities	Results of Operations for Producing Activities Year Ended September 30 2020 2019 2018 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of 1,921, 2,532 and 2,134, respectively)(1) $ 402,447 $ 481,048 $ 390,642 Oil, Condensate and Other Liquids 107,844 149,078 168,254 Total Operating Revenues(2) 510,291 630,126 558,896 Production/Lifting Costs 203,670 186,626 162,721 Franchise/Ad Valorem Taxes 15,582 17,673 14,355 Purchased Emission Allowance Expense 2,930 2,527 1,883 Accretion Expense 5,237 3,723 4,266 Depreciation, Depletion and Amortization ($0.69, $0.71 and $0.67 per Mcfe of production, respectively) 166,759 149,881 119,946 Impairment of Oil and Gas Producing Properties 449,438 — — Income Tax Expense (92,820) 64,652 72,723 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ (240,505) $ 205,044 $ 183,002 (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.
Proved Developed And Undeveloped Oil And Gas Reserve Quantities	Gas MMcf U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: September 30, 2017 1,926,614 46,506 1,973,120 Extensions and Discoveries 521,694 (1) — 521,694 Revisions of Previous Estimates 90,113 3,322 93,435 Production (160,499) (2) (2,407) (162,906) Sale of Minerals in Place (57,420) (10,581) (68,001) September 30, 2018 2,320,502 36,840 2,357,342 Extensions and Discoveries 686,549 (1) — 686,549 Revisions of Previous Estimates 104,741 (1,233) 103,508 Production (195,906) (2) (1,974) (197,880) September 30, 2019 2,915,886 33,633 2,949,519 Extensions and Discoveries 7,246 (1) — 7,246 Revisions of Previous Estimates (85,647) (2,772) (88,419) Production (225,513) (2) (1,889) (227,402) Purchases of Minerals in Place 684,141 — 684,141 September 30, 2020 3,296,113 28,972 3,325,085 Proved Developed Reserves: September 30, 2017 1,316,596 46,506 1,363,102 September 30, 2018 1,569,692 36,840 1,606,532 September 30, 2019 1,901,162 33,633 1,934,795 September 30, 2020 2,744,851 28,972 2,773,823 Proved Undeveloped Reserves: September 30, 2017 610,018 — 610,018 September 30, 2018 750,810 — 750,810 September 30, 2019 1,014,724 — 1,014,724 September 30, 2020 551,262 — 551,262 (1) Extensions and discoveries include 274 Bcf (during 2018), 175 Bcf (during 2019) and 7 Bcf (during 2020), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 248 Bcf (during 2018), 512 Bcf (during 2019) and 0 Bcf (during 2020), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 150,196 MMcf (during 2018), 163,015 MMcf (during 2019) and 169,453 MMcf (during 2020), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018), 32,095 MMcf (during 2019) and 55,392 MMcf (during 2020), from Utica Shale fields. Oil Mbbl U.S. Appalachian West Coast Total Proved Developed and Undeveloped Reserves: September 30, 2017 28 30,179 30,207 Extensions and Discoveries — 2,301 2,301 Revisions of Previous Estimates (10) 2,487 2,477 Production (4) (2,531) (2,535) Sales of Minerals in Place — (4,787) (4,787) September 30, 2018 14 27,649 27,663 Extensions and Discoveries — 787 787 Revisions of Previous Estimates 2 (1,256) (1,254) Production (3) (2,320) (2,323) September 30, 2019 13 24,860 24,873 Extensions and Discoveries — 288 288 Revisions of Previous Estimates 2 (715) (713) Production (3) (2,345) (2,348) September 30, 2020 12 22,088 22,100 Proved Developed Reserves: September 30, 2017 28 29,771 29,799 September 30, 2018 14 26,689 26,703 September 30, 2019 13 24,246 24,259 September 30, 2020 12 22,088 22,100 Proved Undeveloped Reserves: September 30, 2017 — 408 408 September 30, 2018 — 960 960 September 30, 2019 — 614 614 September 30, 2020 — — —
Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Year Ended September 30 2020 2019 2018 (Thousands) United States Future Cash Inflows $ 6,493,362 $ 8,738,182 $ 7,822,855 Less: Future Production Costs 3,149,857 2,989,518 2,606,411 Future Development Costs 501,678 797,640 559,707 Future Income Tax Expense at Applicable Statutory Rate 454,553 1,159,882 1,125,910 Future Net Cash Flows 2,387,274 3,791,142 3,530,827 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,164,804 2,054,823 1,810,522 Standardized Measure of Discounted Future Net Cash Flows $ 1,222,470 $ 1,736,319 $ 1,720,305
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 2020 2019 2018 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,736,319 $ 1,720,305 $ 1,113,046 Sales, Net of Production Costs (290,975) (425,773) (381,775) Net Changes in Prices, Net of Production Costs (1,109,101) (164,428) 541,021 Extensions and Discoveries 4,236 202,683 212,494 Changes in Estimated Future Development Costs 99,884 (69,254) (43,771) Purchases of Minerals in Place 170,363 — — Sales of Minerals in Place — — (100,816) Previously Estimated Development Costs Incurred 219,938 245,964 182,348 Net Change in Income Taxes at Applicable Statutory Rate 248,182 21,370 55,558 Revisions of Previous Quantity Estimates (28,337) 53,777 61,363 Accretion of Discount and Other 171,961 151,675 80,837 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,222,470 $ 1,736,319 $ 1,720,305

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Summary Of Significant Accounting Policies [Line Items]
Capitalized Costs Oil And Gas Producing Activities Net	$ 1,758,140			$ 1,758,140	$ 1,664,553
Full cost ceiling test discount factor	10.00%			10.00%
Impairment of Oil and Gas Producing Properties	$ 253,400	$ 18,200	$ 177,800	$ 449,438	0	$ 0
Increase (decrease) estimated future net cash flows				180,000	(17,700)	(25,100)
Depreciation, Depletion and Amortization Expense for Oil and Gas Properties				166,759	149,881	119,946
Goodwill	5,476			5,476	5,476
Prior service cost	(900)			(900)	(1,000)
Retained Earnings (Accumulated Deficit)	991,630			991,630	1,272,601	$ 1,098,900	$ 851,669
Gas stored underground	33,338			33,338	36,632
Customer Advances	15,319			15,319	13,044
Customer Security Deposits	17,199			$ 17,199	$ 16,210
Antidilutive securities				411,890	242,302	317,899
Amount Exceeds LIFO Basis [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground	6,600			$ 6,600
LIFO Method [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground	33,200			33,200
Accumulated Losses [Member]
Summary Of Significant Accounting Policies [Line Items]
Accumulated losses	$ 89,000			$ 89,000	$ 85,800
Unamortized Debt Expense [Member]
Summary Of Significant Accounting Policies [Line Items]
Rate recovery period				6 years
Impairment of Oil and Gas Producing Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred Income Tax Benefit				$ 123,100
Guidance for Reclassification of Stranded Tax Effects [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Summary Of Significant Accounting Policies [Line Items]
Increase (Decrease) to Accumulated Other Comprehensive Income						$ (10,400)
Retained Earnings (Accumulated Deficit)					0	10,406	0
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Summary Of Significant Accounting Policies [Line Items]
Increase (Decrease) to Accumulated Other Comprehensive Income						(7,400)
Retained Earnings (Accumulated Deficit)					0	7,437	0
Guidance for Hedging [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Summary Of Significant Accounting Policies [Line Items]
Increase (Decrease) to Accumulated Other Comprehensive Income					1,000
Retained Earnings (Accumulated Deficit)					$ (950)	$ 0	$ 0

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Schedule Of Depreciable Plant By Segment) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019
Segment Reporting Information [Line Items]
Depreciable plant	$ 11,906,360	$ 10,788,616
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciable plant	6,384,086	5,747,731
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,418,265	2,191,166
Gathering [Member]
Segment Reporting Information [Line Items]
Depreciable plant	849,204	577,021
Utility [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,234,433	2,159,841
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Depreciable plant	$ 20,372	$ 112,857

Summary Of Significant Accoun_6

Summary Of Significant Accounting Policies (Average Depreciation Depletion And Amortization Rates) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe	[1]	$ 0.71	$ 0.73	$ 0.70
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.40%	2.20%	2.20%
Gathering [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		3.20%	3.60%	3.40%
Utility [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.70%	2.70%	2.80%
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		3.60%	1.80%	2.40%
Oil And Gas Producing Properties [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe		$ 0.69	$ 0.71	$ 0.67
[1]	Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note O — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.69, $0.71 and $0.67 per Mcfe of production in 2020, 2019 and 2018, respectively.

Summary Of Significant Accoun_7

Summary Of Significant Accounting Policies (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ (52,155)	$ (67,750)
Other Comprehensive Gains and Losses Before Reclassifications	(7,573)	25,066
Amounts Reclassified From Other Comprehensive Income (Loss)	(55,979)	8,372
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities		(7,437)
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act	0	(10,406)	$ 0
Ending balance	(114,757)	(52,155)	(67,750)
Gains and Losses on Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	34,675
Other Comprehensive Gains and Losses Before Reclassifications	7,284
Amounts Reclassified From Other Comprehensive Income (Loss)	(67,774)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950
Ending balance	(24,865)	34,675
Gains and Losses on Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	34,675	(28,611)
Other Comprehensive Gains and Losses Before Reclassifications		58,682
Amounts Reclassified From Other Comprehensive Income (Loss)		2,738
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities		0
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act		1,866
Ending balance		34,675	(28,611)
Gains and Losses on Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	0	7,437
Other Comprehensive Gains and Losses Before Reclassifications	0	0
Amounts Reclassified From Other Comprehensive Income (Loss)	0	0
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	0
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities		(7,437)
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act		0
Ending balance	0	0	7,437
Funded Status of the Pension and Other Post-Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(86,830)	(46,576)
Other Comprehensive Gains and Losses Before Reclassifications	(14,857)	(33,616)
Amounts Reclassified From Other Comprehensive Income (Loss)	11,795	5,634
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	0
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities		0
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act		(12,272)
Ending balance	$ (89,892)	$ (86,830)	$ (46,576)

Summary Of Significant Accoun_8

Summary Of Significant Accounting Policies (Reclassification Out of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands		3 Months Ended												12 Months Ended
		Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ 287,989		$ 323,019		$ 491,095		$ 444,188	$ 293,341	$ 357,200	$ 552,544	$ 490,247		$ 1,546,291	$ 1,693,332	$ 1,592,668
Other Income (Deductions)														(17,814)	(15,542)	(21,174)
Purchased Gas														233,890	386,265	337,822
Income (Loss) Before Income Taxes														(105,033)	389,511	384,027
Income Tax Expense														(18,739)	(85,221)	7,494
Net Income (Loss) Available for Common Stock		$ (145,545)	[1]	$ 41,250	[2]	$ (106,068)	[3]	$ 86,591	$ 47,282	$ 63,753	$ 90,595	$ 102,660	[4]	(123,772)	304,290	$ 391,521
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Income (Loss) Before Income Taxes														77,934	(12,796)
Income Tax Expense														(21,955)	4,424
Net Income (Loss) Available for Common Stock														55,979	(8,372)
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Amortization of Prior Year Funded Status of Pension and Other Post-Retirement Benefit Plans [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Amortization of Prior Service Cost	[5]													(237)	(264)
Recognition of Net Actuarial Loss	[5]													(15,124)	(7,068)
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Commodity Contracts [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues															(3,460)
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Commodity Contracts [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues														93,691
Foreign Currency Contracts [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues															(822)
Foreign Currency Contracts [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues														(1,057)
Purchased Gas [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Commodity Contracts [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Purchased Gas															$ (1,182)
Purchased Gas [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Commodity Contracts [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Purchased Gas														$ 661
[1]	Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.
[4]	Includes a $5.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[5]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.

Summary Of Significant Accoun_9

Summary Of Significant Accounting Policies (Materials, Supplies and Emission Allowances (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019
Materials, Supplies and Emission Allowances [Line Items]
Materials and Supplies - at average cost	$ 33,859	$ 29,819
Emission Allowances	18,018	10,898
Materials, Supplies and Emission Allowances	$ 51,877	$ 40,717

Summary of Significant Accou_10

Summary of Significant Accounting Policies (Consolidated Statement of Cash Flows) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Cash and Cash Equivalents [Line Items]
Cash and Temporary Cash Investments	$ 20,541	$ 20,428		$ 229,606	$ 555,530
Hedging Collateral Deposits	0	6,832	[1]	3,441	1,741
Cash, Cash Equivalents and Restricted Cash	$ 20,541	$ 27,260		$ 233,047	$ 557,271
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Summary Of Significant Accou_11

Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) - USD ($) $ in Thousands		Sep. 30, 2020	Sep. 30, 2019
Summary Of Significant Accounting Policies [Line Items]
Prepayments		$ 12,851	$ 12,728
Prepaid Property and Other Taxes		14,269	14,361
Fair Values of Firm Commitments		0	7,538
Regulatory Assets	[1]	16,609	11,460
Other Current Assets		47,557	97,054
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		0	42,388
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		$ 3,828	$ 8,579
[1]	The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.

Summary Of Significant Accou_12

Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liabilities	$ 55,678	$ 54,349
Liability for Royalty and Working Interests	15,665	18,057
Other Accruals and Current Liabilities	140,176	139,600
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	33,344	33,713
Regulatory Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liabilities	44,890	50,332
Other Accruals [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	31,654	24,304
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	163	0
Non-Qualified [Member]
Summary Of Significant Accounting Policies [Line Items]
Non-Qualified Benefit Plan Liability	98,100	99,500	$ 86,100
Non-Qualified [Member] | Current [Member]
Summary Of Significant Accounting Policies [Line Items]
Non-Qualified Benefit Plan Liability	$ 14,460	$ 13,194	$ 11,500

Asset Acquisitions and Divest_3

Asset Acquisitions and Divestitures (Narrative) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2020USD ($)aBcf	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Aug. 05, 2020USD ($)
Asset Acquisition and Divestitures [Line Items]
Total Consideration for Asset Acquisition	$ 506,258
Net Acres Acquired in Appalachia | a	400,000
Net Acres Acquired in Tioga County | a	200,000
Proved Developed Reserves (Volume) | Bcf	684,141
Anticipated Proceeds from Sale of Certain Timber and Other Assets				$ 115,700
Assets Held for Sale, Net	$ 53,424	$ 0
Net Proceeds from Sale of Oil and Gas Producing Properties	$ 0	$ 0	$ 55,506
Seneca [Member]
Asset Acquisition and Divestitures [Line Items]
Net Proceeds from Sale of Oil and Gas Producing Properties			17,300
Sespe Field [Member]
Asset Acquisition and Divestitures [Line Items]
Net Proceeds from Sale of Oil and Gas Producing Properties			$ 38,200

Asset Acquisition and Divestitu

Asset Acquisition and Divestitures (Summary of Asset Acquisition) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Asset Acquisition and Divestitures [Line Items]
Purchase Price		$ 503,908
Transaction Costs		2,350
Total Consideration		506,258
Property, Plant and Equipment		1,228,617	$ 781,246	$ 600,602
Inventory		1,241
Total Accounting		506,258
Shell Acquisition [Member]
Asset Acquisition and Divestitures [Line Items]
Property, Plant and Equipment		505,017
Exploration And Production [Member]
Asset Acquisition and Divestitures [Line Items]
Property, Plant and Equipment		670,455	491,889	380,677
Inventory		1,132
Total Accounting		282,780
Proved Developed Producing Properties		241,134
Property Plant and Equipment Capitalized in the Full Cost Pool		277,832
Exploration And Production [Member] | Shell Acquisition [Member]
Asset Acquisition and Divestitures [Line Items]
Property, Plant and Equipment	[1],[2]	281,648
Gathering [Member]
Asset Acquisition and Divestitures [Line Items]
Property, Plant and Equipment		297,806	$ 49,650	$ 61,728
Inventory		109
Total Accounting		223,478
Gathering [Member] | Shell Acquisition [Member]
Asset Acquisition and Divestitures [Line Items]
Property, Plant and Equipment	[2]	$ 223,369
[1]	Includes $241,134 in Proved Developed Producing Properties and $277,832 capitalized in the full cost pool.
[2]	The Company utilized an income approach and market based approach to determine the fair value of the acquired property, plant and equipment in the Exploration and Production reporting segment. The Company utilized a cost approach and an income approach to determine the fair value of the acquired property, plant and equipment in the Gathering reporting segment.

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Narrative) (Details) $ in Millions	Sep. 30, 2020USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 185.2
Remaining Performance Obligation, Expected Timing of Satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 163.7
Remaining Performance Obligation, Expected Timing of Satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 132.4
Remaining Performance Obligation, Expected Timing of Satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 123
Remaining Performance Obligation, Expected Timing of Satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 116.7
Remaining Performance Obligation, Expected Timing of Satisfaction	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]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 517.4
Remaining Performance Obligation, Expected Timing of Satisfaction

Revenue from Contracts with C_4

Revenue from Contracts with Customers (Disaggregation of Revenue) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Revenue	$ 287,989	$ 323,019	$ 491,095	$ 444,188	$ 293,341	$ 357,200	$ 552,544	$ 490,247	$ 1,546,291	$ 1,693,332	$ 1,592,668
Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									513,762	635,012
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									93,691	(2,272)
Revenue									607,453	632,740
Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									309,604	288,283
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Revenue									309,604	288,283
Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									142,893	127,075
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Revenue									142,893	127,075
Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									644,309	728,746
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									7,989	(1,304)
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Revenue									652,298	727,442
Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,610,568	1,779,116
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									7,989	(1,304)
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									93,691	(2,272)
Revenue									1,712,248	1,775,540
All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									100,901	147,051
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									(10,630)	2,658
Revenue									90,271	149,709
Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(256,228)	(231,917)
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0	0
Revenue									(256,228)	(231,917)
Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,455,241	1,694,250
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									7,989	(1,304)
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									83,061	386
Revenue									1,546,291	1,693,332
Production of Natural Gas [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									402,447	481,048
Production of Natural Gas [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Natural Gas [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Natural Gas [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Natural Gas [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									402,447	481,048
Production of Natural Gas [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Natural Gas [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Natural Gas [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									402,447	481,048
Production of Crude Oil [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									107,844	149,078
Production of Crude Oil [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Crude Oil [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Crude Oil [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Crude Oil [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									107,844	149,078
Production of Crude Oil [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Crude Oil [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Production of Crude Oil [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									107,844	149,078
Natural Gas Processing [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									2,374	3,277
Natural Gas Processing [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Processing [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Processing [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Processing [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									2,374	3,277
Natural Gas Processing [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Processing [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Processing [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									2,374	3,277
Natural Gas Gathering Service [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Gathering Service [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Gathering Service [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									142,893	127,064
Natural Gas Gathering Service [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Gathering Service [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									142,893	127,064
Natural Gas Gathering Service [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Gathering Service [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(142,821)	(127,064)
Natural Gas Gathering Service [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									72	0
Natural Gas Transportation Service [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Transportation Service [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									229,391	209,184
Natural Gas Transportation Service [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Transportation Service [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									109,214	119,253
Natural Gas Transportation Service [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									338,605	328,437
Natural Gas Transportation Service [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Transportation Service [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(77,699)	(70,689)
Natural Gas Transportation Service [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									260,906	257,748
Natural Gas Storage Service [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Storage Service [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									79,073	75,484
Natural Gas Storage Service [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Storage Service [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Storage Service [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									79,073	75,484
Natural Gas Storage Service [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Storage Service [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(34,579)	(32,488)
Natural Gas Storage Service [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									44,494	42,996
Natural Gas Residential Sales [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Residential Sales [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Residential Sales [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Residential Sales [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									475,846	539,962
Natural Gas Residential Sales [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									475,846	539,962
Natural Gas Residential Sales [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Residential Sales [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Residential Sales [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									475,846	539,962
Natural Gas Commercial Sales [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Commercial Sales [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Commercial Sales [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Commercial Sales [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									61,239	73,331
Natural Gas Commercial Sales [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									61,239	73,331
Natural Gas Commercial Sales [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Commercial Sales [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Commercial Sales [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									61,239	73,331
Natural Gas Industrial Sales [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Industrial Sales [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Industrial Sales [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Industrial Sales [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,291	4,830
Natural Gas Industrial Sales [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,291	4,830
Natural Gas Industrial Sales [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Industrial Sales [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Industrial Sales [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,291	4,830
Natural Gas Marketing [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Marketing [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Marketing [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Marketing [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Marketing [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	0
Natural Gas Marketing [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									95,727	143,627
Natural Gas Marketing [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(835)	(1,127)
Natural Gas Marketing [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									94,892	142,500
Other [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,097	1,609
Other [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,140	3,615
Other [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0	11
Other [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(5,281)	(8,630)
Other [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(3,044)	(3,395)
Other [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									5,174	3,424
Other [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(294)	(549)
Other [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									$ 1,836	$ (520)

Leases (Narrative) (Details)

Leases (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Oct. 01, 2019
Lessee, Lease, Description [Line Items]
Right of Use Asset in Exchange for New Lease Liability	$ 0
Lease Payments	$ 22,475
Weighted Average Remaining Lease Term	7 years 4 months 24 days
Weighted Average Discount Rate	3.39%
Cash Paid for Operating Liabilities	$ 5,300
Buildings and Property [Member]
Lessee, Lease, Description [Line Items]
Non-Cancelable Lease Term	10 years
Operating Lease Renewal Term	18 months
Lease Payments	$ 8,400
Buildings and Property [Member] | Minimum [Member]
Lessee, Lease, Description [Line Items]
Non-Cancelable Lease Term	1 month
Operating Lease Renewal Term	1 year
Buildings and Property [Member] | Maximum [Member]
Lessee, Lease, Description [Line Items]
Non-Cancelable Lease Term	10 years
Operating Lease Renewal Term	14 years
Drilling Rigs [Member] | Maximum [Member]
Lessee, Lease, Description [Line Items]
Non-Cancelable Lease Term	1 year
Guidance for Leases [Member]
Lessee, Lease, Description [Line Items]
Increase in Assets and Liabilities Upon Adoption of Leasing Standard		$ 19,700

Leases (Components of Operating

Leases (Components of Operating Lease Costs) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2020USD ($)
Lessee, Lease, Description [Line Items]
Operating Lease Expense	$ 4,129
Variable Lease Expense	525	[1]
Short-Term Lease Expense/Costs	918	[2]
Sublease Income	(297)
Total Lease Expense	5,275
Oil and Natural Gas Properties [Member]
Lessee, Lease, Description [Line Items]
Short-Term Lease Expense/Costs	$ 19,232	[3]
[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]	Short-term lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting.

Leases (Balance Sheet Informati

Leases (Balance Sheet Information Related to Operating Leases) (Details) $ in Thousands	Sep. 30, 2020USD ($)
Deferred Charges [Member]
Lessee, Lease, Description [Line Items]
Operating Lease Asset	$ 19,850
Other Accruals and Current Liabilities [Member]
Lessee, Lease, Description [Line Items]
Operating Lease Liability - Current	4,943
Other Deferred Credits [Member]
Lessee, Lease, Description [Line Items]
Operating Lease Liability - Noncurrent	$ 14,777

Leases (Schedule of Operating L

Leases (Schedule of Operating Lease Liability Maturities) (Details) $ in Thousands	Sep. 30, 2020USD ($)
Lessee, Lease, Description [Line Items]
2021	$ 4,968
2022	3,045
2023	2,507
2024	2,238
2025	2,086
Thereafter	7,631
Total Lease Payments	22,475
Less: Interest	(2,755)
Other Accruals and Current Liabilities and Other Deferred Credits [Member]
Lessee, Lease, Description [Line Items]
Operating Lease Liability	$ 19,720

Leases (Schedule of Future Mini

Leases (Schedule of Future Minimum Operating Lease Payments) (Details) $ in Thousands	Sep. 30, 2019USD ($)
Leases [Abstract]
2020	$ 12,356	[1]
2021	2,813
2022	2,264
2023	2,270
2024	2,237
Thereafter	9,717
Total Operating Lease Obligations	$ 31,657
[1]	The future minimum operating lease payment amount for 2020 includes short-term leases, including drilling rigs, that are not included in the schedule of operating lease liability maturities above under the new authoritative guidance.

Asset Retirement Obligation (Na

Asset Retirement Obligation (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Asset Retirement Obligation [Line Items]
Liabilities Incurred	$ 61,246	$ 4,122	$ 5,597
Shell Acquisition [Member]
Asset Retirement Obligation [Line Items]
Liabilities Incurred	$ 57,200

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Change In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at Beginning of Year	$ 127,458	$ 108,235	$ 106,395
Liabilities Incurred	61,246	4,122	5,597
Revisions of Estimates	3,267	16,693	(419)
Liabilities Settled	(7,268)	(7,670)	(12,858)
Accretion Expense	7,525	6,078	9,520
Balance at End of Year	$ 192,228	$ 127,458	$ 108,235

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details)	12 Months Ended
	Sep. 30, 2020
New York [Member]
Regulatory Matters [Line Items]
Approved Return on Equity	8.70%

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2020	Sep. 30, 2019
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	$ 303,322	$ 307,982
Less: Amounts Included in Other Current Assets	[1]	(16,609)	(11,460)
Total Long-Term Regulatory Assets		156,106	167,320
Total Regulatory Liabilities		804,838	784,918
Less: Amounts Included in Current and Accrued Liabilities		(55,678)	(54,349)
Total Long-Term Regulatory Liabilities		161,573	142,367
Cost Of Removal Regulatory Liability [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		230,079	221,699
Taxes Refundable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		357,508	366,503
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[2]	146,474	126,577
Amounts Payable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		10,788	4,017
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[3]	59,989	66,122
Total Long-Term Regulatory Liabilities		15,099	15,790
Non-Current Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Liabilities		749,160	730,569
Other Accruals and Current Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Current and Accrued Liabilities		(44,890)	(50,332)
Pension Costs Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	107,010	114,509
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	18,863	18,236
Recoverable Future Taxes [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	118,310	115,197
Environmental Site Remediation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	10,479	15,317
Asset Retirement Obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	16,245	15,696
Unamortized Debt Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	12,297	14,005
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[5]	20,118	15,022
Total Long-Term Regulatory Assets		3,509	3,562
Long-Term Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Assets	[1]	286,713	296,522
Other Current Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Other Current Assets		$ (16,609)	$ (11,460)
[1]	The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.
[2]	Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.
[3]	$44,890 and $50,332 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,099 and $15,790 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively.
[4]	Included in Other Regulatory Assets on the Consolidated Balance Sheets.
[5]	$16,609 and $11,460 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,509 and $3,562 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2020 and 2019, respectively.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Mar. 31, 2020
Income Taxes [Line Items]
Federal Statutory Rate	35.00%	21.00%	21.00%	21.00%	24.50%	35.00%
First Installment of AMT Credit Refunds Received			$ 42,500
Accelerated AMT Credit Refund Received Under CARES Act			42,500
Taxes Refundable to Customers			357,508	$ 366,503
Recoverable Future Taxes			118,310	115,197
Valuation Allowance			63,205	0			$ 56,800
Deferred Income Taxes [Member]
Income Taxes [Line Items]
Taxes Refundable to Customers			357,500	366,500
Recoverable Future Taxes			$ 118,300	$ 115,200
Alternative Minimum Tax Credit [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards		$ 85,000			$ 85,000

Income Taxes (Components Of Fed

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, 2020	Sep. 30, 2019	Sep. 30, 2018
Current Income Taxes [Abstract]
Federal	$ (42,548)	$ (41,645)	$ 2,025
State	6,974	4,601	8,634
Deferred Income Taxes [Abstract]
Federal	4,538	98,514	(38,927)
State	49,775	23,751	20,774
Income Tax Expense (Benefit)	18,739	85,221	(7,494)
Deferred Investment Tax Credit	(13)	(91)	(105)
Total Income Taxes	18,726	85,130	(7,599)
Presented as Follows [Abstract]
Other (Income) Deductions	(13)	(91)	(105)
Income Tax Expense (Benefit)	$ 18,739	$ 85,221	$ (7,494)

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate) (Details) - USD ($) $ in Thousands		3 Months Ended	9 Months Ended	12 Months Ended
		Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Taxes [Line Items]
U.S. Income (Loss) Before Income Taxes				$ (105,046)	$ 389,420	$ 383,922
Income Tax Expense, Computed at U.S. Federal Statutory Rate	[1]			(22,060)	81,778	94,061
State Valuation Allowance	[2]			63,205	0	0
State Income Taxes (Benefit)	[3]			(18,374)	22,397	22,203
Federal Tax Credits				(217)	(7,361)	(6,576)
Amortization of Excess Deferred Federal Income Taxes	[4]			(4,749)	(3,185)	(1,336)
Plant Flow Through Items				(2,848)	(1,544)	(872)
Stock Compensation				3,867	(1,491)	(321)
Impact of 2017 Tax Reform Act	[5]			0	(5,000)	(112,598)
Miscellaneous				(98)	(464)	(2,160)
Total Income Taxes				$ 18,726	$ 85,130	$ (7,599)
Federal Statutory Rate		35.00%	21.00%	21.00%	21.00%	24.50%	35.00%
Reversal of estimate for potential sequestration of AMT credit refunds					$ 5,000
Estimate for potential sequestration of AMT credit refunds						$ 5,000
Income tax benefit from blended tax rate						$ 9,100
[1]	For fiscal 2020 and 2019, the statutory rate of 21% was utilized. For fiscal 2018, a blended rate of 24.5% was utilized, calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters.
[2]	During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets, as discussed below.
[3]	The state income tax expense (benefit) shown above includes the impact of state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes.
[4]	Represents amortization of net excess deferred federal income taxes under the 2017 Tax Reform Act.
[5]	The $5.0 million benefit in fiscal 2019 represents the reversal of the estimated sequestration of AMT credit refunds. The amount for fiscal 2018 represents the remeasurement of deferred income taxes as a result of the lower U.S. corporate income tax rate, including a $5.0 million estimate for the potential sequestration of AMT credit refunds and the benefit of $9.1 million as a result of the blended tax rate.

Income Taxes (Significant Compo

Income Taxes (Significant Components Of Deferred Tax Liabilities And Assets) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Mar. 31, 2020	Sep. 30, 2019
Deferred Tax Liabilities [Abstract]
Property, Plant and Equipment	$ 874,607		$ 861,278
Pension and Other Post-Retirement Benefit Costs	54,066		55,795
Other	23,377		54,486
Total Deferred Tax Liabilities	952,050		971,559
Deferred Tax Assets [Abstract]
Tax Loss and Credit Carryforwards	(179,363)		(175,542)
Pension and Other Post-Retirement Benefit Costs	(95,599)		(87,280)
Other	(44,239)		(55,355)
Total Gross Deferred Tax Assets	(319,201)		(318,177)
Valuation Allowance	63,205	$ 56,800	0
Total Deferred Tax Assets	(255,996)		(318,177)
Total Net Deferred Income Taxes	$ 696,054		$ 653,382

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Balance at Beginning of Year	$ 0	$ 0	$ 1,251
Additions for Tax Positions of Prior Years	0	0	0
Reductions for Tax Positions of Prior Years	0	0	(788)
Reductions Related to Settlements with Taxing Authorities	0	0	(463)
Balance at End of Year	$ 0	$ 0	$ 0

Income Taxes Income Taxes (Summ

Income Taxes Income Taxes (Summary of Operating Loss and Tax Credit Carryforwards) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Charitable Contributions	$ 1,559
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss, subject to expiration	205,918
Net operating loss, not subject to expiration	185,779
Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards		$ 85,000
Research and Development Tax Credit Carryforward [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	6,550
Enhanced Oil Recovery Credit [Member] | Federal [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	26,790
Pennsylvania [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	428,672
California [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	224,159
California [Member] | Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	8,864
California [Member] | Enhanced Oil Recovery Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	$ 8,502

Capitalization And Short-Term_3

Capitalization And Short-Term Borrowings (Narrative) (Details)	Jun. 03, 2020USD ($)	Jun. 02, 2020USD ($)$ / sharesshares	Aug. 17, 2018USD ($)	Sep. 30, 2020USD ($)$ / sharesshares	Sep. 30, 2019USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 07, 2018USD ($)	Sep. 27, 2017USD ($)
Debt Instrument [Line Items]
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan | shares				0
Common stock issued for 401(k) plans | shares				0
Shares tendered | shares				91,545
Share-Based Payment Expense				$ 13,100,000	$ 19,500,000	$ 14,200,000
Tax benefit related to stock-based compensation expense				2,100,000	3,800,000	3,400,000
Capitalized stock-based compensation costs				100,000	100,000	100,000
Unamortized Debt Expense				12,297,000	14,005,000
Gain (Loss) on Extinguishment of Debt						1,000,000
Net proceeds from issuance of long-term debt				493,007,000	0	$ 295,020,000
Principal amounts of long-term debt maturing in 2021				0
Principal amounts of long-term debt maturing in 2022				500,000,000
Principal amounts of long-term debt maturing in 2023				549,000,000
Principal amounts of long-term debt maturing in 2024				0
Principal amounts of long-term debt maturing in 2025				500,000,000
Principal amounts of long-term debt maturing after 2025				1,100,000,000
Commercial paper, outstanding				15,000,000	$ 55,200,000
Short-term notes payable outstanding				$ 15,000,000
Committed credit facility maximum debt to capitalization ratio				0.65
Ceiling Test Impairment Adjustment				50.00%
Ceiling Test Impairment Maximum Adjustment				$ 250,000,000
Debt to capitalization ratio				0.55
Additional borrowing				$ 1,300,000,000
Aggregated indebtedness				$ 40,000,000
Preferred stock, shares authorized | shares				10,000,000
Preferred stock par value | $ / shares				$ 1
Percentage of Long-Term Debt issued under 1974 Indenture				3.70%
Common Stock, Par Value | $ / shares				$ 1	$ 1
Cumulative after-tax ceiling test impairments since July 1, 2018				$ 326,300,000
Committed Credit Facility Debt to Capitalization Ratio Ceiling Test Impairment Adjustment Amount				163,100,000
Tax expense related to stock-based compensation exercises and vestings				$ 3,200,000
Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Weighted average interest rate				1.51%
June 2, 2020 Public Offering of Common Stock [Member]
Debt Instrument [Line Items]
Common Stock Issued from Sale of Common Stock (Shares) | shares		4,370,000
Common Stock, Par Value | $ / shares		$ 1
Common Stock Issued, Price Per Share | $ / shares		$ 39.50
Proceeds from Issuance of Common Stock		$ 165,800,000
Stock Appreciation Rights (SARs) [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares				0	0	0
Total intrinsic value of SAR's exercised					$ 7,200,000	$ 4,400,000
Number of Awards Vested | shares				0	0	0
Restricted Share Awards [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares				0	0	0
Weighted Average Fair Value per Award Granted | $ / shares				$ 0
Number of Awards Vested | shares				0
Unrecognized compensation expense				$ 100,000
Unrecognized compensation expense recognized weighted average period				1 month 6 days
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares				150,839	123,939	89,672
Weighted Average Fair Value per Award Granted | $ / shares				$ 40.38	$ 49.40	$ 51.23
Number of Awards Vested | shares				87,835
Unrecognized compensation expense				$ 6,300,000
Unrecognized compensation expense recognized weighted average period				2 years 1 month 6 days
Performance Shares [Member]
Debt Instrument [Line Items]
Common stock issued | shares				231,246
Number of Shares Granted | shares				254,608	244,734	208,588
Weighted Average Fair Value per Award Granted | $ / shares				$ 43.32	$ 55.67	$ 50.95
Number of Awards Vested | shares				231,246
Unrecognized compensation expense				$ 10,600,000
Unrecognized compensation expense recognized weighted average period				1 year 8 months 12 days
Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Common stock issued | shares				87,835
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued | shares				41,873
3.95% Notes Due September 15, 2027 [Member]
Debt Instrument [Line Items]
Long-term debt, face value								$ 300,000,000
Long-term debt, interest rate								3.95%
4.75% Notes Due September 1, 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, face value			$ 300,000,000
Long-term debt, interest rate			4.75%
Net proceeds from issuance of long-term debt			$ 295,000,000
8.75% Notes Due May 2019 [Member]
Debt Instrument [Line Items]
Long-term debt, face value							$ 250,000,000
Long-term debt, interest rate							8.75%
Debt Instrument redeemed						$ 259,500,000
Unamortized Debt Expense						8,500,000
6.50% Notes Due April 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, face value						$ 300,000,000
Long-term debt, interest rate						6.50%
Debt Instrument redeemed						$ 307,000,000
5.50% Notes Due January 15, 2026 [Member]
Debt Instrument [Line Items]
Long-term debt, face value	$ 500,000,000
Long-term debt, interest rate	5.50%
Net proceeds from issuance of long-term debt	$ 493,000,000
5.50% Notes Due January 15, 2026 [Member] | Maximum [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate				7.50%
Indenture From 1974 [Member]
Debt Instrument [Line Items]
Carrying Amount				$ 99,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper available				$ 500,000,000
Weighted average interest rate				0.25%	2.50%
4.90% Notes Due December 2021 [Member]
Debt Instrument [Line Items]
Long-term debt, face value				$ 500,000,000
Long-term debt, interest rate				4.90%
Fourth Amended & Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 750,000,000
364-Day Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 200,000,000
2021 [Member] | Restricted Share Awards [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				20,000
2021 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				105,960
2021 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				169,912
2022 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				97,870
2022 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				176,160
2023 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				82,373
2023 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				246,556
2024 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				32,570
2025 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				17,000

Capitalization And Short-Term_4

Capitalization And Short-Term Borrowings (Summary Of Changes In Common Stock Equity) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended												12 Months Ended
		Sep. 30, 2020		Jun. 30, 2020	[2]	Mar. 31, 2020	[3]	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2020		Sep. 30, 2019	Sep. 30, 2018
Schedule of Capitalization [Line Items]
Beginning balance (shares)								86,315,287						86,315,287
Beginning balance								$ 832,264						$ 832,264
Balance at Beginning of Year								1,272,601				$ 1,098,900		1,272,601		$ 1,098,900	$ 851,669
Beginning balance								(52,155)				(67,750)		(52,155)		(67,750)
Net Income (Loss) Available for Common Stock		$ (145,545)	[1]	$ 41,250		$ (106,068)		$ 86,591	$ 47,282	$ 63,753	$ 90,595	$ 102,660	[4]	(123,772)		304,290	391,521
Dividends Declared on Common Stock														(156,249)		(148,432)	(144,290)
Other Comprehensive Income (Loss), Net of Tax														(62,602)		15,595	(37,627)
Share-Based Payment Expense														$ 13,100		$ 19,500	14,200
Ending balance (Shares)		90,954,696							86,315,287					90,954,696		86,315,287
Ending balance		$ 1,004,158							$ 832,264					$ 1,004,158		$ 832,264
Balance at End of Year		991,630							1,272,601					991,630		1,272,601	1,098,900
Ending balance		(114,757)							$ (52,155)					$ (114,757)		$ (52,155)	$ (67,750)
Dividend per share														$ 1.76		$ 1.72	$ 1.68
Accumulated earnings free from limitations		$ 848,400												$ 848,400
Common Stock [Member]
Schedule of Capitalization [Line Items]
Beginning balance (shares)								86,315,000				85,957,000		86,315,000		85,957,000	85,543,000
Beginning balance (value)								$ 86,315				$ 85,957		$ 86,315		$ 85,957	$ 85,543
Common Stock Issued from Sale of Common Stock (Shares)														4,370,000
Common Stock Issued from Sale of Common Stock (Value)														$ 4,370
Common Stock Issued Under Stock and Benefit Plans (Shares)														270,000		358,000	414,000
Common Stock Issued Under Stock and Benefit Plans (Value)														$ 270		$ 358	$ 414
Ending balance (Shares)		90,955,000							86,315,000					90,955,000		86,315,000	85,957,000
Ending balance (Value)		$ 90,955							$ 86,315					$ 90,955		$ 86,315	$ 85,957
Paid In Capital [Member]
Schedule of Capitalization [Line Items]
Beginning balance								832,264				820,223		832,264		820,223	796,646
Share-Based Payment Expense	[5]													13,180		19,613	14,235
Common Stock Issued from Sale of Common Stock (Value)														161,399
Common Stock Issued Under Stock and Benefit Plans (Value)																	9,342
Stock Repurchased under Stock and Benefit Plans														(2,685)		(7,572)
Ending balance		1,004,158							832,264					1,004,158		832,264	820,223
Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year								1,272,601				1,098,900		1,272,601		1,098,900	851,669
Net Income (Loss) Available for Common Stock														(123,772)		304,290	391,521
Dividends Declared on Common Stock														(156,249)		(148,432)	(144,290)
Balance at End of Year		991,630	[6]						1,272,601					991,630	[6]	1,272,601	1,098,900
Accumulated Other Comprehensive Income (Loss) [Member]
Schedule of Capitalization [Line Items]
Beginning balance								(52,155)				(67,750)		(52,155)		(67,750)	(30,123)
Other Comprehensive Income (Loss), Net of Tax														(62,602)		15,595	(37,627)
Ending balance		$ (114,757)							(52,155)					(114,757)		(52,155)	(67,750)
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year								0				7,437		0		7,437	0
Balance at End of Year									0							0	7,437
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member] | Earnings Reinvested In The Business [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year												7,437				7,437
Balance at End of Year																	7,437
Guidance for Reclassification of Stranded Tax Effects [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year								0				10,406		0		10,406	0
Balance at End of Year									0							0	10,406
Guidance for Reclassification of Stranded Tax Effects [Member] | Earnings Reinvested In The Business [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year												10,406				10,406
Balance at End of Year																	10,406
Guidance for Hedging [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year								(950)				$ 0		(950)		0	0
Balance at End of Year									(950)							(950)	$ 0
Guidance for Hedging [Member] | Earnings Reinvested In The Business [Member] | Cumulative Effect of Adoption of Authoritative Guidance [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year								$ (950)						$ (950)
Balance at End of Year									$ (950)							$ (950)
[1]	Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.
[4]	Includes a $5.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[5]	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.
[6]	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, 2020, $848.4 million of accumulated earnings was free of such limitations.

Capitalization And Short-Term_5

Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Share Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Schedule of Capitalization [Line Items]
Number of Shares available for future grant	[1]	3,220,528
Performance Shares [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		522,514
Number of Shares Granted		254,608	244,734	208,588
Number of Awards Vested		(231,246)
Number of Shares Forfeited		(11,040)
Change in Units Based on Performance Achieved		(57,792)
Number of Shares Outstanding, End of Year		592,628	522,514
Weighted Average Fair Value per Award, Beginning of Year		$ 54.37
Weighted Average Fair Value per Award Granted		43.32	$ 55.67	$ 50.95
Weighted Average Fair Value per Award Vested		55.33
Weighted Average Fair Value per Award Forfeited		46.40
Weighted Average Fair Value per Award, Change in Units Based on Performance Achieved		52.13
Weighted Average Fair Value per Award, End of Year		$ 49.18	$ 54.37
Stock Appreciation Rights (SARs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		733,132
Number of Shares Granted		0	0	0
Number of Shares Exercised		0
Number of Awards Vested		0	0	0
Number of Shares Forfeited		0
Number of Shares Expired		(219,952)
Number of Shares Outstanding, End of Year		513,180	733,132
Number of SARs exercisable		513,180
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 54.90
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		0
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Expired		52.18
Weighted Average Exercise Price, Outstanding End of Year		56.07	$ 54.90
Weighted Average Exercise Price, SARs exercisable		$ 56.07
Weighted Average Remaining Contractual Life, Outstanding		1 year 3 months 10 days
Weighted Average Remaining Contractual Life, SARs exercisable		1 year 3 months 10 days
Aggregate Intrinsic Value Outstanding		$ 0
Aggregate Intrinsic Value, SARs exercisable		$ 0
[1]	Includes shares available for options, SARs, restricted stock and performance share grants.

Capitalization And Short-Term_6

Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Restricted Share Awards [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year	20,000
Number of Shares Granted	0	0	0
Number of Awards Vested	0
Number of Shares Forfeited	0
Number of Shares Outstanding, End of Year	20,000	20,000
Weighted Average Fair Value per Award, Beginning of Year	$ 47.46
Weighted Average Fair Value per Award Granted	0
Weighted Average Fair Value per Award Vested	0
Weighted Average Fair Value per Award Forfeited	0
Weighted Average Fair Value per Award, End of Year	$ 47.46	$ 47.46
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year	281,607
Number of Shares Granted	150,839	123,939	89,672
Number of Awards Vested	(87,835)
Number of Shares Forfeited	(8,838)
Number of Shares Outstanding, End of Year	335,773	281,607
Weighted Average Fair Value per Award, Beginning of Year	$ 48.88
Weighted Average Fair Value per Award Granted	40.38	$ 49.40	$ 51.23
Weighted Average Fair Value per Award Vested	50.26
Weighted Average Fair Value per Award Forfeited	46.72
Weighted Average Fair Value per Award, End of Year	$ 44.76	$ 48.88

Capitalization And Short-Term_7

Capitalization And Short-Term Borrowings (Weighted Average Assumptions Used In Estimating Fair Value) (Details) - Performance Shares [Member]	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk Free Interest Rate	1.63%	2.61%	1.96%
Remaining Term at Date of Grant (Years)	2 years 9 months 21 days	2 years 9 months 10 days	2 years 9 months 10 days
Expected Volatility Rate	19.30%	20.20%	22.00%

Capitalization And Short-Term_8

Capitalization And Short-Term Borrowings (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Jun. 03, 2020	Aug. 17, 2018	Sep. 27, 2017
Debt Instrument [Line Items]
Total Long-Term Debt		$ 2,649,000	$ 2,149,000
Less Unamortized Discount and Debt Issuance Costs		19,424	15,282
Less Current Portion	[1]	0	0
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		$ 2,629,576	2,133,718
4.75% Notes Due September 1, 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, face value					$ 300,000
Long-term debt, interest rate					4.75%
Maximum interest rate adjustment		2.00%
3.95% Notes Due September 15, 2027 [Member]
Debt Instrument [Line Items]
Long-term debt, face value						$ 300,000
Long-term debt, interest rate						3.95%
Maximum interest rate adjustment		2.00%
7.4% Due March 2023 To June 2025 [Member]
Debt Instrument [Line Items]
Medium-Term Notes	[2]	$ 99,000	$ 99,000
Long-term debt, interest rate		7.40%	7.40%
3.75% To 5.50% Due December 2021 To September 2028 [Member]
Debt Instrument [Line Items]
Notes	[2],[3],[4]	$ 2,550,000	$ 2,050,000
Percentage of principal amount		101.00%	101.00%
5.50% Notes Due January 15, 2026 [Member]
Debt Instrument [Line Items]
Long-term debt, face value				$ 500,000
Long-term debt, interest rate				5.50%
Maximum interest rate adjustment		2.00%
Minimum [Member] | 3.75% To 5.50% Due December 2021 To September 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate		3.75%	3.75%
Maximum [Member] | 3.75% To 5.50% Due December 2021 To September 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate		5.50%	5.50%
Maximum [Member] | 5.50% Notes Due January 15, 2026 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate		7.50%
[1]	None of the Company's long-term debt at September 30, 2020 and 2019 will mature within the following twelve-month period.
[2]	The Medium-Term Notes and Notes are unsecured.
[3]	The interest rate payable on $300.0 million of 4.75% notes and $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to a maximum adjustment of 2.00% such that the coupon will not exceed 7.5% if there is a downgrade of the credit rating assigned to the notes. 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 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.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($)	Sep. 30, 2020	Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Hedging collateral deposits	$ 0	$ 6,832,000	[1]	$ 3,441,000	$ 1,741,000
Level 1 or Level 2 Transfers	0	0
Derivative Financial Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Level 3 Fair Value	0	0
Level 1 or Level 2 Transfers	$ 0	0
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Hedging collateral deposits		6,832,000
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Hedging collateral deposits		6,800,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Hedging collateral deposits		$ 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 (Recurr

Fair Value Measurements (Recurring Fair Value Measures Of Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2020	Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 12,285	$ 10,521
Hedging Collateral Deposits		0	6,832	[1]	$ 3,441	$ 1,741
Total Assets	[1]	134,014	169,742
Total Liabilities	[1]	43,969	5,574
Total Net Assets/(Liabilities)	[1]	90,045	164,168
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]		0
Derivative Liability	[1]		5,094
Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	10,018	50,593
Derivative Liability	[1]	34,880	188
Over Counter No Cost Collars - Gas
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(720)
Derivative Liability	[1]	7,451
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(79)	(2,047)
Derivative Liability	[1]	1,638	292
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	39,618	40,660
Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	72,253	62,339
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	639	844
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		12,285	10,521
Hedging Collateral Deposits			6,832
Total Assets		124,795	123,251
Total Liabilities		0	7,149
Total Net Assets/(Liabilities)		124,795	116,102
Fair Value, Inputs, Level 1 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset			2,055
Derivative Liability			7,149
Fair Value, Inputs, Level 1 [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 1 [Member] | Over Counter No Cost Collars - Gas
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0
Derivative Liability		0
Fair Value, Inputs, Level 1 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 1 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		39,618	40,660
Fair Value, Inputs, Level 1 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		72,253	62,339
Fair Value, Inputs, Level 1 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		639	844
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		0	0
Hedging Collateral Deposits			0
Total Assets		36,677	52,081
Total Liabilities		71,427	4,015
Total Net Assets/(Liabilities)		(34,750)	48,066
Fair Value, Inputs, Level 2 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset			0
Derivative Liability			0
Fair Value, Inputs, Level 2 [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		36,418	52,076
Derivative Liability		61,280	1,671
Fair Value, Inputs, Level 2 [Member] | Over Counter No Cost Collars - Gas
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0
Derivative Liability		8,171
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		259	5
Derivative Liability		1,976	2,344
Fair Value, Inputs, Level 2 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		0	0
Hedging Collateral Deposits			0
Total Assets		0	0
Total Liabilities		0	0
Total Net Assets/(Liabilities)		0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset			0
Derivative Liability			0
Fair Value, Inputs, Level 3 [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Over Counter No Cost Collars - Gas
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0
Derivative Liability		0
Fair Value, Inputs, Level 3 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Netting Adjustments [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	0	0
Hedging Collateral Deposits	[1]		0
Total Assets	[1]	(27,458)	(5,590)
Total Liabilities	[1]	(27,458)	(5,590)
Total Net Assets/(Liabilities)	[1]	0	0
Netting Adjustments [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]		(2,055)
Derivative Liability	[1]		(2,055)
Netting Adjustments [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(26,400)	(1,483)
Derivative Liability	[1]	(26,400)	(1,483)
Netting Adjustments [Member] | Over Counter No Cost Collars - Gas
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(720)
Derivative Liability	[1]	(720)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(338)	(2,052)
Derivative Liability	[1]	(338)	(2,052)
Netting Adjustments [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	0	0
Netting Adjustments [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	0	0
Netting Adjustments [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
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.

Financial Instruments (Narrativ

Financial Instruments (Narrative) (Details)	12 Months Ended
	Sep. 30, 2020USD ($)counterpartybblMMcf	Sep. 30, 2019USD ($)		Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Foreign Currency Forward Contract Hedge Duration	10 years
Pre-tax Net hedging gains (losses) reclassified within twelve months	$ 26,700,000
After tax Net hedging gains (losses) reclassified within twelve months	19,100,000
Fair market value of derivative asset with a credit-risk related contingency	8,600,000
Fair market value of derivative liability with a credit-risk related contingency	44,000,000
Hedging collateral deposits	0	$ 6,832,000	[1]	$ 3,441,000	$ 1,741,000
Net Hedging Gains (Losses) in Accumulated Other Comprehensive Income (Loss)	34,800,000
After tax net hedging gains (losses) in accumulated other comprehensive income (Loss)	24,900,000
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)		$ 2,100,000
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount	$ 78,000,000
Cash Flow Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedge Duration	5 years
Over the Counter Swaps, No Cost Collars and Foreign Currency Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties in which the company holds over-the-counter swap positions | counterparty	17
Number of counterparties in net gain position | counterparty	8
Credit risk exposure per counterparty	$ 1,200,000
Maximum credit risk exposure per counterparty	3,900,000
Collateral Received from Counterparties by the Company	0
Hedging collateral deposits	$ 0
Over the Counter Swaps, No Cost Collars and Foreign Currency Forward Contracts [Member] | Credit Risk Related Contingency Feature [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties with a common credit-risk related contingency | counterparty	15
Cash Flow Hedges [Member] | Natural Gas MMCf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas | MMcf	286,700
Cash Flow Hedges [Member] | Crude Oil Bbls [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivative, crude oil | bbl	1,548,000
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Financial Instruments (Long-Ter

Financial Instruments (Long-Term Debt) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,629,576	$ 2,133,718
Fair Value	$ 2,778,556	$ 2,257,085

Financial Instruments (Other In

Financial Instruments (Other Investments) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019
Investment Holdings [Line Items]
Life Insurance Contracts	$ 41,992	$ 41,074
Other Investments	154,502	144,917
Equity Mutual Fund [Member]
Investment Holdings [Line Items]
Fair Value	39,618	40,660
Fixed Income Mutual Fund [Member]
Investment Holdings [Line Items]
Fair Value	72,253	62,339
Marketable Equity Securities [Member]
Investment Holdings [Line Items]
Fair Value	$ 639	$ 844

Financial Instruments (Schedule

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, 2020	Sep. 30, 2019	Sep. 30, 2018
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)	$ 9,862
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	93,295
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss)		$ 79,301	$ (74,103)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income		(5,464)
Foreign Currency Contracts [Member] | Operating Revenues [Member]
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)	(434)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	(1,057)
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss)		(2,646)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income		(822)
Commodity Contracts [Member] | Operating Revenues [Member]
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)	9,905
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	93,691
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss)		82,984
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income		(3,460)
Commodity Contracts [Member] | Purchased Gas [Member]
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)	391
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	$ 661
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss)		(1,037)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income		$ (1,182)

Retirement Plan And Other Pos_3

Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Decrease to accumulated other comprehensive income	$ 85,973,000	$ (36,270,000)	$ 57,283,000
Effect of one percentage point increase on accumulated postretirement benefit obligation	61,700,000
Effect of one percentage point increase on service and interest cost components	2,500,000
Effect of one percentage point decrease on accumulated postretirement benefit obligation	51,500,000
Effect of one percentage point decrease on service and interest cost components	1,800,000
Level 1 or Level 2 Transfers	0	0
Benefit assets transferred in/out of Level 3	0	0
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	8,900,000	7,600,000	6,800,000
Accumulated benefit obligation	78,700,000	79,800,000	70,600,000
Benefit obligation	$ 98,100,000	$ 99,500,000	$ 86,100,000
Discount rate	1.92%	2.77%	4.02%
Rate of compensation increase	8.00%	8.00%	7.75%
Tax-Deferred Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	$ 6,700,000	$ 6,400,000	$ 6,200,000
Retirement Savings Account [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	4,200,000	3,900,000	3,500,000
Other Than Veba Trust And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	300,000
Non-Qualified Benefit Plans, Other Post-Retirement Benefit Plan And Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Decrease in other regulatory assets	3,800,000
Decrease to accumulated other comprehensive income	3,900,000
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	24,657,000	19,907,000	28,382,000
Accumulated benefit obligation	1,096,427,000	1,053,914,000	946,763,000
Benefit obligation	$ 1,139,105,000	$ 1,097,625,000	$ 985,690,000	$ 1,054,826,000
Discount rate	2.66%	3.15%	4.30%
Rate of compensation increase	4.70%	4.70%	4.70%
Employer Contributions	$ 24,621,000	$ 29,215,000	$ 32,980,000
Expected future benefit payments in year one	66,800,000
Expected future benefit payments in year two	67,200,000
Expected future benefit payments in year three	67,400,000
Expected future benefit payments in year four	67,400,000
Expected future benefit payments in year five	67,100,000
Expected future benefit payments in five years thereafter	$ 326,800,000
Expected long term rate of return on plan assets	6.40%	6.75%	7.00%
Retirement Plan [Member] | Discount Rate Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ 61,300,000	$ 128,400,000	$ (58,100,000)
Retirement Plan [Member] | Other Actuarial Experience [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	7,900,000
Retirement Plan [Member] | Mortality Improvement Projection Scale [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(3,300,000)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	10,992,000	10,521,000	10,306,000
Benefit obligation	$ 476,722,000	$ 468,163,000	$ 435,986,000	$ 462,619,000
Discount rate	2.71%	3.17%	4.31%
Rate of compensation increase	4.70%	4.70%	4.70%
Employer Contributions	$ 3,080,000	$ 3,064,000	$ 2,896,000
Expected future benefit payments in year one	28,361,000
Expected future benefit payments in year two	28,820,000
Expected future benefit payments in year three	29,085,000
Expected future benefit payments in year four	29,192,000
Expected future benefit payments in year five	29,231,000
Expected future benefit payments in five years thereafter	$ 143,696,000
Expected long term rate of return on plan assets	5.70%	6.00%	6.25%
Other Post-Retirement Benefit Plans [Member] | Discount Rate Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ 25,400,000	$ 57,200,000	$ (25,800,000)
Other Post-Retirement Benefit Plans [Member] | Other Actuarial Experience [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(6,500,000)	(18,900,000)	7,300,000
Other Post-Retirement Benefit Plans [Member] | Mortality Improvement Projection Scale [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(2,500,000)	(3,900,000)	(2,400,000)
VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	$ 2,800,000
Effective Fiscal 2021 [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	6.00%
Effective Fiscal 2021 [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	5.40%
Minimum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 15,000,000
Minimum [Member] | VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 2,500,000
Minimum [Member] | Equity Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	30.00%
Minimum [Member] | Fixed Income Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	50.00%
Minimum [Member] | Other Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	0.00%
Maximum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 25,000,000
Maximum [Member] | VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 3,000,000
Maximum [Member] | Equity Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	50.00%
Maximum [Member] | Fixed Income Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	70.00%
Maximum [Member] | Other Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	15.00%
Other Accruals And Current Liabilities [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 14,460,000	13,194,000	11,500,000
Non-Current [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 83,600,000	$ 86,300,000	$ 74,600,000

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, 2020	Sep. 30, 2019	Sep. 30, 2018
Defined Benefit Plan Disclosure [Line Items]
Non-Current Assets		$ 76,035	$ 60,517
Amortization period		10 years
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 1,097,625	985,690	$ 1,054,826
Service Cost		9,318	8,482	9,921
Interest Cost		29,930	38,378	33,006
Plan Participants' Contributions		0	0	0
Retiree Drug Subsidy Receipts		0	0	0
Actuarial (Gain) Loss		65,908	127,748	(50,218)
Benefits Paid		(63,676)	(62,673)	(61,845)
Benefit Obligation at End of Period		1,139,105	1,097,625	985,690
Fair Value of Assets at Beginning of Period		968,449	924,506	910,719
Actual Return on Plan Assets		87,402	77,401	42,652
Employer Contributions		24,621	29,215	32,980
Plan Participants' Contributions		0	0	0
Benefits Paid		(63,676)	(62,673)	(61,845)
Fair Value of Assets at End of Period		1,016,796	968,449	924,506
Net Amount Recognized at End of Period (Funded Status)		(122,309)	(129,176)	(61,184)
Non-Current Liabilities		(122,309)	(129,176)	(61,184)
Non-Current Assets		0	0	0
Accumulated Benefit Obligation		$ 1,096,427	$ 1,053,914	$ 946,763
Discount Rate		2.66%	3.15%	4.30%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Expected Return on Plan Assets		$ (60,063)	$ (62,368)	$ (61,715)
Amortization of Prior Service Cost (Credit)		729	826	938
Recognition of Actuarial Loss	[1]	39,384	32,096	37,205
Net Amortization and Deferral for Regulatory Purposes		5,359	2,493	9,027
Net Periodic Benefit Cost		$ 24,657	$ 19,907	$ 28,382
Effective Discount Rate for Benefit Obligations		3.15%	4.30%	3.77%
Effective Rate for Interest on Benefit Obligations		2.81%	4.03%	3.23%
Effective Discount Rate for Service Cost		3.31%	4.40%	4.00%
Effective Rate for Interest on Service Cost		3.12%	4.29%	3.73%
Expected Return on Plan Assets		6.40%	6.75%	7.00%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 468,163	$ 435,986	$ 462,619
Service Cost		1,609	1,519	1,830
Interest Cost		12,913	17,145	14,801
Plan Participants' Contributions		3,058	2,930	2,894
Retiree Drug Subsidy Receipts		1,411	1,855	1,545
Actuarial (Gain) Loss		16,396	34,401	(21,039)
Benefits Paid		(26,828)	(25,673)	(26,664)
Benefit Obligation at End of Period		476,722	468,163	435,986
Fair Value of Assets at Beginning of Period		524,127	513,800	514,017
Actual Return on Plan Assets		44,448	30,006	20,657
Employer Contributions		3,080	3,064	2,896
Plan Participants' Contributions		3,058	2,930	2,894
Benefits Paid		(26,828)	(25,673)	(26,664)
Fair Value of Assets at End of Period		547,885	524,127	513,800
Net Amount Recognized at End of Period (Funded Status)		71,163	55,964	77,814
Non-Current Liabilities		(4,872)	(4,553)	(4,919)
Non-Current Assets		$ 76,035	$ 60,517	$ 82,733
Discount Rate		2.71%	3.17%	4.31%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Expected Return on Plan Assets		$ (29,232)	$ (30,157)	$ (31,482)
Amortization of Prior Service Cost (Credit)		(429)	(429)	(429)
Recognition of Actuarial Loss	[1]	535	5,962	10,558
Net Amortization and Deferral for Regulatory Purposes		25,596	16,481	15,028
Net Periodic Benefit Cost		$ 10,992	$ 10,521	$ 10,306
Effective Discount Rate for Benefit Obligations		3.17%	4.31%	3.81%
Effective Rate for Interest on Benefit Obligations		2.84%	4.05%	3.29%
Effective Discount Rate for Service Cost		3.39%	4.43%	4.10%
Effective Rate for Interest on Service Cost		3.30%	4.39%	3.98%
Expected Return on Plan Assets		5.70%	6.00%	6.25%
Rate of Compensation Increase		4.70%	4.70%	4.70%
[1]	Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.

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, 2020USD ($)	[1]
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	$ (34,065)
Prior Service (Cost) Credit	0
Net Amount Recognized	(34,065)
Increase in Actuarial Loss, excluding amortization	(5,929)	[2]
Change due to Amortization of Actuarial Loss	5,341
Prior Service (Cost) Credit	0
Net Change	(588)
Net Actuarial Loss	(5,852)
Prior Service (Cost) Credit	0
Net Amount Expected to be Recognized	(5,852)
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(215,330)
Prior Service (Cost) Credit	(3,641)
Net Amount Recognized	(218,971)
Increase in Actuarial Loss, excluding amortization	(38,568)	[2]
Change due to Amortization of Actuarial Loss	39,384
Prior Service (Cost) Credit	729
Net Change	1,545
Net Actuarial Loss	(36,814)
Prior Service (Cost) Credit	(631)
Net Amount Expected to be Recognized	(37,445)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(28,044)
Prior Service (Cost) Credit	2,401
Net Amount Recognized	(25,643)
Increase in Actuarial Loss, excluding amortization	(1,180)	[2]
Change due to Amortization of Actuarial Loss	535
Prior Service (Cost) Credit	(429)
Net Change	(1,074)
Net Actuarial Loss	(849)
Prior Service (Cost) Credit	429
Net Amount Expected to be Recognized	$ (420)
[1]	Amounts presented are shown before recognizing deferred taxes.
[2]	Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.

Retirement Plan And Other Pos_6

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Expected Benefit Payments) (Details) - Other Post-Retirement Benefit Plans [Member] $ in Thousands	Sep. 30, 2020USD ($)
Defined Benefit Plan Disclosure [Line Items]
2021 - Benefit Payments	$ 28,361
2021 - Subsidy Receipts	(1,950)
2022 - Benefit Payments	28,820
2022 - Subsidy Receipts	(2,064)
2023 - Benefit Payments	29,085
2023 - Subsidy Receipts	(2,172)
2024 - Benefit Payments	29,192
2024 - Subsidy Receipts	(2,273)
2025 - Benefit Payments	29,231
2025 - Subsidy Receipts	(2,356)
2026 through 2030 - Benefit Payments	143,696
2026 through 2030 - Subsidy Receipts	$ (12,763)

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, 2020	Sep. 30, 2019	Sep. 30, 2018
Retirement Benefits [Abstract]
Rate of Medical Cost Increase for Pre Age 65 Participants	[1]	5.42%	5.50%	5.59%
Rate of Medical Cost Increase for Post Age 65 Participants	[1]	4.75%	4.75%	4.75%
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	[1]	6.80%	7.35%	7.89%
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	[1]	4.75%	4.75%	4.75%
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	[1]	6.20%	6.84%	7.18%
Ultimate Health Care Trend Rate		4.50%	4.50%	4.50%
[1]	It was assumed that this rate would gradually decline to 4.5% by 2039.

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, 2020		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ 1,016,796		$ 968,449	$ 924,506	$ 910,719
Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	188,939		175,812
Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	94,603		81,631
Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	77,736		70,095
Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	512,693		493,839
Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	20,201		17,744
Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	79,595		75,329
Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		106,167		107,764
Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		18,023		18,310
Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		1,097,957		1,040,524
Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(80,511)		(73,688)
Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		1,017,446		966,836
Retirement Plan [Member] | Miscellaneous Accruals, Interest Receivables, And Non-Interest Cash [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(650)		1,613
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		547,885		524,127	$ 513,800	$ 514,017
Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		13,841		8,229
Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		80,511		73,688
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		153,923		167,966
Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		301,290		275,296
Other Post-Retirement Benefit Plans [Member] | Miscellaneous Accruals Including Current and Deferred Taxes Claims Incurred But Not Reported Administrative [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(1,680)		(1,052)
Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		469,054		451,491
Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		549,565		525,179
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	118,124		114,324
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	0		0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	0		0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	2,000		1,784
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	0		0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	0		0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		120,124		116,108
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(8,809)		(8,205)
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		111,315		107,903
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		8,809		8,205
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		301,290		275,296
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		301,290		275,296
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		310,099		283,501
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	0		0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	0		0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	0		0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	457,381		439,255
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	20,201		17,744
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	0		0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		477,582		456,999
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(35,021)		(32,295)
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		442,561		424,704
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		35,021		32,295
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		0		0
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		35,021		32,295
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		471		3,154
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		471		3,154
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(35)		(223)
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		436		2,931
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		35		223
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0		0
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		0		0
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals		35		223
Measured at NAV [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1],[7]	70,815		61,488
Measured at NAV [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2],[7]	94,603		81,631
Measured at NAV [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3],[7]	77,736		70,095
Measured at NAV [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4],[7]	53,312		52,800
Measured at NAV [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5],[7]	0		0
Measured at NAV [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6],[7]	79,595		75,329
Measured at NAV [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	105,696		104,610
Measured at NAV [Member] | Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	18,023		18,310
Measured at NAV [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals	[7]	499,780		464,263
Measured at NAV [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	(36,646)		(32,965)
Measured at NAV [Member] | Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals	[7]	463,134		431,298
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	13,841		8,229
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	36,646		32,965
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		153,923	[7]	167,966
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	0		0
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals	[7]	167,764		176,195
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments, Subtotals	[7]	$ 204,410		$ 209,160
[1]	Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
[2]	International Equities are comprised of collective trust funds.
[3]	Global Equities are comprised of collective trust funds.
[4]	Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
[5]	International Fixed Income securities are comprised mostly of corporate/government bonds.
[6]	Global Fixed Income securities are comprised of a collective trust fund.
[7]	Reflects the authoritative guidance related to investments measured at net asset value (NAV).

Retirement Plan And Other Pos_9

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Significant Unobservable Input Changes In Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	$ 2,931	$ 2,976
Unrealized Gains/(Losses)	(2,495)	(42)
Sales	0	(3)
Balance, End of Year	436	2,931
Retirement Plan [Member] | Excluding 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	(223)	(218)
Unrealized Gains/(Losses)	188	(5)
Sales	0	0
Balance, End of Year	(35)	(223)
Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	3,154	3,194
Unrealized Gains/(Losses)	(2,683)	(37)
Sales	0	(3)
Balance, End of Year	471	3,154
Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	223	218
Unrealized Gains/(Losses)	(188)	5
Sales	0	0
Balance, End of Year	$ 35	$ 223

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2020USD ($)
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 6.4
Future purchase obligation first year	181.9
Future purchase obligation second year	111.3
Future purchase obligation third year	120.9
Future purchase obligation fourth year	129.3
Future purchase obligation fifth year	146.3
Future purchase obligation thereafter	1,128.2
Former Manufactured Gas Plant Site New York [Member]
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 3.4
Environmental Site Remediation Costs [Member]
Site Contingency [Line Items]
Rate recovery period	2 years
Pipeline And Storage, Gathering And Utility Segments [Member]
Site Contingency [Line Items]
Contract commitments first year	$ 98.3
Contract commitments second year	6.4
Contract commitments third year	3.4
Contract commitments fourth year	3.3
Contract commitments fifth year	3.3
Contract commitments thereafter	10.3
Exploration And Production [Member]
Site Contingency [Line Items]
Contract commitments first year	109.3
Contract commitments second year	15.2
Contract commitments third year	$ 0.7

Business Segment Information (N

Business Segment Information (Narrative) (Details)	12 Months Ended
	Sep. 30, 2020segment
Segment Reporting [Abstract]
Number of Reportable Segments	4

Business Segment Information (S

Business Segment Information (Segment Information By Segment) (Details) - USD ($) $ in Thousands		3 Months Ended												12 Months Ended
		Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Segment Reporting Information [Line Items]
Revenue		$ 287,989		$ 323,019		$ 491,095		$ 444,188	$ 293,341	$ 357,200	$ 552,544	$ 490,247		$ 1,546,291	$ 1,693,332	$ 1,592,668
Interest Income														5,007	6,065	6,766
Interest Expense														117,077	106,756	114,522
Depreciation, Depletion and Amortization														306,158	275,660	240,961
Income Tax Expense (Benefit)														18,739	85,221	(7,494)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties		253,400		18,200		177,800								449,438	0	0
Segment Profit: Net Income (Loss)		(145,545)	[1]	$ 41,250	[2]	$ (106,068)	[3]	$ 86,591	47,282	$ 63,753	$ 90,595	$ 102,660	[4]	(123,772)	304,290	391,521
Expenditures for Additions to Long-Lived Assets														1,228,617	781,246	600,602
Segment Assets		6,964,935							6,462,157					6,964,935	6,462,157	6,036,486
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue														607,453	632,740
Interest Income														698	1,107	1,479
Interest Expense														58,098	54,777	54,288
Depreciation, Depletion and Amortization														172,124	154,784	124,274
Income Tax Expense (Benefit)														(41,472)	32,978	(41,962)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														449,438
Segment Profit: Net Income (Loss)														(326,904)	111,807	180,632
Expenditures for Additions to Long-Lived Assets														670,455	491,889	380,677
Segment Assets		1,979,028							1,972,776					1,979,028	1,972,776	1,568,563
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue														309,604	288,283
Interest Income														1,475	2,982	2,748
Interest Expense														32,731	29,142	31,383
Depreciation, Depletion and Amortization														53,951	44,947	43,463
Income Tax Expense (Benefit)														28,613	23,238	17,806
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														0
Segment Profit: Net Income (Loss)														78,860	74,011	97,246
Expenditures for Additions to Long-Lived Assets														166,652	143,005	92,832
Segment Assets		2,204,971							1,893,514					2,204,971	1,893,514	1,848,180
Gathering [Member]
Segment Reporting Information [Line Items]
Revenue														142,893	127,075
Interest Income														545	546	1,106
Interest Expense														10,877	9,406	9,560
Depreciation, Depletion and Amortization														22,440	20,038	17,313
Income Tax Expense (Benefit)														18,191	20,895	(17,677)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														0
Segment Profit: Net Income (Loss)														68,631	58,413	83,519
Expenditures for Additions to Long-Lived Assets														297,806	49,650	61,728
Segment Assets		945,199							547,995					945,199	547,995	533,608
Utility [Member]
Segment Reporting Information [Line Items]
Revenue														652,298	727,442
Interest Income														2,262	1,809	1,591
Interest Expense														22,150	23,443	26,753
Depreciation, Depletion and Amortization														55,248	53,832	53,253
Income Tax Expense (Benefit)														13,274	13,967	15,258
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														0
Segment Profit: Net Income (Loss)														57,366	60,871	51,217
Expenditures for Additions to Long-Lived Assets														94,273	95,847	85,648
Segment Assets		2,067,852							1,991,338					2,067,852	1,991,338	1,921,971
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue														1,712,248	1,775,540
Interest Income														4,980	6,444	6,924
Interest Expense														123,856	116,768	121,984
Depreciation, Depletion and Amortization														303,763	273,601	238,303
Income Tax Expense (Benefit)														18,606	91,078	(26,575)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														449,438
Segment Profit: Net Income (Loss)														(122,047)	305,102	412,614
Expenditures for Additions to Long-Lived Assets														1,229,186	780,391	620,885
Segment Assets		7,197,050							6,405,623					7,197,050	6,405,623	5,872,322
All Other [Member]
Segment Reporting Information [Line Items]
Revenue														90,271	149,709
Interest Income														860	1,291	1,073
Interest Expense														66	21	22
Depreciation, Depletion and Amortization														1,716	1,291	1,902
Income Tax Expense (Benefit)														210	(955)	2,125
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														0
Segment Profit: Net Income (Loss)														(269)	(1,811)	261
Expenditures for Additions to Long-Lived Assets														39	128	41
Segment Assets		113,571							122,241					113,571	122,241	129,080
Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue														(256,228)	(231,917)
Interest Income														(833)	(1,670)	(1,231)
Interest Expense														(6,845)	(10,033)	(7,484)
Depreciation, Depletion and Amortization														679	768	756
Income Tax Expense (Benefit)														(77)	(4,902)	16,956
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties														0
Segment Profit: Net Income (Loss)														(1,456)	999	(21,354)
Expenditures for Additions to Long-Lived Assets														(608)	727	(20,324)
Segment Assets		$ (345,686)							$ (65,707)					(345,686)	(65,707)	35,084
Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													1,546,291	1,693,332	1,592,668
Revenue from External Customers [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													607,453	632,740	564,547
Revenue from External Customers [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													205,998	195,808	210,345
Revenue from External Customers [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													72	11	41
Revenue from External Customers [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													642,855	715,813	674,726
Revenue from External Customers [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													1,456,378	1,544,372	1,449,659
Revenue from External Customers [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													89,435	148,582	142,349
Revenue from External Customers [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													478	378	660
Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue														0	0	0
Intersegment Revenues [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue														0	0	0
Intersegment Revenues [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue														103,606	92,475	89,981
Intersegment Revenues [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue														142,821	127,064	107,856
Intersegment Revenues [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue														9,443	11,629	12,800
Intersegment Revenues [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue														255,870	231,168	210,637
Intersegment Revenues [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue														836	1,127	826
Intersegment Revenues [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue														$ (256,706)	$ (232,295)	$ (211,463)
[1]	Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.
[4]	Includes a $5.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[5]	All Revenue from External Customers originated in the United States.

Business Segment Information _2

Business Segment Information (Schedule Of Long-Lived Assets, By Geographical Areas) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-Lived Assets	$ 6,597,313	$ 6,099,534	$ 5,491,895

Quarterly Financial Data (Sched

Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Sep. 30, 2020		Jun. 30, 2020		Mar. 31, 2020		Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Operating Revenues	$ 287,989		$ 323,019		$ 491,095		$ 444,188	$ 293,341	$ 357,200	$ 552,544	$ 490,247		$ 1,546,291	$ 1,693,332	$ 1,592,668
Operating Income	(173,979)		80,397		(24,580)		148,020	83,940	112,827	153,359	161,683		29,858	511,809	519,723
Net Income Available for Common Stock	$ (145,545)	[1]	$ 41,250	[2]	$ (106,068)	[3]	$ 86,591	$ 47,282	$ 63,753	$ 90,595	$ 102,660	[4]	$ (123,772)	$ 304,290	$ 391,521
Earnings per Common Share, Basic	$ (1.60)		$ 0.47		$ (1.23)		$ 1	$ 0.55	$ 0.74	$ 1.05	$ 1.19		$ (1.41)	$ 3.53	$ 4.56
Earnings per Common Share, Diluted	$ (1.60)		$ 0.47		$ (1.23)		$ 1	$ 0.54	$ 0.73	$ 1.04	$ 1.18		$ (1.41)	$ 3.51	$ 4.53
Impairment of Oil and Gas Producing Properties	$ 253,400		$ 18,200		$ 177,800								$ 449,438	$ 0	$ 0
Impairment of Oil and Gas Producing Properties After Tax	183,700		$ 13,300		129,300
Valuation Allowance	$ 63,205				$ 56,800			$ 0					$ 63,205	$ 0
Increase (Reduction) to Income Tax Expense Due to Remeasurement of Deferred Income Tax Assets and Liabilites											$ (5,000)
[1]	Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.
[4]	Includes a $5.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.

Supplementary Information For_3

Supplementary Information For Oil And Gas Producing Activities (Narrative) (Details) $ in Millions, ft³ in Billions	12 Months Ended
	Sep. 30, 2020USD ($)ft³	Sep. 30, 2019USD ($)ft³	Sep. 30, 2018USD ($)ft³	Sep. 30, 2017	Sep. 30, 2016
Reserve Quantities [Line Items]
Amount spent for developing proved undeveloped reserves | $	$ 219.9	$ 246	$ 182.3
Proved Undeveloped Reserve (Volume)	551	1,018	757
Percentage of PUD reserves to the total proved reserves	16.00%	33.00%	30.00%
New PUD reserve additions	7	575
PUD Upward Revisions	20	38
PUD conversions to developed reserves	363	297
Proved Undeveloped Reserves, Removed	179	55
PUD Well Locations Removed	17	6		4	1
Decrease in Proved undeveloped (PUD) reserves	467
Increase in Proved undeveloped (PUD) reserves		261
Investment made to convert proved undeveloped reserves to developed reserves | $	$ 220	$ 246
Conversion Of Undeveloped Proved Reserves To Developed Proved Reserves After Revisions	393	380
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year	36.00%	39.00%	51.00%	27.00%	25.00%
Well Locations Developed With Net PUD Reserves		56
Percent of Well Locations Developed With Net PUD Reserves		50.00%
Upward Revisions to PUD Reserves Converted to Developed Reserves	30	83
Arbitrary discount rate	10.00%
Proved Undeveloped Reserves, Revisions	48
PUD Well Locations Added	5
West Coast Region [Member]
Reserve Quantities [Line Items]
New PUD reserve additions		2
PUD conversions to developed reserves	3	5
Well Locations Developed With Net PUD Reserves	14
Appalachian Region [Member]
Reserve Quantities [Line Items]
Well Locations Developed With Net PUD Reserves	35
Well Locations To Be Developed With Net PUD Reserves	99
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	287	383	394
New PUD reserve additions		175
PUD conversions to developed reserves	146	186
Proved Undeveloped Reserves, Removed	14	13
PUD Well Locations Removed	2	2
Utica Shale [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	265	632	357
New PUD reserve additions		398
PUD conversions to developed reserves	214	106
Proved Undeveloped Reserves, Removed	165	42
PUD Well Locations Removed	15	4
Total PUD Reserve Additions Estimated In The Next Fiscal Year [Member]
Reserve Quantities [Line Items]
Amount to be spent on developing proved undeveloped reserves | $	$ 134

Supplementary Information For_4

Supplementary Information For Oil And Gas Producing Activities (Capitalized Costs Relating To Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands		Sep. 30, 2020	Sep. 30, 2019
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved Properties	[1]	$ 6,238,830	$ 5,623,623
Unproved Properties		148,075	53,498
Capitalized Costs, Oil and Gas Producing Activities, Gross, Total		6,386,905	5,677,121
Less - Accumulated Depreciation, Depletion and Amortization		4,628,765	4,012,568
Capitalized Costs Oil And Gas Producing Activities Net		1,758,140	1,664,553
Asset retirement costs		$ 132,600	$ 70,500
[1]	Includes asset retirement costs of $132.6 million and $70.5 million at September 30, 2020 and 2019, respectively.

Supplementary Information For_5

Supplementary Information For Oil And Gas Producing Activities (Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	$ 39,953	$ 0	$ 0
Development Costs	54,761	17,326	403
Exploration Costs	0	0	0
Capitalized Interest	969	41	0
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	95,683	$ 17,367	$ 403
Capitalized Costs Of Unproved Properties Cumulative Balance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	64,218
Development Costs	75,138
Exploration Costs	7,606
Capitalized Interest	1,113
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	$ 148,075
Costs Incurred Prior To Fiscal 2018 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs				$ 24,265
Development Costs				2,648
Exploration Costs				7,606
Capitalized Interest				103
Capitalized Costs of Unproved Properties Excluded from Amortization, Total				$ 34,622

Supplementary Information For_6

Supplementary Information For Oil And Gas Producing Activities (Costs Incurred In Oil And Gas Property Acquisition, Exploration And Development Activities) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved		$ 245,976	$ 3,136	$ 1,544
Unproved		42,922	3,679	4,286
Exploration Costs		3,891	2,060	29,365
Development Costs	[1]	355,742	468,498	332,496
Asset Retirement Costs		62,080	26,192
Asset Retirement Costs				(10,107)
Total Property Acquisition Costs		710,611	503,565	357,584
Capitalized interest included in development costs		$ 1,000	$ 200	$ 300
[1]	Amounts for 2020, 2019 and 2018 include capitalized interest of $1.0 million, $0.2 million and $0.3 million, respectively.

Supplementary Information For_7

Supplementary Information For Oil And Gas Producing Activities (Results Of Operations For Producing Activities) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Reserve Quantities [Line Items]
Revenues from sales to affiliates		$ 0	$ 0	$ 0
Operating Revenues	[1]	510,291,000	630,126,000	558,896,000
Production/Lifting Costs		203,670,000	186,626,000	162,721,000
Franchise/Ad Valorem Taxes		15,582,000	17,673,000	14,355,000
Purchased Emission Allowance Expense		2,930,000	2,527,000	1,883,000
Accretion Expense		5,237,000	3,723,000	4,266,000
Depreciation, Depletion and Amortization ($0.69, $0.71 and $0.67 per Mcfe of production)		166,759,000	149,881,000	119,946,000
Impairment of Oil and Gas Producing Properties		449,438,000	0	0
Income Tax Expense		(92,820,000)	64,652,000	72,723,000
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)		(240,505,000)	205,044,000	183,002,000
Depreciation, Depletion and Amortization, per Mcfe of Production		0.69	0.71	0.67
Transfers to Entity's Other Operations		1,921,000	2,532,000	2,134,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Gas (includes transfers to operations of $1,921, $2,532 and $2,134, respectively)	[2]	402,447,000	481,048,000	390,642,000
Oil, Condensate And Other Liquids [Member]
Reserve Quantities [Line Items]
Operating Revenues		$ 107,844,000	$ 149,078,000	$ 168,254,000
[1]	Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments.
[2]	There were no revenues from sales to affiliates for all years presented.

Supplementary Information For_8

Supplementary Information For Oil And Gas Producing Activities (Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) ft³ in Billions		12 Months Ended
		Sep. 30, 2020MMcfMBblsBcfft³	Sep. 30, 2019MMcfMBblsft³	Sep. 30, 2018MMcfMBblsft³	Sep. 30, 2017MMcfMBbls
Reserve Quantities [Line Items]
Purchases of Minerals in Place | Bcf		684,141
Proved Undeveloped Reserve (Volume) | ft³		551	1,018	757
Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		2,949,519	2,357,342	1,973,120
Extensions and Discoveries		7,246	686,549	521,694
Revisions of Previous Estimates		(88,419)	103,508	93,435
Production Volume		(227,402)	(197,880)	(162,906)
Purchases of Minerals in Place		684,141
Sales of Minerals in Place				(68,001)
Proved Developed and Undeveloped Reserves		3,325,085	2,949,519	2,357,342
Proved Developed Reserves (Volume)		2,773,823	1,934,795	1,606,532	1,363,102
Proved Undeveloped Reserve (Volume)		551,262	1,014,724	750,810	610,018
Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		24,873	27,663	30,207
Extensions and Discoveries | MBbls		288	787	2,301
Revisions of Previous Estimates | MBbls		(713)	(1,254)	2,477
Production Volume		(2,348)	(2,323)	(2,535)
Sales of Minerals in Place | MBbls				(4,787)
Proved Developed and Undeveloped Reserves | MBbls		22,100	24,873	27,663
Proved Developed Reserves (Volume) | MBbls		22,100	24,259	26,703	29,799
Proved Undeveloped Reserve (Volume) | MBbls		0	614	960	408
West Coast Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		33,633	36,840	46,506
Extensions and Discoveries		0	0	0
Revisions of Previous Estimates		(2,772)	(1,233)	3,322
Production Volume		(1,889)	(1,974)	(2,407)
Purchases of Minerals in Place		0
Sales of Minerals in Place				(10,581)
Proved Developed and Undeveloped Reserves		28,972	33,633	36,840
Proved Developed Reserves (Volume)		28,972	33,633	36,840	46,506
Proved Undeveloped Reserve (Volume)		0	0	0	0
West Coast Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		24,860	27,649	30,179
Extensions and Discoveries | MBbls		288	787	2,301
Revisions of Previous Estimates | MBbls		(715)	(1,256)	2,487
Production Volume		(2,345)	(2,320)	(2,531)
Sales of Minerals in Place | MBbls				(4,787)
Proved Developed and Undeveloped Reserves | MBbls		22,088	24,860	27,649
Proved Developed Reserves (Volume) | MBbls		22,088	24,246	26,689	29,771
Proved Undeveloped Reserve (Volume) | MBbls		0	614	960	408
Appalachian Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		2,915,886	2,320,502	1,926,614
Extensions and Discoveries	[1]	7,246	686,549	521,694
Revisions of Previous Estimates		(85,647)	104,741	90,113
Production Volume	[2]	(225,513)	(195,906)	(160,499)
Purchases of Minerals in Place		684,141
Sales of Minerals in Place				(57,420)
Proved Developed and Undeveloped Reserves		3,296,113	2,915,886	2,320,502
Proved Developed Reserves (Volume)		2,744,851	1,901,162	1,569,692	1,316,596
Proved Undeveloped Reserve (Volume)		551,262	1,014,724	750,810	610,018
Appalachian Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		13	14	28
Extensions and Discoveries | MBbls		0	0	0
Revisions of Previous Estimates | MBbls		2	2	(10)
Production Volume		(3)	(3)	(4)
Sales of Minerals in Place | MBbls				0
Proved Developed and Undeveloped Reserves | MBbls		12	13	14
Proved Developed Reserves (Volume) | MBbls		12	13	14	28
Proved Undeveloped Reserve (Volume) | MBbls		0	0	0	0
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		287	383	394
Marcellus Shale Fields [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		7,000	175,000	274,000
Production Volume		(169,453)	(163,015)	(150,196)
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15.00%
Utica Shale [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		265	632	357
Utica Shale [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		0	512,000	248,000
Production Volume		(55,392)	(32,095)	(9,409)
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15.00%
[1]	Extensions and discoveries include 274 Bcf (during 2018), 175 Bcf (during 2019) and 7 Bcf (during 2020), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 248 Bcf (during 2018), 512 Bcf (during 2019) and 0 Bcf (during 2020), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.
[2]	Production includes 150,196 MMcf (during 2018), 163,015 MMcf (during 2019) and 169,453 MMcf (during 2020), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018), 32,095 MMcf (during 2019) and 55,392 MMcf (during 2020), from Utica Shale fields.

Supplementary Information For_9

Supplementary Information For Oil And Gas Producing Activities (Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Future Cash Inflows	$ 6,493,362	$ 8,738,182	$ 7,822,855
Future Production Costs	3,149,857	2,989,518	2,606,411
Future Development Costs	501,678	797,640	559,707
Future Income Tax Expense at Applicable Statutory Rate	454,553	1,159,882	1,125,910
Future Net Cash Flows	2,387,274	3,791,142	3,530,827
10% Annual Discount for Estimated Timing of Cash Flows	1,164,804	2,054,823	1,810,522
Standardized Measure of Discounted Future Net Cash Flows	$ 1,222,470	$ 1,736,319	$ 1,720,305	$ 1,113,046

Supplementary Information Fo_10

Supplementary Information For Oil And Gas Producing Activities (Principal Sources Of Change In The Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$ 1,736,319	$ 1,720,305	$ 1,113,046
Sales, Net of Production Costs	(290,975)	(425,773)	(381,775)
Net Changes in Prices, Net of Production Costs	(1,109,101)	(164,428)	541,021
Extensions and Discoveries	4,236	202,683	212,494
Changes in Estimated Future Development Costs	99,884	(69,254)	(43,771)
Purchases of Minerals in Place	170,363	0	0
Sales of Minerals in Place	0	0	(100,816)
Previously Estimated Development Costs Incurred	219,938	245,964	182,348
Net Change in Income Taxes at Applicable Statutory Rate	248,182	21,370	55,558
Revisions of Previous Quantity Estimates	(28,337)	53,777	61,363
Accretion of Discount and Other	171,961	151,675	80,837
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$ 1,222,470	$ 1,736,319	$ 1,720,305

Valuation And Qualifying Acco_2

Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2020	Sep. 30, 2019	Sep. 30, 2018
Valuation and Qualifying Accounts [Line Items]
Reversal of estimate for potential sequestration of AMT credit refunds			$ 5,000
Allowance for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts [Line Items]
Balance at Beginning of Period		$ 25,788	24,537	$ 22,526
Additions Charged to Costs and Expenses		12,339	10,184	10,905
Additions Charged to Other Accounts	[1]	1,353	1,707	1,967
Deductions	[2]	16,670	10,640	10,861
Balance at End of Period		22,810	25,788	24,537
Valuation Allowance for Deferred Tax Assets [Member]
Valuation and Qualifying Accounts [Line Items]
Balance at Beginning of Period	[3]	0	5,000	0
Additions Charged to Costs and Expenses	[3]	63,205	0	5,000
Additions Charged to Other Accounts	[1],[3]	0	0	0
Deductions	[2],[3]	0	5,000	0
Balance at End of Period	[3]	$ 63,205	$ 0	$ 5,000
[1]	Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.
[2]	Amounts represent net accounts receivable written-off, as well as a reversal of a valuation allowance, as discussed in footnote (3) below.
[3]	During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets. During fiscal 2019, there was a $5.0 million benefit recorded to reverse the valuation allowance established at September 30, 2018 related to the potential sequestration of estimated alternative minimum tax credit refunds as a result of the 2017 Tax Reform Act.