National Fuel Gas (NFG) 10-K 15 Nov 19 2019 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2019	Oct. 31, 2019	Mar. 31, 2019
Cover page.
Amendment Flag	false
Current Fiscal Year End Date	--09-30
Document Annual Report	true
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2019
Document Period End Date	Sep. 30, 2019
Documents Incorporated by Reference	Portions of the registrant’s definitive Proxy Statement for its 2020 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2019, 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		86,324,767
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			$ 5,152,011,000
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

Consolidated Statements Of Inco

Consolidated Statements Of Income And Earnings Reinvested In The Business - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
INCOME
Operating Revenues	$ 1,693,332	$ 1,592,668	$ 1,579,881
Operating Expenses:
Property, Franchise and Other Taxes	88,886	84,393	84,995
Depreciation, Depletion and Amortization	275,660	240,961	224,195
Total Operating Expenses	1,181,523	1,072,945	986,103
Operating Income	511,809	519,723	593,778
Other Income (Expense):
Other Income (Deductions)	(15,542)	(21,174)	(29,777)
Interest Expense on Long-Term Debt	(101,614)	(110,946)	(116,471)
Other Interest Expense	(5,142)	(3,576)	(3,366)
Income Before Income Taxes	389,511	384,027	444,164
Income Tax Expense (Benefit)	85,221	(7,494)	160,682
Net Income Available for Common Stock	304,290	391,521	283,482
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	1,098,900	851,669	676,361
Beginning Retained Earnings Unappropriated And Current Period Net Income	1,403,190	1,243,190	959,843
Dividends on Common Stock	(148,432)	(144,290)	(140,090)
Balance at End of Year	$ 1,272,601	$ 1,098,900	$ 851,669
Earnings Per Common Share, Basic:
Net Income Available for Common Stock (in dollars per share)	$ 3.53	$ 4.56	$ 3.32
Earnings Per Common Share, Diluted:
Net Income Available for Common Stock (in dollars per share)	$ 3.51	$ 4.53	$ 3.30
Weighted Average Number of Shares Outstanding:
Used in Basic Calculation	86,235,550	85,830,597	85,364,929
Used in Diluted Calculation	86,773,259	86,439,698	86,021,386
Utility and Energy Marketing [Member]
INCOME
Operating Revenues	$ 860,985	$ 812,474	$ 755,485
Operating Expenses:
Operation and Maintenance	171,472	168,885	169,731
Exploration and Production and Other [Member]
INCOME
Operating Revenues	636,528	569,808	617,666
Operating Expenses:
Operation and Maintenance	147,457	139,546	141,010
Pipeline and Storage and Gathering [Member]
INCOME
Operating Revenues	195,819	210,386	206,730
Operating Expenses:
Operation and Maintenance	111,783	101,338	90,918
Purchased Gas [Member]
Operating Expenses:
Purchased Gas	386,265	337,822	275,254
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member]
EARNINGS REINVESTED IN THE BUSINESS
Cumulative Effect of Adoption of Authoritative Guidance	7,437	0	0
Guidance for Reclassification of Stranded Tax Effects [Member]
EARNINGS REINVESTED IN THE BUSINESS
Cumulative Effect of Adoption of Authoritative Guidance	10,406	0	0
Guidance for Stock Based Compensation [Member]
EARNINGS REINVESTED IN THE BUSINESS
Cumulative Effect of Adoption of Authoritative Guidance	$ 0	$ 0	$ 31,916

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income Available for Common Stock	$ 304,290	$ 391,521	$ 283,482
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(44,089)	6,225	15,661
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	7,332	9,704	13,433
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	0	132	4,008
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	79,301	(74,103)	5,347
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	0	(430)	(1,575)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	5,464	1,189	(81,605)
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	(11,738)	0	0
Other Comprehensive Income (Loss), Before Tax	36,270	(57,283)	(44,731)
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(10,473)	1,582	6,175
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	1,698	2,437	4,929
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	0	(15)	1,505
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	20,619	(22,547)	2,009
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	0	(158)	(580)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	2,726	(955)	(34,286)
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	(4,301)	0	0
Reclassification Adjustment for Stranded Tax Effects Related to the 2017 Tax Reform Act to Earnings Reinvested in the Business	10,406	0	0
Income Taxes - Net	20,675	(19,656)	(20,248)
Other Comprehensive Income (Loss)	15,595	(37,627)	(24,483)
Comprehensive Income	$ 319,885	$ 353,894	$ 258,999

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2019	Sep. 30, 2018
ASSETS
Property, Plant and Equipment		$ 11,204,838	$ 10,439,839
Less - Accumulated Depreciation, Depletion and Amortization		5,695,328	5,462,696
Property, Plant and Equipment, Net, Total		5,509,510	4,977,143
Current Assets
Cash and Temporary Cash Investments		20,428	229,606
Hedging Collateral Deposits	[1]	6,832	3,441
Receivables - Net of Allowance for Uncollectible Accounts of $25,788 and $24,537, Respectively		139,956	141,498
Unbilled Revenue		18,758	24,182
Gas Stored Underground		36,632	37,813
Materials and Supplies - at average cost		40,717	35,823
Unrecovered Purchased Gas Costs		2,246	4,204
Other Current Assets		97,054	68,024
Total Current Assets		362,623	544,591
Other Assets
Recoverable Future Taxes		115,197	115,460
Unamortized Debt Expense		14,005	15,975
Other Regulatory Assets		167,320	112,918
Deferred Charges		33,843	40,025
Other Investments		144,917	132,545
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		60,517	82,733
Fair Value of Derivative Financial Instruments		48,669	9,518
Other		80	102
Total Other Assets		590,024	514,752
Total Assets		6,462,157	6,036,486
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 86,315,287 Shares and 85,956,814 Shares, Respectively		86,315	85,957
Paid In Capital		832,264	820,223
Earnings Reinvested in the Business		1,272,601	1,098,900
Accumulated Other Comprehensive Loss		(52,155)	(67,750)
Total Comprehensive Shareholders' Equity		2,139,025	1,937,330
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,133,718	2,131,365
Total Capitalization		4,272,743	4,068,695
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		55,200	0
Current Portion of Long-Term Debt	[2]	0	0
Accounts Payable		132,208	160,031
Amounts Payable to Customers		4,017	3,394
Dividends Payable		37,547	36,532
Interest Payable on Long-Term Debt		18,508	19,062
Customer Advances		13,044	13,609
Customer Security Deposits		16,210	25,703
Other Accruals and Current Liabilities		139,600	132,693
Fair Value of Derivative Financial Instruments		5,574	49,036
Total Current and Accrued Liabilities		421,908	440,060
Deferred Credits
Deferred Income Taxes		653,382	512,686
Taxes Refundable to Customers		366,503	370,628
Cost of Removal Regulatory Liability		221,699	212,311
Other Regulatory Liabilities		142,367	146,743
Pension and Other Post-Retirement Liabilities		133,729	66,103
Asset Retirement Obligations		127,458	108,235
Other Deferred Credits		122,368	111,025
Total Deferred Credits		1,767,506	1,527,731
Commitments and Contingencies (Note J)		0	0
Total Capitalization and Liabilities		$ 6,462,157	$ 6,036,486
[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, 2019 and 2018 will mature within the following twelve-month period.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2019	Sep. 30, 2018
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 25,788	$ 24,537
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	86,315,287	85,956,814
Common Stock, Shares Outstanding	86,315,287	85,956,814

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net Income Available for Common Stock	$ 304,290	$ 391,521	$ 283,482
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	275,660	240,961	224,195
Deferred Income Taxes	122,265	(18,153)	117,975
Stock-Based Compensation	21,186	15,762	12,262
Other	8,608	16,133	16,476
Change in:
Receivables and Unbilled Revenue	6,379	(30,882)	(3,380)
Gas Stored Underground and Materials and Supplies	(3,713)	(4,021)	(1,417)
Unrecovered Purchased Gas Costs	1,958	419	(2,183)
Other Current Assets	(29,030)	(16,519)	7,849
Accounts Payable	(24,770)	17,962	17,192
Amounts Payable to Customers	623	3,394	(19,537)
Customer Advances	(565)	(2,092)	939
Customer Security Deposits	(9,493)	5,331	4,353
Other Accruals and Current Liabilities	10,992	3,865	27,004
Other Assets	5,115	(9,556)	(2,885)
Other Liabilities	4,978	1,178	2,183
Net Cash Provided by Operating Activities	694,483	615,303	684,508
Investing Activities
Capital Expenditures	(788,938)	(584,004)	(450,335)
Net Proceeds from Sale of Oil and Gas Producing Properties	0	55,506	26,554
Other	(10,237)	(389)	1,216
Net Cash Used in Investing Activities	(799,175)	(528,887)	(422,565)
Financing Activities
Change in Notes Payable to Banks and Commercial Paper	55,200	0	0
Net Proceeds from Issuance of Long-Term Debt	0	295,020	295,151
Reduction of Long-Term Debt	0	(566,512)	0
Net Repurchases of Common Stock	(8,877)
Net Proceeds from Issuance of Common Stock		4,110	7,784
Dividends Paid on Common Stock	(147,418)	(143,258)	(139,063)
Net Cash Provided by (Used in) Financing Activities	(101,095)	(410,640)	163,872
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(205,787)	(324,224)	425,815
Cash, Cash Equivalents and Restricted Cash At Beginning of Year	233,047	557,271	131,456
Cash, Cash Equivalents and Restricted Cash At End of Year	27,260	233,047	557,271
Supplemental Disclosure of Cash Flow Information
Cash Paid for Interest	102,920	126,079	116,894
Cash Refunded for Income Taxes	(17,342)
Cash Paid for Income Taxes		31,771	34,826
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities
Non-Cash Capital Expenditures	$ 81,121	$ 88,813	$ 72,216

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2019
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. Reclassifications In November 2016, the FASB issued authoritative guidance related to the presentation of restricted cash on the statement of cash flows. The new guidance requires restricted cash and cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and requires disclosure of how cash and cash equivalents on the statement of cash flows reconciles to the balance sheet. The Company considers Hedging Collateral Deposits to be restricted cash. The Company adopted this guidance effective October 1, 2018 on a retrospective basis. As a result, prior periods have been reclassified to conform to the current year presentation. Additional discussion is provided below at Consolidated Statement of Cash Flows. In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component is eligible to be capitalized as part of the cost of inventory or property, plant and equipment while the other components of net periodic pension cost and net periodic postretirement benefit cost are generally not eligible for capitalization, unless allowed by a regulator. The Company adopted this guidance effective October 1, 2018. The Company applied the guidance retrospectively for the pension and postretirement benefit costs using amounts disclosed in prior period financial statement notes as estimates for the reclassifications in accordance with a practical expedient allowed under the guidance. For the years ended September 30, 2018 and September 30, 2017, Operating Income increased $32.6 million and $40.9 million , respectively, and Other Income (Deductions) decreased by the same amounts as a result of the reclassifications. For the year ended September 30, 2019, Other Income (Deductions) includes $27.3 million of pension and postretirement benefit costs. 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 D — 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 and other specific information about customer accounts. 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. 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 D — 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. 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 $1.7 billion and $1.3 billion at September 30, 2019 and 2018, respectively. For further discussion of capitalized costs, refer to Note M — 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. At September 30, 2019, the ceiling exceeded the book value of the oil and gas properties by $381.2 million . In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2019, 2018 and 2017, estimated future net cash flows were decreased by $17.7 million , decreased by $25.1 million and increased by $30.5 million , respectively. The Company entered into a purchase and sale agreement to sell its oil and gas properties in the Sespe Field area of Ventura County, California in October 2017 for $43.0 million . The Company completed the sale on May 1, 2018, effective as of October 1, 2017, 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 for the year ended September 30, 2018). The net proceeds received by the Company were adjusted for production revenue and production expenses retained by the Company between the effective date of the sale and the closing date, resulting in lower proceeds from sale at the closing date. 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 and $26.6 million in fiscal 2018 and fiscal 2017, respectively. 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 and fiscal 2017. 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. 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 $149.9 million , $119.9 million and $108.5 million for the years ended September 30, 2019, 2018 and 2017, respectively. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. 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 2019 2018 (Thousands) Exploration and Production $ 5,747,731 $ 5,222,037 Pipeline and Storage 2,191,166 2,110,714 Gathering 577,021 527,188 Utility 2,159,841 2,104,437 All Other and Corporate 112,857 112,295 $ 10,788,616 $ 10,076,671 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2019 2018 2017 Exploration and Production, per Mcfe(1) $ 0.73 $ 0.70 $ 0.65 Pipeline and Storage 2.2 % 2.2 % 2.2 % Gathering 3.6 % 3.4 % 3.4 % Utility 2.7 % 2.8 % 2.8 % All Other and Corporate 1.8 % 2.4 % 1.5 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.71 , $0.67 and $0.63 per Mcfe of production in 2019 , 2018 and 2017 , respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2019 and 2018 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, 2019 , 2018 and 2017 , 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 price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, 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 G — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments. For effective 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 H — Financial Instruments for further discussion concerning cash flow hedges. For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. Reference is made to Note H — Financial Instruments for further discussion concerning fair value hedges. Accumulated Other Comprehensive Income (Loss) The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2019, net of related tax effect, 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, 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 ) Year Ended September 30, 2018 Balance at October 1, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) Other Comprehensive Gains and Losses Before Reclassifications (51,556 ) 147 4,643 (46,766 ) Amounts Reclassified From Other Comprehensive Loss 2,144 (272 ) 7,267 9,139 Balance at September 30, 2018 $ (28,611 ) $ 7,437 $ (46,576 ) $ (67,750 ) 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 $1.0 million at both September 30, 2019 and 2018. The total amount for accumulated losses was $85.8 million and $45.6 million at September 30, 2019 and 2018, respectively. 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 loss for the year ended September 30, 2019 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Income (Loss) Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the Year Ended September 30, Affected Line Item in the Statement Where Net Income is Presented 2019 2018 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($3,460 ) $423 Operating Revenues Commodity Contracts (1,182 ) 952 Purchased Gas Foreign Currency Contracts (822 ) (2,564 ) Operating Revenues Gains (Losses) on Securities Available for Sale — 430 Other Income (Deductions) Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (264 ) (258 ) (1) Net Actuarial Loss (7,068 ) (9,446 ) (1) (12,796 ) (10,463 ) Total Before Income Tax 4,424 1,324 Income Tax Expense ($8,372 ) ($9,139 ) Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note I — Retirement Plan and Other Post-Retirement Benefits for additional details. Gas Stored Underground In the Utility segment, gas stored underground in the amount of $29.6 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 2019, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $19.8 million at September 30, 2019. All other gas stored underground, which is recorded by NFR (included in the All Other category), is carried at an average cost method, subject to lower of cost or net realizable value adjustments. 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, 2019, the remaining weighted average amortization period for such costs was approximately 7 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 2019 2018 2017 2016 Cash and Temporary Cash Investments $ 20,428 $ 229,606 $ 555,530 $ 129,972 Hedging Collateral Deposits 6,832 3,441 1,741 1,484 Cash, Cash Equivalents, and Restricted Cash $ 27,260 $ 233,047 $ 557,271 $ 131,456 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 2019 2018 (Thousands) Prepayments $ 12,728 $ 11,126 Prepaid Property and Other Taxes 14,361 14,088 Federal Income Taxes Receivable 42,388 22,457 State Income Taxes Receivable 8,579 8,822 Fair Values of Firm Commitments 7,538 1,739 Regulatory Assets 11,460 9,792 $ 97,054 $ 68,024 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2019 2018 (Thousands) Accrued Capital Expenditures $ 33,713 $ 38,354 Regulatory Liabilities 50,332 57,425 Liability for Royalty and Working Interests 18,057 12,062 Non-Qualified Benefit Plan Liability 13,194 11,536 Other 24,304 13,316 $ 139,600 $ 132,693 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, 2019 and 2018, customers in the balanced billing programs had advanced excess funds of $13.0 million and $13.6 million , respectively. Customer Security Deposits The Company, primarily in its Utility and Pipeline and Storage segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2019 and 2018, the Company had received customer security deposits amounting to $16.2 million and $25.7 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. 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, 317,899 securities and 157,649 securities excluded as being antidilutive for the years ended September 30, 2019, 2018 and 2017, 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, both performance and nonperformance-based, 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 performance based and nonperformance-based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and nonperformance-based restricted stock units is the same as the accounting for restricted share 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 F — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans. New Authoritative Accounting and Financial Reporting Guidance Leasing In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, requiring entities that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required entities to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases only while excluding operating leases from balance sheet recognition. The updated guidance provides entities with an optional transition method, which allows an entity to apply the new lease standard prospectively at the adoption date, elect not to reclassify comparable periods, and recognize a cumulative-effect adjustment to retained earnings in the period of adoption. The Company adopted the new leases standard on October 1, 2019, using the optional transition method. Comparative periods, including disclosures relating to those periods, will not be restated. The Company also elected to apply the following practical expedients p

Revenue from Contracts with Cus

Revenue from Contracts with Customers	12 Months Ended
	Sep. 30, 2019
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 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 table provides a disaggregation of the Company's revenues for the year ended September 30, 2019, presented by type of service from each reportable segment. Year Ended September 30, 2019 Revenues by Type of Service Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Production of Natural Gas $ 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: $162.0 million for fiscal 2020; $138.4 million for fiscal 2021; $115.1 million for fiscal 2022; $82.3 million for fiscal 2023; $72.9 million for fiscal 2024; and $297.6 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), records revenue from natural gas sales in western and central New York and northwestern Pennsylvania. NFR's operations were previously reported as the Energy Marketing segment, however the Company is no longer reporting the energy marketing operations as a separate reportable segment. For further discussion of this change, refer to Note K — Business Segment Information. NFR's sales are provided largely to industrial, wholesale, commercial, public authority and residential customers. NFR’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 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. Since NFR bills its residential 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. NFR also allows 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. The Company uses derivative financial instruments 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 are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Sep. 30, 2019
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). This obligation increased significantly during fiscal 2019 for this segment's California operations due to a statewide effort to increase the pace of plugging idle wells combined with more stringent state mandated plugging requirements. 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. The following is a reconciliation of the change in the Company’s asset retirement obligations: Year Ended September 30 2019 2018 2017 (Thousands) Balance at Beginning of Year $ 108,235 $ 106,395 $ 112,330 Liabilities Incurred 4,122 5,597 2,963 Revisions of Estimates 16,693 (419 ) (10,578 ) Liabilities Settled (7,670 ) (12,858 ) (4,967 ) Accretion Expense 6,078 9,520 6,647 Balance at End of Year $ 127,458 $ 108,235 $ 106,395

Regulatory Matters

Regulatory Matters	12 Months Ended
	Sep. 30, 2019
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 2019 2018 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note I) $ 114,509 $ 62,703 Post-Retirement Benefit Costs(2) (Note I) 18,236 11,160 Recoverable Future Taxes (Note E) 115,197 115,460 Environmental Site Remediation Costs(2) (Note J) 15,317 20,308 Asset Retirement Obligations(2) (Note C) 15,696 15,495 Unamortized Debt Expense (Note A) 14,005 15,975 Other(3) 15,022 13,044 Total Regulatory Assets 307,982 254,145 Less: Amounts Included in Other Current Assets (11,460 ) (9,792 ) Total Long-Term Regulatory Assets $ 296,522 $ 244,353 At September 30 2019 2018 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 221,699 $ 212,311 Taxes Refundable to Customers (Note E) 366,503 370,628 Post-Retirement Benefit Costs(4) (Note I) 126,577 134,387 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 4,017 3,394 Other(5) 66,122 69,781 Total Regulatory Liabilities 784,918 790,501 Less: Amounts included in Current and Accrued Liabilities (54,349 ) (60,819 ) Total Long-Term Regulatory Liabilities $ 730,569 $ 729,682 (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) $11,460 and $9,792 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,562 and $3,252 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $50,332 and $57,425 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,790 and $12,356 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, 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 C — 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 filed a Section 4 rate case on July 31, 2019 proposing rate increases to be effective September 1, 2019. The proposed rates reflect an annual cost of service of $295.4 million , a rate base of $970.8 million and a proposed cost of equity of 15% . The FERC has accepted the filed rates and suspended the effective date of the increases until February 1, 2020, when the rates will be made effective, subject to refund. If the rates finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2019, but are less than rates put into effect subject to refund on February 1, 2020, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2019, such lower rates will become effective prospectively from the date of the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2019. The FERC also terminated the proceeding in which Supply Corporation filed its Form 501-G, addressing the impact of the 2017 Tax Reform Act. Refer to Note E — Income Taxes for further discussion of the 2017 Tax Reform Act.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2019
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 a blended 24.5% for fiscal 2018 and 21% for fiscal 2019 and beyond. The changes had a material impact on the financial statements in the year ended September 30, 2018. The Company’s deferred income taxes were remeasured based upon the new tax rates. For the non-rate regulated activities through the year ended September 30, 2018, the change in beginning of the year deferred income taxes of $103.5 million was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $336.7 million was recorded as a decrease to Recoverable Future Taxes of $65.7 million and an increase to Taxes Refundable to Customers of $271.0 million . 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 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 that are expected to be refunded between fiscal 2020 and fiscal 2023, if not previously utilized. During fiscal 2018, the Department of Treasury indicated that a portion of the refundable AMT credit carryovers would be subject to sequestration. Accordingly, the Company recorded a $5.0 million valuation allowance related to this sequestration. During the quarter ended December 31, 2018, the Office of Management and Budget determined that these AMT refunds would not be subject to sequestration. As such, the Company has removed the valuation allowance. These amounts are recorded in Deferred Income Taxes and will be reclassified to a receivable when the amounts are expected to be realized in cash. As of September 30, 2019, $42.5 million of AMT credit refunds are recorded as a receivable in Other Current Assets. The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. Based upon the available guidance, the Company has completed the remeasurement of deferred income taxes as of December 31, 2018. Any subsequent guidance or clarification related to the 2017 Tax Reform Act will be accounted for in the period issued. The components of federal and state income taxes included in the Consolidated Statements of Income are as follows: Year Ended September 30 2019 2018 2017 (Thousands) Current Income Taxes — Federal $ (41,645 ) $ 2,025 $ 32,034 State 4,601 8,634 10,673 Deferred Income Taxes — Federal 98,514 (38,927 ) 103,046 State 23,751 20,774 14,929 85,221 (7,494 ) 160,682 Deferred Investment Tax Credit (91 ) (105 ) (173 ) Total Income Taxes $ 85,130 $ (7,599 ) $ 160,509 Presented as Follows: Other (Income) Deductions $ (91 ) $ (105 ) $ (173 ) Income Tax Expense (Benefit) 85,221 (7,494 ) 160,682 Total Income Taxes $ 85,130 $ (7,599 ) $ 160,509 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 2019 2018 2017 (Thousands) U.S. Income Before Income Taxes $ 389,420 $ 383,922 $ 443,991 Income Tax Expense, Computed at U.S. Federal Statutory Rate(1) $ 81,778 $ 94,061 $ 155,397 State Income Tax Expense(2) 22,397 22,203 16,641 Federal Tax Credits (7,361 ) (6,576 ) (6,679 ) Amortization of Excess Deferred Federal Income Taxes(3) (5,036 ) (3,236 ) — Impact of 2017 Tax Reform Act(4) (5,000 ) (112,598 ) — Miscellaneous (1,648 ) (1,453 ) (4,850 ) Total Income Taxes $ 85,130 $ (7,599 ) $ 160,509 (1) For fiscal 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. For fiscal 2017, the statutory rate of 35% was utilized. (2) The state income tax expense 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. (3) Represents amortization of excess deferred federal income taxes under the 2017 Tax Reform Act. (4) 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 2019 2018 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 861,278 $ 770,794 Pension and Other Post-Retirement Benefit Costs 55,795 39,541 Other 54,486 49,734 Total Deferred Tax Liabilities 971,559 860,069 Deferred Tax Assets: Tax Loss and Credit Carryforwards (175,542 ) (214,128 ) Pension and Other Post-Retirement Benefit Costs (87,280 ) (62,969 ) Other (55,355 ) (75,286 ) Total Gross Deferred Tax Assets (318,177 ) (352,383 ) Valuation Allowance — 5,000 Total Deferred Tax Assets (318,177 ) (347,383 ) Total Net Deferred Income Taxes $ 653,382 $ 512,686 The Company adopted authoritative guidance issued by the FASB simplifying several aspects of the accounting for stock-based compensation effective as of October 1, 2016. Under this guidance, the Company recognizes excess tax benefits as incurred. The Company recognized $31.9 million , that arose directly from excess tax benefits related to stock-based compensation in prior periods, as a cumulative effect adjustment increasing retained earnings at October 1, 2016. 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 $366.5 million and $370.6 million at September 30, 2019 and 2018, 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 $115.2 million and $115.5 million at September 30, 2019 and 2018, respectively. The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2019 2018 2017 (Thousands) Balance at Beginning of Year $ — $ 1,251 $ 396 Additions for Tax Positions of Prior Years — — 1,251 Reductions for Tax Positions of Prior Years — (788 ) (396 ) Reductions Related to Settlements with Taxing Authorities — (463 ) — Balance at End of Year $ — $ — $ 1,251 The IRS is currently conducting an examination of the Company for fiscal 2019 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 2016 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. 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. As of September 30, 2019, the Company has the following carryforwards available: Jurisdiction Tax Attribute Amount (Thousands) Expires Federal Pre-Fiscal 2018 Net Operating Loss $ 143,571 2032-2033 Federal Post-Fiscal 2017 Net Operating Loss 54,789 Unlimited Pennsylvania Net Operating Loss 383,056 2030-2039 California Net Operating Loss 207,995 2030-2039 Federal Alternative Minimum Tax Credit 42,546 Unlimited California Alternative Minimum Tax Credit 7,711 Unlimited Federal Enhanced Oil Recovery Credit 26,790 2029-2039 California Enhanced Oil Recovery Credit 8,504 2037-2039 Federal R&D Tax Credit 6,339 2031-2039 Federal Charitable Contributions 2,097 2023

Capitalization And Short-Term B

Capitalization And Short-Term Borrowings	12 Months Ended
	Sep. 30, 2019
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 Capital Earnings Reinvested in the Business Accumulated Other Comprehensive Income (Loss) Shares Amount (Thousands, except per share amounts) Balance at September 30, 2016 85,119 $ 85,119 $ 771,164 $ 676,361 $ (5,640 ) Net Income Available for Common Stock 283,482 Dividends Declared on Common Stock ($1.64 Per Share) (140,090 ) Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation 31,916 Other Comprehensive Loss, Net of Tax (24,483 ) Share-Based Payment Expense(1) 10,902 Common Stock Issued Under Stock and Benefit Plans 424 424 14,580 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 (2) $ (52,155 ) (1) Paid in Capital includes compensation costs associated with SARs, 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, 2019, $1.1 billion of accumulated earnings was free of such limitations. Common Stock The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent. During 2019, 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 2019, the Company issued 126,879 original issue shares of common stock as a result of SARs exercises, 80,354 original issue shares of common stock for restricted stock units that vested and 281,882 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 2019, 159,413 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 28,771 original issue shares of common stock during 2019. 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, 2019, 2018 and 2017 was approximately $19.5 million , $14.2 million and $10.8 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, 2019, 2018 and 2017 was approximately $3.8 million , $3.4 million and $4.4 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, 2019, 2018 and 2017. The tax benefit recognized from stock-based compensation exercises and vestings was $3.2 million for the year ended September 30, 2019. SARs Transactions for 2019 involving SARs for all plans are summarized as follows: Number of Shares Subject To Option Weighted Average Exercise Price Weighted Average Remaining Contractual Life (Years) Aggregate Intrinsic Value (In thousands) Outstanding at September 30, 2018 1,299,088 $ 50.70 Granted in 2019 — $ — Exercised in 2019 (528,456 ) $ 43.94 Forfeited in 2019 — $ — Expired in 2019 (37,500 ) $ 63.87 Outstanding at September 30, 2019 733,132 $ 54.90 1.73 $ — SARs exercisable at September 30, 2019 733,132 $ 54.90 1.73 $ — Shares available for future grant at September 30, 2019(1) 1,225,831 (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, 2018 and 2017. 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, 2018 and 2017 totaled approximately $7.2 million , $4.4 million , and $1.6 million , respectively. For the year ended September 30, 2017, 5,000 SARs became fully vested. There were no SARs that became fully vested during the years ended September 30, 2019 and 2018, and all SARs outstanding have been fully vested since fiscal 2017. The total fair value of the SARs that became vested during the year ended September 30, 2017 was approximately $0.1 million . Restricted Share Awards Transactions for 2019 involving restricted share awards for all plans are summarized as follows: Number of Restricted Share Awards Weighted Average Fair Value per Award Outstanding at September 30, 2018 20,000 $ 47.46 Granted in 2019 — $ — Vested in 2019 — $ — Forfeited in 2019 — $ — Outstanding at September 30, 2019 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, 2018 and 2017. As of September 30, 2019, unrecognized compensation expense related to restricted share awards totaled approximately $0.1 million , which will be recognized over a weighted average period of 1.1 years . Vesting restrictions for the 20,000 outstanding shares of non-vested restricted stock at September 30, 2019 will lapse in 2021. Restricted Stock Units Transactions for 2019 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Restricted Stock Units Weighted Average Fair Value per Award Outstanding at September 30, 2018 245,316 $ 48.45 Granted in 2019 123,939 $ 49.40 Vested in 2019 (80,354 ) $ 48.24 Forfeited in 2019 (7,294 ) $ 50.40 Outstanding at September 30, 2019 281,607 $ 48.88 The Company also granted 89,672 and 87,143 nonperformance-based restricted stock units during the years ended September 30, 2018 and 2017, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2018 and 2017 was $51.23 per share and $52.13 per share, respectively. As of September 30, 2019, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $6.1 million , which will be recognized over a weighted average period of 2.3 years . Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2019 will lapse as follows: 2020 — 87,835 units; 2021 — 76,146 units; 2022 — 67,525 units; 2023 - 33,831 units; and 2024 - 16,270 units. Performance Shares Transactions for 2019 involving performance shares for all plans are summarized as follows: Number of Performance Shares Weighted Average Fair Value per Award Outstanding at September 30, 2018 641,290 $ 44.49 Granted in 2019 244,734 $ 55.67 Vested in 2019 (281,882 ) $ 31.16 Forfeited in 2019 (109,806 ) $ 54.19 Change in Units Based on Performance Achieved 28,178 $ 35.14 Outstanding at September 30, 2019 522,514 $ 54.37 The Company also granted 208,588 and 184,148 performance shares during the years ended September 30, 2018 and 2017, respectively. The weighted average grant date fair value of such performance shares granted in 2018 and 2017 was $50.95 per share and $56.39 per share, respectively. As of September 30, 2019, unrecognized compensation expense related to performance shares totaled approximately $8.7 million , which will be recognized over a weighted average period of 1.7 years . Vesting restrictions for the outstanding performance shares at September 30, 2019 will lapse as follows: 2020 — 173,454 shares; 2021 — 170,526 shares; and 2022 — 178,534 shares. Half of the performance shares granted during the years ended September 30, 2019, 2018 and 2017 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 2019, 2018 and 2017 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, 2019, 2018 and 2017 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 2019, 2018 and 2017 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 2019 2018 2017 Risk-Free Interest Rate 2.61 % 1.96 % 1.54 % Remaining Term at Date of Grant (Years) 2.78 2.78 2.79 Expected Volatility 20.2 % 22.0 % 22.6 % Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2019, 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 2019 2018 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(2)(3): 3.75% to 5.20% due December 2021 to September 2028 2,050,000 2,050,000 Total Long-Term Debt 2,149,000 2,149,000 Less Unamortized Discount and Debt Issuance Costs 15,282 17,635 Less Current Portion(4) — — $ 2,133,718 $ 2,131,365 (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). (4) None of the Company's long-term debt at September 30, 2019 and 2018 will mature within the following twelve-month period. 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 call 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, 2019, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2020 and 2021, $500.0 million in 2022, $549.0 million in 2023, zero in 2024, 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. 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. 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, 2019, the commercial paper program was backed by the Credit Agreement. At September 30, 2019, the Company had outstanding commercial paper of $55.2 million . The Company did not have any outstanding short-term notes payable to banks at September 30, 2019. At September 30, 2019, the weighted average interest rate on the commercial paper was 2.50% . The Company did not have any outstanding commercial paper or short term notes payable to banks at September 30, 2018. 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 . At September 30, 2019, the Company’s debt to capitalization ratio (as calculated under the facility) was .51 . The constraints specified in the Credit Agreement would have permitted an additional $1.78 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 . A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations. The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of September 30, 2019, the Company did not have any debt outstanding under the Credit Agreement. Under the Company’s existing indenture covenants at September 30, 2019, the Company would have been permitted to issue up to a maximum of $1.02 billion in additional long-term indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtedness to replace maturing debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. The Company’s 1974 indenture pursuant to which $99.0 million (or 4.6% ) of the Company’s long-term debt (as of September 30, 2019) 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, 2019
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, 2019 and 2018. 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, 2019 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Adjustments(1) Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 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 At Fair Value as of September 30, 2018 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Adjustments(1) Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 215,272 $ — $ — $ — $ 215,272 Derivative Financial Instruments: Commodity Futures Contracts — Gas 1,075 — — (1,075 ) — Over the Counter Swaps — Gas and Oil — 26,074 — (17,041 ) 9,033 Foreign Currency Contracts — 443 — (443 ) — Other Investments: Balanced Equity Mutual Fund 38,468 — — — 38,468 Fixed Income Mutual Fund 51,331 — — — 51,331 Common Stock — Financial Services Industry 2,776 — — — 2,776 Hedging Collateral Deposits 3,441 — — — 3,441 Total $ 312,363 $ 26,517 $ — $ (18,559 ) $ 320,321 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 2,412 $ — $ — $ (1,075 ) $ 1,337 Over the Counter Swaps — Gas and Oil — 64,224 — (17,041 ) 47,183 Foreign Currency Contracts — 959 — (443 ) 516 Total $ 2,412 $ 65,183 $ — $ (18,559 ) $ 49,036 Total Net Assets/(Liabilities) $ 309,951 $ (38,666 ) $ — $ — $ 271,285 (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, 2019 and 2018, 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) and $3.4 million (at September 30, 2018), 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 and 2018 consist of natural gas price swap agreements used in the Company’s Exploration and Production segment and in its NFR operations, the 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 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 is 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, 2019, 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. For the years ended September 30, 2019 and 2018, there were no assets or liabilities measured at fair value and classified as Level 3. For the years ended September 30, 2019 and September 30, 2018, no

Financial Instruments

Financial Instruments	12 Months Ended
	Sep. 30, 2019
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 2019 Carrying Amount 2019 Fair Value 2018 Carrying 2018 Fair Value (Thousands) Long-Term Debt $ 2,133,718 $ 2,257,085 $ 2,131,365 $ 2,121,861 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 2019 2018 (Thousands) Life Insurance Contracts $ 41,074 $ 39,970 Equity Mutual Fund 40,660 38,468 Fixed Income Mutual Fund 62,339 51,331 Marketable Equity Securities 844 2,776 $ 144,917 $ 132,545 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 as well as by NFR (included in the All Other category). The Company enters into futures contracts 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 Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The duration of the Company’s combined cash flow and fair value hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 7 years . The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. 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, 2019 and September 30, 2018 . 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). 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, 2019 , the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding: Commodity Units Natural Gas 105.2 Bcf (short positions) Natural Gas 2.7 Bcf (long positions) Crude Oil 2,772,000 Bbls (short positions) As of September 30, 2019 , the Company was hedging a total of $81.6 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions). As of September 30, 2019 , the Company had $47.4 million ( $34.7 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $39.1 million ( $28.6 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2019 and 2018 (Dollar Amounts in Thousands) Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Year Ended September 30, Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Year Ended September 30, Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Year Ended September 30, 2019 2018 2019 2018 2019 2018 Commodity Contracts $ 82,984 $ (70,905 ) Operating Revenue $ (3,460 ) $ 423 Operating Revenue $ 2,096 $ (782 ) Commodity Contracts (1,037 ) 701 Purchased Gas (1,182 ) 952 Not Applicable — — Foreign Currency Contracts (2,646 ) (3,899 ) Operating Revenue (822 ) (2,564 ) Not Applicable — — Total $ 79,301 $ (74,103 ) $ (5,464 ) $ (1,189 ) $ 2,096 $ (782 ) Fair Value Hedges The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of September 30, 2019 , NFR had fair value hedges covering approximately 25.6 Bcf ( 25.2 Bcf of fixed price sales commitments and 0.4 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below. Derivatives in Fair Value Hedging Relationships Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2019 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2019 (In thousands) Commodity Contracts Operating Revenues $ 2,606 $ (2,606 ) Commodity Contracts Purchased Gas (665 ) 665 $ 1,941 $ (1,941 ) 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 and applicable foreign currency forward contracts with eighteen counterparties of which sixteen are in a net gain position. On average, the Company had $3.0 million of credit exposure per counterparty in a gain position at September 30, 2019 . The maximum credit exposure per counterparty in a gain position at September 30, 2019 was $7.0 million . As of September 30, 2019 , 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, 2019 , fifteen of the eighteen 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, 2019 , the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $36.6 million according to the Company’s internal model (discussed in Note G — Fair Value Measurements). At September 30, 2019 , the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $0.4 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, 2019 . For its exchange traded futures contracts, the Company was required to post $6.8 million in hedging collateral deposits as of September 30, 2019 . As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts or receives hedging collateral based on open positions and margin requirements it has with its counterparties.

Retirement Plan And Other Post-

Retirement Plan And Other Post-Retirement Benefits	12 Months Ended
	Sep. 30, 2019
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 $3.9 million , $3.5 million and $2.9 million for the years ended September 30, 2019 , 2018 and 2017 , 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 $6.4 million , $6.2 million , and $5.9 million for the years ended September 30, 2019 , 2018 and 2017 , 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 date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2019 , 2018 and 2017 . Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2019 2018 2017 2019 2018 2017 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 985,690 $ 1,054,826 $ 1,097,421 $ 435,986 $ 462,619 $ 526,138 Service Cost 8,482 9,921 11,969 1,519 1,830 2,449 Interest Cost 38,378 33,006 38,383 17,145 14,801 19,007 Plan Participants’ Contributions — — — 2,930 2,894 2,717 Retiree Drug Subsidy Receipts — — — 1,855 1,545 1,553 Actuarial (Gain) Loss 127,748 (50,218 ) (32,466 ) 34,401 (21,039 ) (62,215 ) Benefits Paid (62,673 ) (61,845 ) (60,481 ) (25,673 ) (26,664 ) (27,030 ) Benefit Obligation at End of Period $ 1,097,625 $ 985,690 $ 1,054,826 $ 468,163 $ 435,986 $ 462,619 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 924,506 $ 910,719 $ 869,775 $ 513,800 $ 514,017 $ 494,320 Actual Return on Plan Assets 77,401 42,652 84,279 30,006 20,657 40,157 Employer Contributions 29,215 32,980 17,146 3,064 2,896 3,853 Plan Participants’ Contributions — — — 2,930 2,894 2,717 Benefits Paid (62,673 ) (61,845 ) (60,481 ) (25,673 ) (26,664 ) (27,030 ) Fair Value of Assets at End of Period $ 968,449 $ 924,506 $ 910,719 $ 524,127 $ 513,800 $ 514,017 Net Amount Recognized at End of Period (Funded Status) $ (129,176 ) $ (61,184 ) $ (144,107 ) $ 55,964 $ 77,814 $ 51,398 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (129,176 ) $ (61,184 ) $ (144,107 ) $ (4,553 ) $ (4,919 ) $ (4,972 ) Non-Current Assets — — — 60,517 82,733 56,370 Net Amount Recognized at End of Period $ (129,176 ) $ (61,184 ) $ (144,107 ) $ 55,964 $ 77,814 $ 51,398 Accumulated Benefit Obligation $ 1,053,914 $ 946,763 $ 1,010,179 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 3.15 % 4.30 % 3.77 % 3.17 % 4.31 % 3.81 % 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 2019 2018 2017 2019 2018 2017 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 8,482 $ 9,921 $ 11,969 $ 1,519 $ 1,830 $ 2,449 Interest Cost 38,378 33,006 38,383 17,145 14,801 19,007 Expected Return on Plan Assets (62,368 ) (61,715 ) (59,718 ) (30,157 ) (31,482 ) (31,458 ) Amortization of Prior Service Cost (Credit) 826 938 1,058 (429 ) (429 ) (429 ) Recognition of Actuarial Loss(1) 32,096 37,205 42,687 5,962 10,558 18,415 Net Amortization and Deferral for Regulatory Purposes 2,493 9,027 469 16,481 15,028 6,108 Net Periodic Benefit Cost $ 19,907 $ 28,382 $ 34,848 $ 10,521 $ 10,306 $ 14,092 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 4.30 % 3.77 % 3.60 % 4.31 % 3.81 % 3.70 % Effective Rate for Interest on Benefit Obligations 4.03 % 3.23 % 3.60 % 4.05 % 3.29 % 3.70 % Effective Discount Rate for Service Cost 4.40 % 4.00 % 3.60 % 4.43 % 4.10 % 3.70 % Effective Rate for Interest on Service Cost 4.29 % 3.73 % 3.60 % 4.39 % 3.98 % 3.70 % Expected Return on Plan Assets 6.75 % 7.00 % 7.00 % 6.00 % 6.25 % 6.50 % 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 $7.6 million , $6.8 million and $7.6 million in 2019 , 2018 and 2017 , respectively. The accumulated benefit obligations for the plans were $79.8 million , $70.6 million and $72.5 million at September 30, 2019 , 2018 and 2017 , respectively. The projected benefit obligations for the plans were $99.5 million , $86.1 million and $88.9 million at September 30, 2019 , 2018 and 2017 , respectively. At September 30, 2019 , $13.2 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $86.3 million is 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. At September 30, 2017 , $14.1 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $74.8 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 2.77% , 4.02% and 3.22% as of September 30, 2019 , 2018 and 2017 , respectively and the weighted average rates of compensation increase for these plans were 8.00% , 7.75% and 7.75% as of September 30, 2019 , 2018 and 2017 , respectively. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2019 , the changes in such amounts during 2019 , as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2020 are presented in the table below: Retirement Plan Other Post-Retirement Benefits Non-Qualified Benefit Plans (Thousands) Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) Net Actuarial Loss $ (216,146 ) $ (27,398 ) $ (33,477 ) Prior Service (Cost) Credit (4,370 ) 2,829 — Net Amount Recognized $ (220,516 ) $ (24,569 ) $ (33,477 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2019(1) Increase in Actuarial Loss, excluding amortization(2) $ (112,715 ) $ (34,553 ) $ (14,217 ) Change due to Amortization of Actuarial Loss 32,096 5,962 3,558 Prior Service (Cost) Credit 826 (429 ) — Net Change $ (79,793 ) $ (29,020 ) $ (10,659 ) Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (39,384 ) $ (535 ) $ (5,341 ) Prior Service (Cost) Credit (729 ) 429 — Net Amount Expected to be Recognized $ (40,113 ) $ (106 ) $ (5,341 ) (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, 2019 , the Company recorded an $82.7 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $36.8 million (pre-tax) decrease to Accumulated Other Comprehensive Income. 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 mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2019 by $5.3 million . Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2019 by $4.7 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 effect of the discount rate change for the Retirement Plan in 2017 was to decrease the projected benefit obligation of the Retirement Plan by $20.5 million . The Company made cash contributions totaling $29.2 million to the Retirement Plan during the year ended September 30, 2019. The Company expects that the annual contribution to the Retirement Plan in 2020 will be in the range of $25.0 million to $30.0 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: $66.3 million in 2020; $66.8 million in 2021; $67.1 million in 2022; $67.1 million in 2023; $67.1 million in 2024; and $328.7 million in the five years thereafter. 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 , 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 2017 was to decrease the other post-retirement benefit obligation by $6.2 million . The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2017 by $5.7 million . Other actuarial experience decreased the other post-retirement benefit obligation in 2017 by $50.3 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 2020 $ 27,998 $ (1,901 ) 2021 $ 28,711 $ (2,025 ) 2022 $ 29,142 $ (2,147 ) 2023 $ 29,478 $ (2,264 ) 2024 $ 29,631 $ (2,372 ) 2025 through 2029 $ 147,138 $ (12,960 ) Assumed health care cost trend rates as of September 30 were: 2019 2018 2017 Rate of Medical Cost Increase for Pre Age 65 Participants 5.50 % (1) 5.59 % (1) 5.67 % (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 7.35 % (1) 7.89 % (1) 8.45 % (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 6.84 % (1) 7.18 % (1) 7.33 % (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, 2019 would increase by $60.8 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 2019 by $2.7 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, 2019 would decrease by $49.1 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 2019 by $2.1 million . The Company made cash contributions totaling $2.8 million to its VEBA trusts during the year ended September 30, 2019 . 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, 2019 . The Company expects that the annual contribution to its VEBA trusts in 2020 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 G — 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, 2019 and 2018 , 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, 2019 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) 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 At September 30, 2018 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) Retirement Plan Investments Domestic Equities(1) $ 223,300 $ 139,885 $ — $ — $ 83,415 International Equities(2) 100,832 — — — 100,832 Global Equities(3) 85,942 — — — 85,942 Domestic Fixed Income(4) 434,392 1,640 382,348 — 50,404 International Fixed Income(5) 416 416 — — — Global Fixed Income(6) 72,382 — — — 72,382 Real Estate 53,878 — — 3,194 50,684 Cash Held in Collective Trust Funds 26,191 — — — 26,191 Total Retirement Plan Investments 997,333 141,941 382,348 3,194 469,850 401(h) Investments (67,817 ) (9,695 ) (26,114 ) (218 ) (31,790 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 929,516 $ 132,246 $ 356,234 $ 2,976 $ 438,060 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (5,010 ) Total Retirement Plan Assets $ 924,506 (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, 2019 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(1) Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 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 At September 30, 2018 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(1) Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Domestic Equities $ 125,295 $ — $ — $ — $ 125,295 Collective Trust Funds — International Equities 47,245 — — — 47,245 Exchange Traded Funds — Fixed Income 265,667 265,667 — — — Cash Held in Collective Trust Funds 7,894 — — — 7,894 Total VEBA Trust Investments 446,101 265,667 — — 180,434 401(h) Investments 67,817 9,695 26,114 218 31,790 Total Investments (including 401(h) Investments) $ 513,918 $ 275,362 $ 26,114 $ 218 $ 212,224 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (118 ) Total Other Post-Retirement Benefit Assets $ 513,800 (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, 2019 and September 30, 2018 , there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3. Retirement Plan Level 3 Assets (Thousands) Real Estate Excluding 401(h) Investments Total Balance at September 30, 2017 $ 3,391 $ (225 ) $ 3,166 Unrealized Gains/(Losses) 188 (19 ) 169 Sales (385 ) 26 (359 ) 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 Other Post-Retirement Benefit Level 3 Assets (Thousands) 401(h) Investments Balance at September 30, 2017 $ 225 Unrealized Gains/(Losses) 19 Sales (26 ) Balance at September 30, 2018 218 Unrealized Gains/(Losses) 5 Sales — Balance at September 30, 2019 $ 223 The Company’s assumption regarding the expected long-term rate of return on plan assets is 6.40% (Retirement Plan) and 5.70% (other post-retirement benefits), effective for fiscal 2020. 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.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Sep. 30, 2019
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, 2019, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $7.0 million , which includes a $3.8 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, 2019. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 3 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, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company remains committed to the project. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022. Other The Company, in its Utility segment, Exploration and Production segment, and its NFR operations (included in the All Other category), 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: $256.4 million in 2020, $78.5 million in 2021, $111.2 million in 2022, $110.8 million in 2023, $115.6 million in 2024 and $1,098.8 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 has entered into leases for the use of buildings and office space, drilling rigs, compressor equipment and other miscellaneous assets. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $12.4 million in 2020, $2.8 million in 2021, $2.3 million in 2022, $2.3 million in 2023, $2.2 million in 2024 and $9.7 million thereafter. 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, 2019, the future contractual commitments related to the system modernization and expansion projects are $97.5 million in 2020, $34.9 million in 2021, $6.0 million in 2022, $3.3 million in 2023, $3.3 million in 2024 and $11.6 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, and fuel purchases for steam generation. The future contractual commitments are $104.3 million in 2020, $22.2 million in 2021 and $1.7 million in 2022. There are no contractual commitments extending beyond 2022. The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note D — 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, 2019
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 Company previously reported financial results for five business segments: Exploration and Production, Pipeline and Storage, Gathering, Utility and Energy Marketing. However, management has made the decision to eliminate the Energy Marketing segment as a reportable segment based on the fact that the energy marketing operations do not meet any of the quantitative thresholds specified by authoritative guidance related to segment reporting. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the energy marketing operations, and management no longer considers the energy marketing operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the energy marketing operations cannot be aggregated into one of the other four reportable business segments, the energy marketing operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation. The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas and oil reserves in California and the Appalachian region of the United States. The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR), 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 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, 2019 Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 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 and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Elimination Total Consolidated (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 Year Ended September 30, 2017 Exploration Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 614,599 $ 206,615 $ 115 $ 626,899 $ 1,448,228 $ 130,759 $ 894 $ 1,579,881 Intersegment Revenues $ — $ 87,810 $ 107,566 $ 13,072 $ 208,448 $ 794 $ (209,242 ) $ — Interest Income $ 707 $ 1,467 $ 994 $ 1,051 $ 4,219 $ 784 $ (890 ) $ 4,113 Interest Expense $ 53,702 $ 33,717 $ 9,142 $ 28,492 $ 125,053 $ 47 $ (5,263 ) $ 119,837 Depreciation, Depletion and Amortization $ 112,565 $ 41,196 $ 16,162 $ 52,582 $ 222,505 $ 940 $ 750 $ 224,195 Income Tax Expense (Benefit) $ 66,093 $ 40,947 $ 29,694 $ 24,894 $ 161,628 $ 644 $ (1,590 ) $ 160,682 Segment Profit: Net Income (Loss) $ 129,326 $ 68,446 $ 40,377 $ 46,935 $ 285,084 $ 1,167 $ (2,769 ) $ 283,482 Expenditures for Additions to Long-Lived Assets $ 253,057 $ 95,336 $ 32,645 $ 80,867 $ 461,905 $ 75 $ 137 $ 462,117 At September 30, 2017 (Thousands) Segment Assets $ 1,407,152 $ 1,929,788 $ 580,051 $ 2,013,123 $ 5,930,114 $ 137,798 $ 35,408 $ 6,103,320 (1) All Revenue from External Customers originated in the United States. Geographic Information At September 30 2019 2018 2017 (Thousands) Long-Lived Assets: United States $ 6,099,534 $ 5,491,895 $ 5,285,040

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Sep. 30, 2019
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 Revenues Operating Income Net Income Available for Common Stock Earnings per Common Share Basic Diluted (Thousands, except per common share amounts) 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 (1) $ 1.19 $ 1.18 2018 9/30/2018 $ 289,196 $ 84,662 $ 37,995 (2) $ 0.44 $ 0.44 6/30/2018 $ 342,912 $ 114,003 $ 63,025 $ 0.73 $ 0.73 3/31/2018 $ 540,905 $ 171,589 $ 91,847 (3) $ 1.07 $ 1.06 12/31/2017 $ 419,655 $ 149,469 $ 198,654 (4) $ 2.32 $ 2.30 (1) 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. (2) Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act. (3) Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act. (4) Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated

Supplementary Information For O

Supplementary Information For Oil And Gas Producing Activities	12 Months Ended
	Sep. 30, 2019
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 2019 2018 (Thousands) Proved Properties(1) $ 5,623,623 $ 5,114,753 Unproved Properties 53,498 62,234 5,677,121 5,176,987 Less — Accumulated Depreciation, Depletion and Amortization 4,012,568 3,862,687 $ 1,664,553 $ 1,314,300 (1) Includes asset retirement costs of $70.5 million and $44.3 million at September 30, 2019 and 2018, 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 2024. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2022. Following is a summary of costs excluded from amortization at September 30, 2019: Total as of September 30, 2019 Year Costs Incurred 2019 2018 2017 Prior (Thousands) Acquisition Costs $ 24,265 $ — $ — $ — $ 24,265 Development Costs 21,483 17,819 481 43 3,140 Exploration Costs 7,606 — — 32 7,574 Capitalized Interest 144 41 — — 103 $ 53,498 $ 17,860 $ 481 $ 75 $ 35,082 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2019 2018 2017 (Thousands) United States Property Acquisition Costs: Proved $ 3,136 $ 1,544 $ 8,908 Unproved 3,679 4,286 262 Exploration Costs(1) 2,060 29,365 40,975 Development Costs(2) 468,498 332,496 200,639 Asset Retirement Costs 26,192 (10,107 ) (9,175 ) $ 503,565 $ 357,584 $ 241,609 (1) Amounts for 2019, 2018 and 2017 include capitalized interest of zero , zero and $0.3 million , respectively. (2) Amounts for 2019, 2018 and 2017 include capitalized interest of $0.2 million , $0.3 million and $0.2 million , respectively. For the years ended September 30, 2019, 2018 and 2017, the Company spent $246.0 million , $182.3 million and $101.1 million , respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2019 2018 2017 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of $2,532, $2,134 and $2,357, respectively)(1) $ 481,048 $ 390,642 $ 399,975 Oil, Condensate and Other Liquids 149,078 168,254 126,517 Total Operating Revenues(2) 630,126 558,896 526,492 Production/Lifting Costs 186,626 162,721 165,991 Franchise/Ad Valorem Taxes 17,673 14,355 15,372 Purchased Emission Allowance Expense 2,527 1,883 1,391 Accretion Expense 3,723 4,266 4,896 Depreciation, Depletion and Amortization ($0.71, $0.67 and $0.63 per Mcfe of production, respectively) 149,881 119,946 108,471 Income Tax Expense 64,652 72,723 86,657 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 205,044 $ 183,002 $ 143,714 (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 H — 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, 2019 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 Region West Coast Region Total Company Proved Developed and Undeveloped Reserves: September 30, 2016 1,631,451 43,124 1,674,575 Extensions and Discoveries 386,649 (1) 8 386,657 Revisions of Previous Estimates 84,480 6,369 90,849 Production (154,093 ) (2) (2,995 ) (157,088 ) Sale of Minerals in Place (21,873 ) — (21,873 ) 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 Proved Developed Reserves: September 30, 2016 1,089,492 43,124 1,132,616 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 Proved Undeveloped Reserves: September 30, 2016 541,959 — 541,959 September 30, 2017 610,018 — 610,018 September 30, 2018 750,810 — 750,810 September 30, 2019 1,014,724 — 1,014,724 (1) Extensions and discoveries include 181 Bcf (during 2017), 274 Bcf (during 2018) and 175 Bcf (during 2019), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 205 Bcf (during 2017), 248 Bcf (during 2018) and 512 Bcf (during 2019), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 145,452 MMcf (during 2017), 150,196 MMcf (during 2018) and 163,015 MMcf (during 2019), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018) and 32,095 MMcf (during 2019), from Utica Shale fields. Oil Mbbl U.S. Appalachian Region West Coast Region Total Company Proved Developed and Undeveloped Reserves: September 30, 2016 73 28,936 29,009 Extensions and Discoveries — 674 674 Revisions of Previous Estimates (12 ) 3,305 3,293 Production (4 ) (2,736 ) (2,740 ) Sales of Minerals in Place (29 ) — (29 ) 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 Proved Developed Reserves: September 30, 2016 73 28,698 28,771 September 30, 2017 28 29,771 29,799 September 30, 2018 14 26,689 26,703 September 30, 2019 13 24,246 24,259 Proved Undeveloped Reserves: September 30, 2016 — 238 238 September 30, 2017 — 408 408 September 30, 2018 — 960 960 September 30, 2019 — 614 614 The Company’s proved undeveloped (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 Company’s PUD reserves increased from 612 Bcfe at September 30, 2017 to 757 Bcfe at September 30, 2018. PUD reserves in the Marcellus Shale decreased from 456 Bcfe at September 30, 2017 to 394 Bcfe at September 30, 2018. PUD reserves in the Utica Shale increased from 154 Bcfe at September 30, 2017 to 357 Bcfe at September 30, 2018. The Company’s total PUD reserves were 30% of total proved reserves at September 30, 2018, up from 28% of total proved reserves at September 30, 2017. 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 increase in PUD reserves in 2018 of 145 Bcfe is a result of 431 Bcfe in new PUD reserve additions ( 229 Bcfe from the Marcellus Shale, 197 Bcfe from the Utica Shale and 5 Bcfe from the West Coast region) and 60 Bcfe in upward revisions to remaining PUD reserves, partially offset by 284 Bcfe in PUD conversions to developed reserves ( 264 Bcfe from the Marcellus Shale, 18 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region), 5 Bcfe in PUD reserves removed for one Marcellus PUD and sales of 57 Bcfe in PUD working interest reserves sold as part of a joint development agreement with IOG CRV - Marcellus, LLC. 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, 2018. The Company invested $182 million during the year ended September 30, 2018 to convert 284 Bcfe of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 46% of the net PUD reserves recorded at September 30, 2017 (or 51% of remaining net PUD reserves after 57 Bcfe in PUD working interest reserves were sold as part of the joint development agreement, as previously discussed). In fiscal 2018, the Company developed 53 (or 62% ) of its well locations with net PUD reserves recorded at September 30, 2017. The vast majority of these wells were in the Appalachian region. In 2020, the Company estimates that it will invest approximately $251 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 33% of its beginning year PUD reserves in fiscal 2015, 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 and 39% of its beginning year PUD reserves in fiscal 2019. At September 30, 2019, the Company does not have a material concentration of 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 2019 2018 2017 (Thousands) United States Future Cash Inflows $ 8,738,182 $ 7,822,855 $ 6,144,317 Less: Future Production Costs 2,989,518 2,606,411 2,378,262 Future Development Costs 797,640 559,707 411,578 Future Income Tax Expense at Applicable Statutory Rate 1,159,882 1,125,910 1,160,469 Future Net Cash Flows 3,791,142 3,530,827 2,194,008 Less: 10% Annual Discount for Estimated Timing of Cash Flows 2,054,823 1,810,522 1,080,962 Standardized Measure of Discounted Future Net Cash Flows $ 1,736,319 $ 1,720,305 $ 1,113,046 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2019 2018 2017 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,720,305 $ 1,113,046 $ 642,528 Sales, Net of Production Costs (425,773 ) (381,775 ) (345,075 ) Net Changes in Prices, Net of Production Costs (164,428 ) 541,021 828,187 Extensions and Discoveries 202,683 212,494 170,500 Changes in Estimated Future Development Costs (69,254 ) (43,771 ) 8,816 Sales of Minerals in Place — (100,816 ) (9,849 ) Previously Estimated Development Costs Incurred 245,964 182,348 101,134 Net Change in Income Taxes at Applicable Statutory Rate 21,370 55,558 (393,353 ) Revisions of Previous Quantity Estimates 53,777 61,363 39,078 Accretion of Discount and Other 151,675 80,837 71,080 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,736,319 $ 1,720,305 $ 1,113,046

Valuation And Qualifying Accoun

Valuation And Qualifying Accounts	12 Months Ended
	Sep. 30, 2019
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, 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 Year Ended September 30, 2017 Allowance for Uncollectible Accounts $ 21,109 $ 6,301 $ 1,774 $ 6,658 $ 22,526 (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 2019, there was a $5.0 million

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Sep. 30, 2019
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.
Reclassifications	Reclassifications In November 2016, the FASB issued authoritative guidance related to the presentation of restricted cash on the statement of cash flows. The new guidance requires restricted cash and cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and requires disclosure of how cash and cash equivalents on the statement of cash flows reconciles to the balance sheet. The Company considers Hedging Collateral Deposits to be restricted cash. The Company adopted this guidance effective October 1, 2018 on a retrospective basis. As a result, prior periods have been reclassified to conform to the current year presentation. Additional discussion is provided below at Consolidated Statement of Cash Flows. In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component is eligible to be capitalized as part of the cost of inventory or property, plant and equipment while the other components of net periodic pension cost and net periodic postretirement benefit cost are generally not eligible for capitalization, unless allowed by a regulator. The Company adopted this guidance effective October 1, 2018. The Company applied the guidance retrospectively for the pension and postretirement benefit costs using amounts disclosed in prior period financial statement notes as estimates for the reclassifications in accordance with a practical expedient allowed under the guidance. For the years ended September 30, 2018 and September 30, 2017, Operating Income increased $32.6 million and $40.9 million , respectively, and Other Income (Deductions) decreased by the same amounts as a result of the reclassifications. For the year ended September 30, 2019, Other Income (Deductions) includes $27.3 million of pension and postretirement benefit costs.
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 D — 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 and other specific information about customer accounts. 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.
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 D — 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.
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 $1.7 billion and $1.3 billion at September 30, 2019 and 2018, respectively. For further discussion of capitalized costs, refer to Note M — 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. At September 30, 2019, the ceiling exceeded the book value of the oil and gas properties by $381.2 million . In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2019, 2018 and 2017, estimated future net cash flows were decreased by $17.7 million , decreased by $25.1 million and increased by $30.5 million , respectively. The Company entered into a purchase and sale agreement to sell its oil and gas properties in the Sespe Field area of Ventura County, California in October 2017 for $43.0 million . The Company completed the sale on May 1, 2018, effective as of October 1, 2017, 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 for the year ended September 30, 2018). The net proceeds received by the Company were adjusted for production revenue and production expenses retained by the Company between the effective date of the sale and the closing date, resulting in lower proceeds from sale at the closing date. 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 and $26.6 million in fiscal 2018 and fiscal 2017, respectively. 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 and fiscal 2017. 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. 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 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 $149.9 million , $119.9 million and $108.5 million for the years ended September 30, 2019, 2018 and 2017, respectively. In the All Other category, for timber properties, depletion, determined on a property by property basis, is charged to operations based on the actual amount of timber cut in relation to the total amount of recoverable timber. 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 2019 2018 (Thousands) Exploration and Production $ 5,747,731 $ 5,222,037 Pipeline and Storage 2,191,166 2,110,714 Gathering 577,021 527,188 Utility 2,159,841 2,104,437 All Other and Corporate 112,857 112,295 $ 10,788,616 $ 10,076,671 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2019 2018 2017 Exploration and Production, per Mcfe(1) $ 0.73 $ 0.70 $ 0.65 Pipeline and Storage 2.2 % 2.2 % 2.2 % Gathering 3.6 % 3.4 % 3.4 % Utility 2.7 % 2.8 % 2.8 % All Other and Corporate 1.8 % 2.4 % 1.5 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.71 , $0.67 and $0.63 per Mcfe of production in 2019 , 2018 and 2017 , respectively.
Goodwill	Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2019 and 2018 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, 2019 , 2018 and 2017 , 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 price swap agreements and futures contracts. The Company accounts for these instruments as either cash flow hedges or fair value hedges. In both cases, 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 G — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments. For effective 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 H — Financial Instruments for further discussion concerning cash flow hedges. For fair value hedges, the offset to the asset or liability that is recorded is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income. However, in the case of fair value hedges, the Company also records an asset or liability on the Consolidated Balance Sheets representing the change in fair value of the asset or firm commitment that is being hedged (see Other Current Assets section in this footnote). The offset to this asset or liability is a gain or loss recorded to operating revenues or purchased gas expense on the Consolidated Statements of Income as well. If the fair value hedge is effective, the gain or loss from the derivative financial instrument is offset by the gain or loss that arises from the change in fair value of the asset or firm commitment that is being hedged. Reference is made to Note H — Financial Instruments for further discussion concerning fair value hedges.
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2019, net of related tax effect, 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, 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 ) Year Ended September 30, 2018 Balance at October 1, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) Other Comprehensive Gains and Losses Before Reclassifications (51,556 ) 147 4,643 (46,766 ) Amounts Reclassified From Other Comprehensive Loss 2,144 (272 ) 7,267 9,139 Balance at September 30, 2018 $ (28,611 ) $ 7,437 $ (46,576 ) $ (67,750 ) 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 $1.0 million at both September 30, 2019 and 2018. The total amount for accumulated losses was $85.8 million and $45.6 million at September 30, 2019 and 2018, respectively. 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 loss for the year ended September 30, 2019 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Income (Loss) Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the Year Ended September 30, Affected Line Item in the Statement Where Net Income is Presented 2019 2018 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($3,460 ) $423 Operating Revenues Commodity Contracts (1,182 ) 952 Purchased Gas Foreign Currency Contracts (822 ) (2,564 ) Operating Revenues Gains (Losses) on Securities Available for Sale — 430 Other Income (Deductions) Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (264 ) (258 ) (1) Net Actuarial Loss (7,068 ) (9,446 ) (1) (12,796 ) (10,463 ) Total Before Income Tax 4,424 1,324 Income Tax Expense ($8,372 ) ($9,139 ) Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note I — 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 $29.6 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 2019, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $19.8 million at September 30, 2019. All other gas stored underground, which is recorded by NFR (included in the All Other category), is carried at an average cost method, subject to lower of cost or net realizable value adjustments.
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, 2019, the remaining weighted average amortization period for such costs was approximately 7 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 2019 2018 2017 2016 Cash and Temporary Cash Investments $ 20,428 $ 229,606 $ 555,530 $ 129,972 Hedging Collateral Deposits 6,832 3,441 1,741 1,484 Cash, Cash Equivalents, and Restricted Cash $ 27,260 $ 233,047 $ 557,271 $ 131,456 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 2019 2018 (Thousands) Prepayments $ 12,728 $ 11,126 Prepaid Property and Other Taxes 14,361 14,088 Federal Income Taxes Receivable 42,388 22,457 State Income Taxes Receivable 8,579 8,822 Fair Values of Firm Commitments 7,538 1,739 Regulatory Assets 11,460 9,792 $ 97,054 $ 68,024
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 2019 2018 (Thousands) Accrued Capital Expenditures $ 33,713 $ 38,354 Regulatory Liabilities 50,332 57,425 Liability for Royalty and Working Interests 18,057 12,062 Non-Qualified Benefit Plan Liability 13,194 11,536 Other 24,304 13,316 $ 139,600 $ 132,693
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, 2019 and 2018, customers in the balanced billing programs had advanced excess funds of $13.0 million and $13.6 million , respectively.
Customer Security Deposits	Customer Security Deposits The Company, primarily in its Utility and Pipeline and Storage segments, often times requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2019 and 2018, the Company had received customer security deposits amounting to $16.2 million and $25.7 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. 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, 317,899 securities and 157,649
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, both performance and nonperformance-based, 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 performance based and nonperformance-based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and nonperformance-based restricted stock units is the same as the accounting for restricted share 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.
New Authoritative Accounting And Financial Reporting Guidance	New Authoritative Accounting and Financial Reporting Guidance Leasing In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, requiring entities that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required entities to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases only while excluding operating leases from balance sheet recognition. The updated guidance provides entities with an optional transition method, which allows an entity to apply the new lease standard prospectively at the adoption date, elect not to reclassify comparable periods, and recognize a cumulative-effect adjustment to retained earnings in the period of adoption. The Company adopted the new leases standard on October 1, 2019, using the optional transition method. Comparative periods, including disclosures relating to those periods, will not be restated. The Company also elected to apply the following practical expedients provided in the 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 leases standard 2. An election not to apply the recognition requirements in the new leases standard to short-term leases (a lease that at commencement date has a lease term of twelve months or less) 3. A practical expedient to not reassess certain land easements that existed prior to October 1, 2019; 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). The Company has completed its determination and evaluation of its population of existing lease contracts as of October 1, 2019, which include leases of office buildings and facilities, land for surface use, compressors and field equipment, and other leases. The new leases standard does not apply to leases to explore for or use minerals, oil or gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company has documented the nature and impact of technical issues and related accounting policy elections. The Company has also designed and implemented procedures and internal controls to ensure that contracts that are leases or contain lease components are appropriately accounted for under the authoritative guidance, including both new contracts and modifications to existing contracts. The Company expects to recognize a right of use asset for operating leases and a corresponding operating lease liability on its Consolidated Balance Sheets of approximately $20.0 million , representing the present value of the minimum remaining payment obligations of existing lease contracts with lease terms greater than twelve months. The Company’s adoption did not require an adjustment to the opening balance of retained earnings. The Company does not expect the adoption of the new leases standard to have a material effect on its results of operations or cash flows. Additional disclosures will be required to describe the nature of the Company’s leases, significant assumptions and judgments, amounts recognized in the financial statements, maturity of lease liabilities, and accounting policy elections. Hedging 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

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Schedule Of Depreciable Plant By Segment	The following is a summary of depreciable plant by segment: As of September 30 2019 2018 (Thousands) Exploration and Production $ 5,747,731 $ 5,222,037 Pipeline and Storage 2,191,166 2,110,714 Gathering 577,021 527,188 Utility 2,159,841 2,104,437 All Other and Corporate 112,857 112,295 $ 10,788,616 $ 10,076,671
Average Depreciation Depletion And Amortization Rates	Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2019 2018 2017 Exploration and Production, per Mcfe(1) $ 0.73 $ 0.70 $ 0.65 Pipeline and Storage 2.2 % 2.2 % 2.2 % Gathering 3.6 % 3.4 % 3.4 % Utility 2.7 % 2.8 % 2.8 % All Other and Corporate 1.8 % 2.4 % 1.5 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.71 , $0.67 and $0.63 per Mcfe of production in 2019 , 2018 and 2017 , respectively.
Components Of Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2019, net of related tax effect, 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, 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 ) Year Ended September 30, 2018 Balance at October 1, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) Other Comprehensive Gains and Losses Before Reclassifications (51,556 ) 147 4,643 (46,766 ) Amounts Reclassified From Other Comprehensive Loss 2,144 (272 ) 7,267 9,139 Balance at September 30, 2018 $ (28,611 ) $ 7,437 $ (46,576 ) $ (67,750 )
Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Income (Loss)	The details about the reclassification adjustments out of accumulated other comprehensive loss for the year ended September 30, 2019 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Income (Loss) Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the Year Ended September 30, Affected Line Item in the Statement Where Net Income is Presented 2019 2018 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($3,460 ) $423 Operating Revenues Commodity Contracts (1,182 ) 952 Purchased Gas Foreign Currency Contracts (822 ) (2,564 ) Operating Revenues Gains (Losses) on Securities Available for Sale — 430 Other Income (Deductions) Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Cost (264 ) (258 ) (1) Net Actuarial Loss (7,068 ) (9,446 ) (1) (12,796 ) (10,463 ) Total Before Income Tax 4,424 1,324 Income Tax Expense ($8,372 ) ($9,139 ) Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note I — Retirement Plan and Other Post-Retirement Benefits for additional details.
Schedule of Cash, Cash Equivalents and Restricted Cash	The components, as reported on the Company's Consolidated Balance Sheets, of the total cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands): Year Ended September 30 2019 2018 2017 2016 Cash and Temporary Cash Investments $ 20,428 $ 229,606 $ 555,530 $ 129,972 Hedging Collateral Deposits 6,832 3,441 1,741 1,484 Cash, Cash Equivalents, and Restricted Cash $ 27,260 $ 233,047 $ 557,271 $ 131,456
Schedule Of Other Current Assets	The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2019 2018 (Thousands) Prepayments $ 12,728 $ 11,126 Prepaid Property and Other Taxes 14,361 14,088 Federal Income Taxes Receivable 42,388 22,457 State Income Taxes Receivable 8,579 8,822 Fair Values of Firm Commitments 7,538 1,739 Regulatory Assets 11,460 9,792 $ 97,054 $ 68,024
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 2019 2018 (Thousands) Accrued Capital Expenditures $ 33,713 $ 38,354 Regulatory Liabilities 50,332 57,425 Liability for Royalty and Working Interests 18,057 12,062 Non-Qualified Benefit Plan Liability 13,194 11,536 Other 24,304 13,316 $ 139,600 $ 132,693

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Tables)	12 Months Ended
	Sep. 30, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table provides a disaggregation of the Company's revenues for the year ended September 30, 2019, presented by type of service from each reportable segment. Year Ended September 30, 2019 Revenues by Type of Service Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Production of Natural Gas $ 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

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Sep. 30, 2019
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 2019 2018 2017 (Thousands) Balance at Beginning of Year $ 108,235 $ 106,395 $ 112,330 Liabilities Incurred 4,122 5,597 2,963 Revisions of Estimates 16,693 (419 ) (10,578 ) Liabilities Settled (7,670 ) (12,858 ) (4,967 ) Accretion Expense 6,078 9,520 6,647 Balance at End of Year $ 127,458 $ 108,235 $ 106,395

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2019
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 2019 2018 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note I) $ 114,509 $ 62,703 Post-Retirement Benefit Costs(2) (Note I) 18,236 11,160 Recoverable Future Taxes (Note E) 115,197 115,460 Environmental Site Remediation Costs(2) (Note J) 15,317 20,308 Asset Retirement Obligations(2) (Note C) 15,696 15,495 Unamortized Debt Expense (Note A) 14,005 15,975 Other(3) 15,022 13,044 Total Regulatory Assets 307,982 254,145 Less: Amounts Included in Other Current Assets (11,460 ) (9,792 ) Total Long-Term Regulatory Assets $ 296,522 $ 244,353 At September 30 2019 2018 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 221,699 $ 212,311 Taxes Refundable to Customers (Note E) 366,503 370,628 Post-Retirement Benefit Costs(4) (Note I) 126,577 134,387 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 4,017 3,394 Other(5) 66,122 69,781 Total Regulatory Liabilities 784,918 790,501 Less: Amounts included in Current and Accrued Liabilities (54,349 ) (60,819 ) Total Long-Term Regulatory Liabilities $ 730,569 $ 729,682 (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) $11,460 and $9,792 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,562 and $3,252 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively. (4) Included in Other Regulatory Liabilities on the Consolidated Balance Sheets. (5) $50,332 and $57,425 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,790 and $12,356 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2019
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 2019 2018 2017 (Thousands) Current Income Taxes — Federal $ (41,645 ) $ 2,025 $ 32,034 State 4,601 8,634 10,673 Deferred Income Taxes — Federal 98,514 (38,927 ) 103,046 State 23,751 20,774 14,929 85,221 (7,494 ) 160,682 Deferred Investment Tax Credit (91 ) (105 ) (173 ) Total Income Taxes $ 85,130 $ (7,599 ) $ 160,509 Presented as Follows: Other (Income) Deductions $ (91 ) $ (105 ) $ (173 ) Income Tax Expense (Benefit) 85,221 (7,494 ) 160,682 Total Income Taxes $ 85,130 $ (7,599 ) $ 160,509
Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate	The following is a reconciliation of this difference: Year Ended September 30 2019 2018 2017 (Thousands) U.S. Income Before Income Taxes $ 389,420 $ 383,922 $ 443,991 Income Tax Expense, Computed at U.S. Federal Statutory Rate(1) $ 81,778 $ 94,061 $ 155,397 State Income Tax Expense(2) 22,397 22,203 16,641 Federal Tax Credits (7,361 ) (6,576 ) (6,679 ) Amortization of Excess Deferred Federal Income Taxes(3) (5,036 ) (3,236 ) — Impact of 2017 Tax Reform Act(4) (5,000 ) (112,598 ) — Miscellaneous (1,648 ) (1,453 ) (4,850 ) Total Income Taxes $ 85,130 $ (7,599 ) $ 160,509 (1) For fiscal 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. For fiscal 2017, the statutory rate of 35% was utilized. (2) The state income tax expense 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. (3) Represents amortization of excess deferred federal income taxes under the 2017 Tax Reform Act. (4) 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 Deferred Tax Liabilities And Assets	Significant components of the Company’s deferred tax liabilities and assets were as follows: At September 30 2019 2018 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 861,278 $ 770,794 Pension and Other Post-Retirement Benefit Costs 55,795 39,541 Other 54,486 49,734 Total Deferred Tax Liabilities 971,559 860,069 Deferred Tax Assets: Tax Loss and Credit Carryforwards (175,542 ) (214,128 ) Pension and Other Post-Retirement Benefit Costs (87,280 ) (62,969 ) Other (55,355 ) (75,286 ) Total Gross Deferred Tax Assets (318,177 ) (352,383 ) Valuation Allowance — 5,000 Total Deferred Tax Assets (318,177 ) (347,383 ) Total Net Deferred Income Taxes $ 653,382 $ 512,686
Reconciliation Of The Change In Unrecognized Tax Benefits	The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2019 2018 2017 (Thousands) Balance at Beginning of Year $ — $ 1,251 $ 396 Additions for Tax Positions of Prior Years — — 1,251 Reductions for Tax Positions of Prior Years — (788 ) (396 ) Reductions Related to Settlements with Taxing Authorities — (463 ) — Balance at End of Year $ — $ — $ 1,251
Summary of Operating Loss and Tax Credit Carryforwards	As of September 30, 2019, the Company has the following carryforwards available: Jurisdiction Tax Attribute Amount (Thousands) Expires Federal Pre-Fiscal 2018 Net Operating Loss $ 143,571 2032-2033 Federal Post-Fiscal 2017 Net Operating Loss 54,789 Unlimited Pennsylvania Net Operating Loss 383,056 2030-2039 California Net Operating Loss 207,995 2030-2039 Federal Alternative Minimum Tax Credit 42,546 Unlimited California Alternative Minimum Tax Credit 7,711 Unlimited Federal Enhanced Oil Recovery Credit 26,790 2029-2039 California Enhanced Oil Recovery Credit 8,504 2037-2039 Federal R&D Tax Credit 6,339 2031-2039 Federal Charitable Contributions 2,097 2023

Capitalization And Short-Term_2

Capitalization And Short-Term Borrowings (Tables)	12 Months Ended
	Sep. 30, 2019
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 Capital Earnings Reinvested in the Business Accumulated Other Comprehensive Income (Loss) Shares Amount (Thousands, except per share amounts) Balance at September 30, 2016 85,119 $ 85,119 $ 771,164 $ 676,361 $ (5,640 ) Net Income Available for Common Stock 283,482 Dividends Declared on Common Stock ($1.64 Per Share) (140,090 ) Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation 31,916 Other Comprehensive Loss, Net of Tax (24,483 ) Share-Based Payment Expense(1) 10,902 Common Stock Issued Under Stock and Benefit Plans 424 424 14,580 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 (2) $ (52,155 ) (1) Paid in Capital includes compensation costs associated with SARs, 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, 2019, $1.1 billion of accumulated earnings was free of such limitations.
Schedule Of Share-Based Compensation For SARs	Transactions for 2019 involving SARs for all plans are summarized as follows: Number of Shares Subject To Option Weighted Average Exercise Price Weighted Average Remaining Contractual Life (Years) Aggregate Intrinsic Value (In thousands) Outstanding at September 30, 2018 1,299,088 $ 50.70 Granted in 2019 — $ — Exercised in 2019 (528,456 ) $ 43.94 Forfeited in 2019 — $ — Expired in 2019 (37,500 ) $ 63.87 Outstanding at September 30, 2019 733,132 $ 54.90 1.73 $ — SARs exercisable at September 30, 2019 733,132 $ 54.90 1.73 $ — Shares available for future grant at September 30, 2019(1) 1,225,831 (1) Includes shares available for options, SARs, restricted stock and performance share grants.
Schedule Of Share-Based Compensation For Restricted Share Awards	Transactions for 2019 involving restricted share awards for all plans are summarized as follows: Number of Restricted Share Awards Weighted Average Fair Value per Award Outstanding at September 30, 2018 20,000 $ 47.46 Granted in 2019 — $ — Vested in 2019 — $ — Forfeited in 2019 — $ — Outstanding at September 30, 2019 20,000 $ 47.46
Schedule Of Share-Based Compensation For Non-Performance Based Restricted Stock Units	Transactions for 2019 involving nonperformance-based restricted stock units for all plans are summarized as follows: Number of Restricted Stock Units Weighted Average Fair Value per Award Outstanding at September 30, 2018 245,316 $ 48.45 Granted in 2019 123,939 $ 49.40 Vested in 2019 (80,354 ) $ 48.24 Forfeited in 2019 (7,294 ) $ 50.40 Outstanding at September 30, 2019 281,607 $ 48.88
Schedule of Share-based Compensation for Performance Shares	Transactions for 2019 involving performance shares for all plans are summarized as follows: Number of Performance Shares Weighted Average Fair Value per Award Outstanding at September 30, 2018 641,290 $ 44.49 Granted in 2019 244,734 $ 55.67 Vested in 2019 (281,882 ) $ 31.16 Forfeited in 2019 (109,806 ) $ 54.19 Change in Units Based on Performance Achieved 28,178 $ 35.14 Outstanding at September 30, 2019 522,514 $ 54.37
Schedule Of Long-Term Debt	The outstanding long-term debt is as follows: At September 30 2019 2018 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(2)(3): 3.75% to 5.20% due December 2021 to September 2028 2,050,000 2,050,000 Total Long-Term Debt 2,149,000 2,149,000 Less Unamortized Discount and Debt Issuance Costs 15,282 17,635 Less Current Portion(4) — — $ 2,133,718 $ 2,131,365 (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). (4) None of the Company's long-term debt at September 30, 2019 and 2018 will mature within the following twelve-month period.
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 2019 2018 2017 Risk-Free Interest Rate 2.61 % 1.96 % 1.54 % Remaining Term at Date of Grant (Years) 2.78 2.78 2.79 Expected Volatility 20.2 % 22.0 % 22.6 % Expected Dividend Yield (Quarterly) N/A N/A N/A

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2019
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, 2019 and 2018. 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, 2019 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Adjustments(1) Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 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 At Fair Value as of September 30, 2018 Recurring Fair Value Measures Level 1 Level 2 Level 3 Netting Adjustments(1) Total(1) (Dollars in thousands) Assets: Cash Equivalents — Money Market Mutual Funds $ 215,272 $ — $ — $ — $ 215,272 Derivative Financial Instruments: Commodity Futures Contracts — Gas 1,075 — — (1,075 ) — Over the Counter Swaps — Gas and Oil — 26,074 — (17,041 ) 9,033 Foreign Currency Contracts — 443 — (443 ) — Other Investments: Balanced Equity Mutual Fund 38,468 — — — 38,468 Fixed Income Mutual Fund 51,331 — — — 51,331 Common Stock — Financial Services Industry 2,776 — — — 2,776 Hedging Collateral Deposits 3,441 — — — 3,441 Total $ 312,363 $ 26,517 $ — $ (18,559 ) $ 320,321 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 2,412 $ — $ — $ (1,075 ) $ 1,337 Over the Counter Swaps — Gas and Oil — 64,224 — (17,041 ) 47,183 Foreign Currency Contracts — 959 — (443 ) 516 Total $ 2,412 $ 65,183 $ — $ (18,559 ) $ 49,036 Total Net Assets/(Liabilities) $ 309,951 $ (38,666 ) $ — $ — $ 271,285 (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 (Tables)

Financial Instruments (Tables)	12 Months Ended
	Sep. 30, 2019
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 2019 Carrying Amount 2019 Fair Value 2018 Carrying 2018 Fair Value (Thousands) Long-Term Debt $ 2,133,718 $ 2,257,085 $ 2,131,365 $ 2,121,861
Schedule of Other Investments	The components of the Company's Other Investments are as follows (in thousands): At September 30 2019 2018 (Thousands) Life Insurance Contracts $ 41,074 $ 39,970 Equity Mutual Fund 40,660 38,468 Fixed Income Mutual Fund 62,339 51,331 Marketable Equity Securities 844 2,776 $ 144,917 $ 132,545
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 Year Ended September 30, 2019 and 2018 (Dollar Amounts in Thousands) Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Year Ended September 30, Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Year Ended September 30, Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Year Ended September 30, 2019 2018 2019 2018 2019 2018 Commodity Contracts $ 82,984 $ (70,905 ) Operating Revenue $ (3,460 ) $ 423 Operating Revenue $ 2,096 $ (782 ) Commodity Contracts (1,037 ) 701 Purchased Gas (1,182 ) 952 Not Applicable — — Foreign Currency Contracts (2,646 ) (3,899 ) Operating Revenue (822 ) (2,564 ) Not Applicable — — Total $ 79,301 $ (74,103 ) $ (5,464 ) $ (1,189 ) $ 2,096 $ (782 )
Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships	For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below. Derivatives in Fair Value Hedging Relationships Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2019 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2019 (In thousands) Commodity Contracts Operating Revenues $ 2,606 $ (2,606 ) Commodity Contracts Purchased Gas (665 ) 665 $ 1,941 $ (1,941 )

Retirement Plan And Other Pos_2

Retirement Plan And Other Post-Retirement Benefits (Tables)	12 Months Ended
	Sep. 30, 2019
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 date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2019 , 2018 and 2017 . Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2019 2018 2017 2019 2018 2017 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 985,690 $ 1,054,826 $ 1,097,421 $ 435,986 $ 462,619 $ 526,138 Service Cost 8,482 9,921 11,969 1,519 1,830 2,449 Interest Cost 38,378 33,006 38,383 17,145 14,801 19,007 Plan Participants’ Contributions — — — 2,930 2,894 2,717 Retiree Drug Subsidy Receipts — — — 1,855 1,545 1,553 Actuarial (Gain) Loss 127,748 (50,218 ) (32,466 ) 34,401 (21,039 ) (62,215 ) Benefits Paid (62,673 ) (61,845 ) (60,481 ) (25,673 ) (26,664 ) (27,030 ) Benefit Obligation at End of Period $ 1,097,625 $ 985,690 $ 1,054,826 $ 468,163 $ 435,986 $ 462,619 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 924,506 $ 910,719 $ 869,775 $ 513,800 $ 514,017 $ 494,320 Actual Return on Plan Assets 77,401 42,652 84,279 30,006 20,657 40,157 Employer Contributions 29,215 32,980 17,146 3,064 2,896 3,853 Plan Participants’ Contributions — — — 2,930 2,894 2,717 Benefits Paid (62,673 ) (61,845 ) (60,481 ) (25,673 ) (26,664 ) (27,030 ) Fair Value of Assets at End of Period $ 968,449 $ 924,506 $ 910,719 $ 524,127 $ 513,800 $ 514,017 Net Amount Recognized at End of Period (Funded Status) $ (129,176 ) $ (61,184 ) $ (144,107 ) $ 55,964 $ 77,814 $ 51,398 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (129,176 ) $ (61,184 ) $ (144,107 ) $ (4,553 ) $ (4,919 ) $ (4,972 ) Non-Current Assets — — — 60,517 82,733 56,370 Net Amount Recognized at End of Period $ (129,176 ) $ (61,184 ) $ (144,107 ) $ 55,964 $ 77,814 $ 51,398 Accumulated Benefit Obligation $ 1,053,914 $ 946,763 $ 1,010,179 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 3.15 % 4.30 % 3.77 % 3.17 % 4.31 % 3.81 % 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 2019 2018 2017 2019 2018 2017 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 8,482 $ 9,921 $ 11,969 $ 1,519 $ 1,830 $ 2,449 Interest Cost 38,378 33,006 38,383 17,145 14,801 19,007 Expected Return on Plan Assets (62,368 ) (61,715 ) (59,718 ) (30,157 ) (31,482 ) (31,458 ) Amortization of Prior Service Cost (Credit) 826 938 1,058 (429 ) (429 ) (429 ) Recognition of Actuarial Loss(1) 32,096 37,205 42,687 5,962 10,558 18,415 Net Amortization and Deferral for Regulatory Purposes 2,493 9,027 469 16,481 15,028 6,108 Net Periodic Benefit Cost $ 19,907 $ 28,382 $ 34,848 $ 10,521 $ 10,306 $ 14,092 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 4.30 % 3.77 % 3.60 % 4.31 % 3.81 % 3.70 % Effective Rate for Interest on Benefit Obligations 4.03 % 3.23 % 3.60 % 4.05 % 3.29 % 3.70 % Effective Discount Rate for Service Cost 4.40 % 4.00 % 3.60 % 4.43 % 4.10 % 3.70 % Effective Rate for Interest on Service Cost 4.29 % 3.73 % 3.60 % 4.39 % 3.98 % 3.70 % Expected Return on Plan Assets 6.75 % 7.00 % 7.00 % 6.00 % 6.25 % 6.50 % 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 2019 , the changes in such amounts during 2019 , as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2020 are presented in the table below: Retirement Plan Other Post-Retirement Benefits Non-Qualified Benefit Plans (Thousands) Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) Net Actuarial Loss $ (216,146 ) $ (27,398 ) $ (33,477 ) Prior Service (Cost) Credit (4,370 ) 2,829 — Net Amount Recognized $ (220,516 ) $ (24,569 ) $ (33,477 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2019(1) Increase in Actuarial Loss, excluding amortization(2) $ (112,715 ) $ (34,553 ) $ (14,217 ) Change due to Amortization of Actuarial Loss 32,096 5,962 3,558 Prior Service (Cost) Credit 826 (429 ) — Net Change $ (79,793 ) $ (29,020 ) $ (10,659 ) Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (39,384 ) $ (535 ) $ (5,341 ) Prior Service (Cost) Credit (729 ) 429 — Net Amount Expected to be Recognized $ (40,113 ) $ (106 ) $ (5,341 ) (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 2020 $ 27,998 $ (1,901 ) 2021 $ 28,711 $ (2,025 ) 2022 $ 29,142 $ (2,147 ) 2023 $ 29,478 $ (2,264 ) 2024 $ 29,631 $ (2,372 ) 2025 through 2029 $ 147,138 $ (12,960 )
Schedule Of Health Care Cost Trend Rates	Assumed health care cost trend rates as of September 30 were: 2019 2018 2017 Rate of Medical Cost Increase for Pre Age 65 Participants 5.50 % (1) 5.59 % (1) 5.67 % (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 7.35 % (1) 7.89 % (1) 8.45 % (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 6.84 % (1) 7.18 % (1) 7.33 % (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, 2019 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) 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 At September 30, 2018 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) Retirement Plan Investments Domestic Equities(1) $ 223,300 $ 139,885 $ — $ — $ 83,415 International Equities(2) 100,832 — — — 100,832 Global Equities(3) 85,942 — — — 85,942 Domestic Fixed Income(4) 434,392 1,640 382,348 — 50,404 International Fixed Income(5) 416 416 — — — Global Fixed Income(6) 72,382 — — — 72,382 Real Estate 53,878 — — 3,194 50,684 Cash Held in Collective Trust Funds 26,191 — — — 26,191 Total Retirement Plan Investments 997,333 141,941 382,348 3,194 469,850 401(h) Investments (67,817 ) (9,695 ) (26,114 ) (218 ) (31,790 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 929,516 $ 132,246 $ 356,234 $ 2,976 $ 438,060 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (5,010 ) Total Retirement Plan Assets $ 924,506 (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).
Schedule Of Significant Unobservable Input Changes In Plan Assets	Retirement Plan Level 3 Assets (Thousands) Real Estate Excluding 401(h) Investments Total Balance at September 30, 2017 $ 3,391 $ (225 ) $ 3,166 Unrealized Gains/(Losses) 188 (19 ) 169 Sales (385 ) 26 (359 ) 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
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule Of Fair Value Of Plan Assets	At September 30, 2019 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(1) Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Global Equities $ 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 At September 30, 2018 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(1) Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Domestic Equities $ 125,295 $ — $ — $ — $ 125,295 Collective Trust Funds — International Equities 47,245 — — — 47,245 Exchange Traded Funds — Fixed Income 265,667 265,667 — — — Cash Held in Collective Trust Funds 7,894 — — — 7,894 Total VEBA Trust Investments 446,101 265,667 — — 180,434 401(h) Investments 67,817 9,695 26,114 218 31,790 Total Investments (including 401(h) Investments) $ 513,918 $ 275,362 $ 26,114 $ 218 $ 212,224 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (118 ) Total Other Post-Retirement Benefit Assets $ 513,800 (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 (Thousands) 401(h) Investments Balance at September 30, 2017 $ 225 Unrealized Gains/(Losses) 19 Sales (26 ) Balance at September 30, 2018 218 Unrealized Gains/(Losses) 5 Sales — Balance at September 30, 2019 $ 223

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Sep. 30, 2019
Segment Reporting [Abstract]
Segment Information By Segment	Year Ended September 30, 2019 Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 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 and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Elimination Total Consolidated (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 Year Ended September 30, 2017 Exploration Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 614,599 $ 206,615 $ 115 $ 626,899 $ 1,448,228 $ 130,759 $ 894 $ 1,579,881 Intersegment Revenues $ — $ 87,810 $ 107,566 $ 13,072 $ 208,448 $ 794 $ (209,242 ) $ — Interest Income $ 707 $ 1,467 $ 994 $ 1,051 $ 4,219 $ 784 $ (890 ) $ 4,113 Interest Expense $ 53,702 $ 33,717 $ 9,142 $ 28,492 $ 125,053 $ 47 $ (5,263 ) $ 119,837 Depreciation, Depletion and Amortization $ 112,565 $ 41,196 $ 16,162 $ 52,582 $ 222,505 $ 940 $ 750 $ 224,195 Income Tax Expense (Benefit) $ 66,093 $ 40,947 $ 29,694 $ 24,894 $ 161,628 $ 644 $ (1,590 ) $ 160,682 Segment Profit: Net Income (Loss) $ 129,326 $ 68,446 $ 40,377 $ 46,935 $ 285,084 $ 1,167 $ (2,769 ) $ 283,482 Expenditures for Additions to Long-Lived Assets $ 253,057 $ 95,336 $ 32,645 $ 80,867 $ 461,905 $ 75 $ 137 $ 462,117 At September 30, 2017 (Thousands) Segment Assets $ 1,407,152 $ 1,929,788 $ 580,051 $ 2,013,123 $ 5,930,114 $ 137,798 $ 35,408 $ 6,103,320 (1) All Revenue from External Customers originated in the United States.
Schedule Of Long-Lived Assets, By Geographical Areas	Geographic Information At September 30 2019 2018 2017 (Thousands) Long-Lived Assets: United States $ 6,099,534 $ 5,491,895 $ 5,285,040

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Sep. 30, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	Quarter Ended Operating Revenues Operating Income Net Income Available for Common Stock Earnings per Common Share Basic Diluted (Thousands, except per common share amounts) 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 (1) $ 1.19 $ 1.18 2018 9/30/2018 $ 289,196 $ 84,662 $ 37,995 (2) $ 0.44 $ 0.44 6/30/2018 $ 342,912 $ 114,003 $ 63,025 $ 0.73 $ 0.73 3/31/2018 $ 540,905 $ 171,589 $ 91,847 (3) $ 1.07 $ 1.06 12/31/2017 $ 419,655 $ 149,469 $ 198,654 (4) $ 2.32 $ 2.30 (1) 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. (2) Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act. (3) Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act. (4) Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated

Supplementary Information For_2

Supplementary Information For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Sep. 30, 2019
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 2019 2018 (Thousands) Proved Properties(1) $ 5,623,623 $ 5,114,753 Unproved Properties 53,498 62,234 5,677,121 5,176,987 Less — Accumulated Depreciation, Depletion and Amortization 4,012,568 3,862,687 $ 1,664,553 $ 1,314,300 (1) Includes asset retirement costs of $70.5 million and $44.3 million at September 30, 2019 and 2018, respectively.
Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization	Following is a summary of costs excluded from amortization at September 30, 2019: Total as of September 30, 2019 Year Costs Incurred 2019 2018 2017 Prior (Thousands) Acquisition Costs $ 24,265 $ — $ — $ — $ 24,265 Development Costs 21,483 17,819 481 43 3,140 Exploration Costs 7,606 — — 32 7,574 Capitalized Interest 144 41 — — 103 $ 53,498 $ 17,860 $ 481 $ 75 $ 35,082
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 2019 2018 2017 (Thousands) United States Property Acquisition Costs: Proved $ 3,136 $ 1,544 $ 8,908 Unproved 3,679 4,286 262 Exploration Costs(1) 2,060 29,365 40,975 Development Costs(2) 468,498 332,496 200,639 Asset Retirement Costs 26,192 (10,107 ) (9,175 ) $ 503,565 $ 357,584 $ 241,609 (1) Amounts for 2019, 2018 and 2017 include capitalized interest of zero , zero and $0.3 million , respectively. (2) Amounts for 2019, 2018 and 2017 include capitalized interest of $0.2 million , $0.3 million and $0.2 million , respectively.
Results Of Operations For Producing Activities	Results of Operations for Producing Activities Year Ended September 30 2019 2018 2017 United States (Thousands, except per Mcfe amounts) Operating Revenues: Gas (includes transfers to operations of $2,532, $2,134 and $2,357, respectively)(1) $ 481,048 $ 390,642 $ 399,975 Oil, Condensate and Other Liquids 149,078 168,254 126,517 Total Operating Revenues(2) 630,126 558,896 526,492 Production/Lifting Costs 186,626 162,721 165,991 Franchise/Ad Valorem Taxes 17,673 14,355 15,372 Purchased Emission Allowance Expense 2,527 1,883 1,391 Accretion Expense 3,723 4,266 4,896 Depreciation, Depletion and Amortization ($0.71, $0.67 and $0.63 per Mcfe of production, respectively) 149,881 119,946 108,471 Income Tax Expense 64,652 72,723 86,657 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 205,044 $ 183,002 $ 143,714 (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 H — Financial Instruments.
Proved Developed And Undeveloped Oil And Gas Reserve Quantities	Gas MMcf U.S. Appalachian Region West Coast Region Total Company Proved Developed and Undeveloped Reserves: September 30, 2016 1,631,451 43,124 1,674,575 Extensions and Discoveries 386,649 (1) 8 386,657 Revisions of Previous Estimates 84,480 6,369 90,849 Production (154,093 ) (2) (2,995 ) (157,088 ) Sale of Minerals in Place (21,873 ) — (21,873 ) 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 Proved Developed Reserves: September 30, 2016 1,089,492 43,124 1,132,616 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 Proved Undeveloped Reserves: September 30, 2016 541,959 — 541,959 September 30, 2017 610,018 — 610,018 September 30, 2018 750,810 — 750,810 September 30, 2019 1,014,724 — 1,014,724 (1) Extensions and discoveries include 181 Bcf (during 2017), 274 Bcf (during 2018) and 175 Bcf (during 2019), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 205 Bcf (during 2017), 248 Bcf (during 2018) and 512 Bcf (during 2019), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region. (2) Production includes 145,452 MMcf (during 2017), 150,196 MMcf (during 2018) and 163,015 MMcf (during 2019), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018) and 32,095 MMcf (during 2019), from Utica Shale fields. Oil Mbbl U.S. Appalachian Region West Coast Region Total Company Proved Developed and Undeveloped Reserves: September 30, 2016 73 28,936 29,009 Extensions and Discoveries — 674 674 Revisions of Previous Estimates (12 ) 3,305 3,293 Production (4 ) (2,736 ) (2,740 ) Sales of Minerals in Place (29 ) — (29 ) 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 Proved Developed Reserves: September 30, 2016 73 28,698 28,771 September 30, 2017 28 29,771 29,799 September 30, 2018 14 26,689 26,703 September 30, 2019 13 24,246 24,259 Proved Undeveloped Reserves: September 30, 2016 — 238 238 September 30, 2017 — 408 408 September 30, 2018 — 960 960 September 30, 2019 — 614 614
Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Year Ended September 30 2019 2018 2017 (Thousands) United States Future Cash Inflows $ 8,738,182 $ 7,822,855 $ 6,144,317 Less: Future Production Costs 2,989,518 2,606,411 2,378,262 Future Development Costs 797,640 559,707 411,578 Future Income Tax Expense at Applicable Statutory Rate 1,159,882 1,125,910 1,160,469 Future Net Cash Flows 3,791,142 3,530,827 2,194,008 Less: 10% Annual Discount for Estimated Timing of Cash Flows 2,054,823 1,810,522 1,080,962 Standardized Measure of Discounted Future Net Cash Flows $ 1,736,319 $ 1,720,305 $ 1,113,046
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 2019 2018 2017 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,720,305 $ 1,113,046 $ 642,528 Sales, Net of Production Costs (425,773 ) (381,775 ) (345,075 ) Net Changes in Prices, Net of Production Costs (164,428 ) 541,021 828,187 Extensions and Discoveries 202,683 212,494 170,500 Changes in Estimated Future Development Costs (69,254 ) (43,771 ) 8,816 Sales of Minerals in Place — (100,816 ) (9,849 ) Previously Estimated Development Costs Incurred 245,964 182,348 101,134 Net Change in Income Taxes at Applicable Statutory Rate 21,370 55,558 (393,353 ) Revisions of Previous Quantity Estimates 53,777 61,363 39,078 Accretion of Discount and Other 151,675 80,837 71,080 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,736,319 $ 1,720,305 $ 1,113,046

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Oct. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Oct. 01, 2019
Summary Of Significant Accounting Policies [Line Items]
Customer Security Deposits		$ 16,210	$ 25,703
Customer Advances		13,044	13,609
Pension and Postretirement Benefit Costs in Other Income and Deductions		27,300	32,600	$ 40,900
Capitalized Costs Oil And Gas Producing Activities Net		$ 1,664,553	1,314,300
Full cost ceiling test discount factor		10.00%
Amount full cost ceiling exceeds book value of oil and gas properties		$ 381,200
Increase (decrease) estimated future net cash flows		(17,700)	(25,100)	30,500
Net Proceeds from Sale of Oil and Gas Producing Properties		0	55,506	26,554
Depreciation, Depletion and Amortization Expense for Oil and Gas Properties		149,881	119,946	$ 108,471
Prior service cost		(1,000)	(1,000)
Goodwill		5,476	5,476
Gas stored underground		$ 36,632	$ 37,813
Antidilutive securities		242,302	317,899	157,649
Amount Exceeds LIFO Basis [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground		$ 19,800
LIFO Method [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground		29,600
Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Net Proceeds from Sale of Oil and Gas Producing Properties			$ 17,300	$ 26,600
Accumulated Losses [Member]
Summary Of Significant Accounting Policies [Line Items]
Accumulated losses		$ 85,800	45,600
Unamortized Debt Expense [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulated Reacquisition of Debt Cost Weighted Average Amortization Period		7 years
Sespe Field [Member]
Summary Of Significant Accounting Policies [Line Items]
Oil and Gas Producing Properties Purchase and Sale Agreement Price	$ 43,000
Net Proceeds from Sale of Oil and Gas Producing Properties			$ 38,200
Guidance for Reclassification of Stranded Tax Effects [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance		$ 10,400
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance		$ 7,400
Guidance for Leases [Member] | Forecast [Member]
Summary Of Significant Accounting Policies [Line Items]
Operating Lease Liability					$ 20,000
Right-of-Use Asset					20,000
Guidance for Hedge Accounting [Member] | Forecast [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance					$ (1,000)

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Schedule Of Depreciable Plant By Segment) (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Sep. 30, 2018
Segment Reporting Information [Line Items]
Depreciable plant	$ 10,788,616	$ 10,076,671
Utility [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,159,841	2,104,437
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,191,166	2,110,714
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciable plant	5,747,731	5,222,037
Gathering [Member]
Segment Reporting Information [Line Items]
Depreciable plant	577,021	527,188
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Depreciable plant	$ 112,857	$ 112,295

Summary Of Significant Accoun_6

Summary Of Significant Accounting Policies (Average Depreciation Depletion And Amortization Rates) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe	[1]	$ 0.73	$ 0.70	$ 0.65
Utility [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.70%	2.80%	2.80%
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.20%	2.20%	2.20%
Gathering [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		3.60%	3.40%	3.40%
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		1.80%	2.40%	1.50%
Oil And Gas Producing Properties [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe		$ 0.71	$ 0.67	$ 0.63
[1]	Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.71 , $0.67 and $0.63 per Mcfe of production in 2019 , 2018 and 2017 , 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, 2019	Sep. 30, 2018	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ (67,750)	$ (30,123)
Other Comprehensive Gains and Losses Before Reclassifications	25,066	(46,766)
Amounts Reclassified From Other Comprehensive Loss	8,372	9,139
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	(10,406)	0	$ 0
Ending balance	(52,155)	(67,750)	(30,123)
Gains and Losses on Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(28,611)	20,801
Other Comprehensive Gains and Losses Before Reclassifications	58,682	(51,556)
Amounts Reclassified From Other Comprehensive Loss	2,738	2,144
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)	20,801
Gains and Losses on Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	7,437	7,562
Other Comprehensive Gains and Losses Before Reclassifications	0	147
Amounts Reclassified From Other Comprehensive Loss	0	(272)
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	7,437	7,562
Funded Status of the Pension and Other Post-Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(46,576)	(58,486)
Other Comprehensive Gains and Losses Before Reclassifications	(33,616)	4,643
Amounts Reclassified From Other Comprehensive Loss	5,634	7,267
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	$ (86,830)	$ (46,576)	$ (58,486)

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, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ 293,341	$ 357,200	$ 552,544	$ 490,247		$ 289,196		$ 342,912	$ 540,905		$ 419,655		$ 1,693,332	$ 1,592,668	$ 1,579,881
Other Income (Deductions)														(15,542)	(21,174)	(29,777)
Income Before Income Taxes														389,511	384,027	444,164
Income Tax Expense														(85,221)	7,494	(160,682)
Net Income Available for Common Stock		$ 47,282	$ 63,753	$ 90,595	$ 102,660	[1]	$ 37,995	[2]	$ 63,025	$ 91,847	[3]	$ 198,654	[4]	304,290	391,521	283,482
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 Before Income Taxes														(12,796)	(10,463)
Income Tax Expense														4,424	1,324
Net Income Available for Common Stock														(8,372)	(9,139)
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Gains and Losses on Securities Available for Sale [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Income (Deductions)														0	430
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]													(264)	(258)
Recognition of Net Actuarial Loss	[5]													(7,068)	(9,446)
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)	423
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)	(2,564)
Purchased Gas [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Purchased Gas														386,265	337,822	$ 275,254
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)	$ 952
[1]	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.
[2]	Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[3]	Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated
[4]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated
[5]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note I — Retirement Plan and Other Post-Retirement Benefits for additional details.

Summary of Significant Accoun_9

Summary of Significant Accounting Policies (Consolidated Statement of Cash Flows) (Details) - USD ($) $ in Thousands	Sep. 30, 2019		Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2016
Cash and Cash Equivalents [Line Items]
Cash and Temporary Cash Investments	$ 20,428		$ 229,606		$ 555,530	$ 129,972
Hedging Collateral Deposits	6,832	[1]	3,441	[1]	1,741	1,484
Cash, Cash Equivalents and Restricted Cash	$ 27,260		$ 233,047		$ 557,271	$ 131,456
[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_10

Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) - USD ($) $ in Thousands		Sep. 30, 2019	Sep. 30, 2018
Summary Of Significant Accounting Policies [Line Items]
Prepayments		$ 12,728	$ 11,126
Prepaid Property and Other Taxes		14,361	14,088
Fair Values of Firm Commitments		7,538	1,739
Regulatory Assets	[1]	11,460	9,792
Other Current Assets		97,054	68,024
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		42,388	22,457
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		$ 8,579	$ 8,822
[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_11

Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liabilities	$ 54,349	$ 60,819
Reserve for Gas Replacement	(36,632)	(37,813)
Liability for Royalty and Working Interests	18,057	12,062
Other Accruals and Current Liabilities	139,600	132,693
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	33,713	38,354
Regulatory Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liabilities	50,332	57,425
Other Accruals [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	24,304	13,316
Non-Qualified [Member]
Summary Of Significant Accounting Policies [Line Items]
Non-Qualified Benefit Plan Liability	99,500	86,100	$ 88,900
Non-Qualified [Member] | Current [Member]
Summary Of Significant Accounting Policies [Line Items]
Non-Qualified Benefit Plan Liability	$ 13,194	$ 11,536	$ 14,100

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Narrative) (Details) $ in Millions	Sep. 30, 2019USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Future Revenue Amounts Related to Remaining Performance Obligations	$ 162
Remaining Performance Obligation, Expected Timing of Satisfaction	1 year
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	$ 138.4
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	$ 115.1
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	$ 82.3
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	$ 72.9
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	$ 297.6
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, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue	$ 293,341	$ 357,200	$ 552,544	$ 490,247	$ 289,196	$ 342,912	$ 540,905	$ 419,655	$ 1,693,332	$ 1,592,668	$ 1,579,881
Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									635,012
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									(2,272)
Revenue									632,740
Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									288,283
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0
Revenue									288,283
Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									127,075
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0
Revenue									127,075
Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									728,746
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									(1,304)
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0
Revenue									727,442
Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,779,116
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									(1,304)
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									(2,272)
Revenue									1,775,540
All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									147,051
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									2,658
Revenue									149,709
Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(231,917)
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									0
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									0
Revenue									(231,917)
Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,694,250
Alternative Revenue Programs Outside Scope of Authoritative Guidance on Revenue Recognition									(1,304)
Derivative Financial Instruments Outside Scope of Authoritative Guidance on Revenue Recognition									386
Revenue									1,693,332
Production of Natural Gas [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									481,048
Production of Natural Gas [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Natural Gas [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Natural Gas [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Natural Gas [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									481,048
Production of Natural Gas [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Natural Gas [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Natural Gas [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									481,048
Production of Crude Oil [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									149,078
Production of Crude Oil [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Crude Oil [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Crude Oil [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Crude Oil [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									149,078
Production of Crude Oil [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Crude Oil [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Production of Crude Oil [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									149,078
Natural Gas Processing [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,277
Natural Gas Processing [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Processing [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Processing [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Processing [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,277
Natural Gas Processing [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Processing [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Processing [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,277
Natural Gas Gathering Service [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Gathering Service [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Gathering Service [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									127,064
Natural Gas Gathering Service [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Gathering Service [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									127,064
Natural Gas Gathering Service [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Gathering Service [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(127,064)
Natural Gas Gathering Service [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Transportation Service [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Transportation Service [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									209,184
Natural Gas Transportation Service [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Transportation Service [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									119,253
Natural Gas Transportation Service [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									328,437
Natural Gas Transportation Service [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Transportation Service [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(70,689)
Natural Gas Transportation Service [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									257,748
Natural Gas Storage Service [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Storage Service [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									75,484
Natural Gas Storage Service [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Storage Service [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Storage Service [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									75,484
Natural Gas Storage Service [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Storage Service [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(32,488)
Natural Gas Storage Service [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									42,996
Natural Gas Residential Sales [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Residential Sales [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Residential Sales [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Residential Sales [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									539,962
Natural Gas Residential Sales [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									539,962
Natural Gas Residential Sales [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Residential Sales [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Residential Sales [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									539,962
Natural Gas Commercial Sales [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Commercial Sales [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Commercial Sales [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Commercial Sales [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									73,331
Natural Gas Commercial Sales [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									73,331
Natural Gas Commercial Sales [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Commercial Sales [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Commercial Sales [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									73,331
Natural Gas Industrial Sales [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Industrial Sales [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Industrial Sales [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Industrial Sales [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									4,830
Natural Gas Industrial Sales [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									4,830
Natural Gas Industrial Sales [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Industrial Sales [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Industrial Sales [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									4,830
Natural Gas Marketing [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Marketing [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Marketing [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Marketing [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Marketing [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									0
Natural Gas Marketing [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									143,627
Natural Gas Marketing [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(1,127)
Natural Gas Marketing [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									142,500
Other [Member] | Exploration And Production [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									1,609
Other [Member] | Pipeline And Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,615
Other [Member] | Gathering [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									11
Other [Member] | Utility [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(8,630)
Other [Member] | Total Reportable Segments [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(3,395)
Other [Member] | All Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									3,424
Other [Member] | Corporate And Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									(549)
Other [Member] | Total Consolidated [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contracts with Customers									$ (520)

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule Of Change In Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at Beginning of Year	$ 108,235	$ 106,395	$ 112,330
Liabilities Incurred	4,122	5,597	2,963
Revisions of Estimates	16,693	(419)	(10,578)
Liabilities Settled	(7,670)	(12,858)	(4,967)
Accretion Expense	6,078	9,520	6,647
Balance at End of Year	$ 127,458	$ 108,235	$ 106,395

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2019USD ($)
Regulatory Matters [Line Items]
Approved Return on Equity	8.70%
Supply Corporation [Member]
Regulatory Matters [Line Items]
Proposed Annual Cost of Service	$ 295.4
Proposed Rate Base	$ 970.8
Proposed Return on Equity	15.00%

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2019	Sep. 30, 2018
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	$ 307,982	$ 254,145
Less: Amounts Included in Other Current Assets	[1]	(11,460)	(9,792)
Total Long-Term Regulatory Assets		167,320	112,918
Total Regulatory Liabilities		784,918	790,501
Less: Amounts Included in Current and Accrued Liabilities		(54,349)	(60,819)
Total Long-Term Regulatory Liabilities		142,367	146,743
Cost Of Removal Regulatory Liability [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		221,699	212,311
Taxes Refundable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		366,503	370,628
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[2]	126,577	134,387
Amounts Payable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		4,017	3,394
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[3]	66,122	69,781
Total Long-Term Regulatory Liabilities		15,790	12,356
Non-Current Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Liabilities		730,569	729,682
Other Accruals and Current Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Current and Accrued Liabilities		(50,332)	(57,425)
Pension Costs Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	114,509	62,703
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	18,236	11,160
Recoverable Future Taxes [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	115,197	115,460
Environmental Site Remediation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	15,317	20,308
Asset Retirement Obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	15,696	15,495
Unamortized Debt Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	14,005	15,975
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[5]	15,022	13,044
Total Long-Term Regulatory Assets		3,562	3,252
Long-Term Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Assets	[1]	296,522	244,353
Other Current Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Other Current Assets		$ (11,460)	$ (9,792)
[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]	$50,332 and $57,425 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $15,790 and $12,356 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively.
[4]	Included in Other Regulatory Assets on the Consolidated Balance Sheets.
[5]	$11,460 and $9,792 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,562 and $3,252 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2019 and 2018, respectively.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended				9 Months Ended	12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Taxes [Line Items]
Federal Statutory Rate					21.00%	21.00%	24.50%	35.00%
Reduction to Income Tax Expense Due to Remeasurement of Deferred Income Tax Assets and Liabilites	$ (5,000)	$ 3,500	$ 4,000	$ (111,000)		$ (5,000)	$ (103,500)
Reduction In Deferred Taxes for Rate Regulated Activities Due to Remeasurement of Deferred Income Tax Assets and Liabilities							336,700
Decrease To Recoverable Future Taxes Impact of Change In Corporate Tax Rate							65,700
Increase in Taxes Refundable To Customers Due to Changes In Corporate Tax Rate							271,000
Taxes Refundable to Customers		370,628			$ 370,628	366,503	370,628
Recoverable Future Taxes		115,460			115,460	115,197	115,460
Deferred Income Taxes [Member]
Income Taxes [Line Items]
Taxes Refundable to Customers		370,600			370,600	366,500	370,600
Recoverable Future Taxes		115,500			115,500	115,200	115,500
Federal [Member]
Income Taxes [Line Items]
Income Taxes Receivable		22,457			22,457	42,388	22,457
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Income Taxes Receivable		8,822			8,822	8,579	8,822
Alternative Minimum Tax Credit [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards		$ 85,000			$ 85,000		$ 85,000
Alternative Minimum Tax Credit [Member] | California [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards						7,711
Alternative Minimum Tax Credit [Member] | Federal [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards						42,546
Guidance for Stock Based Compensation [Member]
Income Taxes [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance								$ 31,900
Other Current Assets [Member] | Federal [Member]
Income Taxes [Line Items]
Income Taxes Receivable						$ 42,500

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, 2019	Sep. 30, 2018	Sep. 30, 2017
Current Income Taxes [Abstract]
Federal	$ (41,645)	$ 2,025	$ 32,034
State	4,601	8,634	10,673
Deferred Income Taxes [Abstract]
Federal	98,514	(38,927)	103,046
State	23,751	20,774	14,929
Income Tax Expense (Benefit)	85,221	(7,494)	160,682
Deferred Investment Tax Credit	(91)	(105)	(173)
Total Income Taxes	85,130	(7,599)	160,509
Presented as Follows [Abstract]
Other (Income) Deductions	(91)	(105)	(173)
Income Tax Expense (Benefit)	$ 85,221	$ (7,494)	$ 160,682

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate) (Details) - USD ($) $ in Thousands		9 Months Ended	12 Months Ended
		Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Taxes [Line Items]
U.S. Income Before Income Taxes			$ 389,420	$ 383,922	$ 443,991
Income Tax Expense, Computed at U.S. Federal Statutory Rate	[1]		81,778	94,061	155,397
State Income Taxes (Benefit)	[2]		22,397	22,203	16,641
Federal Tax Credits			(7,361)	(6,576)	(6,679)
Amortization of Excess Deferred Federal Income Taxes	[3]		(5,036)	(3,236)	0
Impact of 2017 Tax Reform Act	[4]		(5,000)	(112,598)	0
Miscellaneous			(1,648)	(1,453)	(4,850)
Total Income Taxes			$ 85,130	$ (7,599)	$ 160,509
Federal Statutory Rate		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 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. For fiscal 2017, the statutory rate of 35% was utilized.
[2]	The state income tax expense 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.
[3]	Represents amortization of excess deferred federal income taxes under the 2017 Tax Reform Act.
[4]	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, 2019	Sep. 30, 2018
Deferred Tax Liabilities [Abstract]
Property, Plant and Equipment	$ 861,278	$ 770,794
Pension and Other Post-Retirement Benefit Costs	55,795	39,541
Other	54,486	49,734
Total Deferred Tax Liabilities	971,559	860,069
Deferred Tax Assets [Abstract]
Tax Loss and Credit Carryforwards	(175,542)	(214,128)
Pension and Other Post-Retirement Benefit Costs	(87,280)	(62,969)
Other	(55,355)	(75,286)
Total Gross Deferred Tax Assets	(318,177)	(352,383)
Valuation Allowance	0	5,000
Total Deferred Tax Assets	(318,177)	(347,383)
Total Net Deferred Income Taxes	$ 653,382	$ 512,686

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Balance at Beginning of Year	$ 0	$ 1,251	$ 396
Additions for Tax Positions of Prior Years	0	0	1,251
Reductions for Tax Positions of Prior Years	0	(788)	(396)
Reductions Related to Settlements with Taxing Authorities	0	(463)	0
Balance at End of Year	$ 0	$ 0	$ 1,251

Income Taxes Income Taxes (Summ

Income Taxes Income Taxes (Summary of Operating Loss and Tax Credit Carryforwards) (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Sep. 30, 2018
Operating Loss Carryforwards [Line Items]
Charitable Contributions	$ 2,097
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss, subject to expiration	143,571
Net operating loss, not subject to expiration	54,789
Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards		$ 85,000
Alternative Minimum Tax Credit [Member] | Federal [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	42,546
Research and Development Tax Credit Carryforward [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	6,339
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	383,056
California [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	207,995
California [Member] | Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	7,711
California [Member] | Enhanced Oil Recovery Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	$ 8,504

Capitalization And Short-Term_3

Capitalization And Short-Term Borrowings (Narrative) (Details)	Aug. 17, 2018USD ($)	Sep. 30, 2019USD ($)$ / sharesshares	Sep. 30, 2019USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / 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
Common stock shares issued due to SARs exercises | shares			126,879
Shares tendered | shares			159,413
Share-Based Payment Expense			$ 19,500,000	$ 14,200,000	$ 10,800,000
Tax benefit related to stock-based compensation expense			3,800,000	3,400,000	4,400,000
Capitalized stock-based compensation costs			100,000	100,000	100,000
Tax benefit from stock-based compensation exercises and vestings			3,200,000
Unamortized Debt Expense		$ 14,005,000	14,005,000	15,975,000
Gain (Loss) on Extinguishment of Debt				1,000,000
Net proceeds from issuance of long-term debt			0	295,020,000	$ 295,151,000
Principal amounts of long-term debt maturing in 2020		0	0
Principal amounts of long-term debt maturing in 2021		0	0
Principal amounts of long-term debt maturing in 2022		500,000,000	500,000,000
Principal amounts of long-term debt maturing in 2023		549,000,000	549,000,000
Principal amounts of long-term debt maturing in 2024		0	0
Principal amounts of long-term debt maturing after 2024		1,100,000,000	1,100,000,000
Commercial paper, outstanding		$ 55,200,000	$ 55,200,000	0
Weighted average interest rate on commercial paper		2.50%	2.50%
Short-term notes payable outstanding		$ 0	$ 0	$ 0
Committed credit facility maximum debt to capitalization ratio			0.65
Ceiling Test Impairment Adjustment		50.00%	50.00%
Ceiling Test Impairment Maximum Adjustment		$ 250,000,000	$ 250,000,000
Debt to capitalization ratio			0.51
Additional borrowing		1,780,000,000	$ 1,780,000,000
Aggregated indebtedness			$ 40,000,000
Maximum debt increase under existing indenture covenants		$ 1,020,000,000
Preferred stock, shares authorized | shares		10,000,000	10,000,000
Preferred stock par value | $ / shares		$ 1	$ 1
Percentage of Long-Term Debt issued under 1974 Indenture			4.60%
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	$ 1,600,000
Number of Awards Vested | shares			0	0	5,000
Equity instruments other than options, vested in period, total fair value					$ 100,000
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	$ 100,000
Unrecognized compensation expense recognized weighted average period			1 year 1 month 6 days
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares			123,939	89,672	87,143
Weighted Average Fair Value per Award Granted | $ / shares			$ 49.40	$ 51.23	$ 52.13
Number of Awards Vested | shares			80,354
Unrecognized compensation expense		6,100,000	$ 6,100,000
Unrecognized compensation expense recognized weighted average period			2 years 3 months 18 days
Performance Shares [Member]
Debt Instrument [Line Items]
Common stock issued | shares			281,882
Number of Shares Granted | shares			244,734	208,588	184,148
Weighted Average Fair Value per Award Granted | $ / shares			$ 55.67	$ 50.95	$ 56.39
Number of Awards Vested | shares			281,882
Unrecognized compensation expense		8,700,000	$ 8,700,000
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			80,354
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued | shares			28,771
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
Indenture From 1974 [Member]
Debt Instrument [Line Items]
Carrying Amount		99,000,000	$ 99,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper available		500,000,000	500,000,000
Fourth Amended & Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 750,000,000	$ 750,000,000
2020 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			87,835
2020 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			173,454
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			76,146
2021 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			170,526
2022 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			67,525
2022 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			178,534
2023 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			33,831
2024 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			16,270

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, 2019		Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018	Mar. 31, 2018	[3]	Dec. 31, 2017		Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Schedule of Capitalization [Line Items]
Beginning balance (shares)						85,956,814									85,956,814
Beginning balance						$ 820,223									$ 820,223
Balance at Beginning of Year						1,098,900							$ 851,669		1,098,900		$ 851,669	$ 676,361
Beginning balance						(67,750)							(30,123)		(67,750)		(30,123)
Net Income Available for Common Stock		$ 47,282		$ 63,753	$ 90,595	$ 102,660	[1]	$ 37,995	[2]	$ 63,025	$ 91,847		$ 198,654	[4]	304,290		391,521	283,482
Dividends Declared on Common Stock															(148,432)		(144,290)	(140,090)
Other Comprehensive Income (Loss), Net of Tax															15,595		(37,627)	(24,483)
Share-Based Payment Expense															$ 19,500		$ 14,200	10,800
Ending balance (Shares)		86,315,287						85,956,814							86,315,287		85,956,814
Ending balance		$ 832,264						$ 820,223							$ 832,264		$ 820,223
Balance at End of Year		1,272,601						1,098,900							1,272,601		1,098,900	851,669
Ending balance		(52,155)						$ (67,750)							$ (52,155)		$ (67,750)	$ (30,123)
Dividend per share															$ 1.72		$ 1.68	$ 1.64
Accumulated earnings free from limitations		$ 1,100,000													$ 1,100,000
Common Stock [Member]
Schedule of Capitalization [Line Items]
Beginning balance (shares)						85,957,000							85,543,000		85,957,000		85,543,000	85,119,000
Beginning balance (value)						$ 85,957							$ 85,543		$ 85,957		$ 85,543	$ 85,119
Common Stock Issued Under Stock and Benefit Plans (Shares)															358,000		414,000	424,000
Common Stock Issued Under Stock and Benefit Plans (Value)															$ 358		$ 414	$ 424
Ending balance (Shares)		86,315,000						85,957,000							86,315,000		85,957,000	85,543,000
Ending balance (Value)		$ 86,315						$ 85,957							$ 86,315		$ 85,957	$ 85,543
Paid In Capital [Member]
Schedule of Capitalization [Line Items]
Beginning balance						820,223							796,646		820,223		796,646	771,164
Share-Based Payment Expense	[5]														19,613		14,235	10,902
Common Stock Issued Under Stock and Benefit Plans (Value)																	9,342	14,580
Stock Repurchased During Period, Value															(7,572)
Ending balance		832,264						820,223							832,264		820,223	796,646
Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year						1,098,900							851,669		1,098,900		851,669	676,361
Net Income Available for Common Stock															304,290		391,521	283,482
Dividends Declared on Common Stock															(148,432)		(144,290)	(140,090)
Balance at End of Year		1,272,601	[6]					1,098,900							1,272,601	[6]	1,098,900	851,669
Accumulated Other Comprehensive Income (Loss) [Member]
Schedule of Capitalization [Line Items]
Beginning balance						$ (67,750)							$ (30,123)		(67,750)		(30,123)	(5,640)
Other Comprehensive Income (Loss), Net of Tax															15,595		(37,627)	(24,483)
Ending balance		(52,155)						$ (67,750)							(52,155)		$ (67,750)	(30,123)
Guidance for Stock Based Compensation [Member]
Schedule of Capitalization [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance																		31,900
Guidance for Stock Based Compensation [Member] | Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance																		$ 31,916
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member]
Schedule of Capitalization [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance		7,400													7,400
Guidance for Recognition and Measurement of Financial Assets and Liabilities [Member] | Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance		7,437													7,437
Guidance for Reclassification of Stranded Tax Effects [Member]
Schedule of Capitalization [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance		10,400													10,400
Guidance for Reclassification of Stranded Tax Effects [Member] | Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance		$ 10,406													$ 10,406
[1]	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.
[2]	Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[3]	Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated
[4]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated
[5]	Paid in Capital includes compensation costs associated with SARs, 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, 2019, $1.1 billion 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, 2019	Sep. 30, 2018	Sep. 30, 2017
Schedule of Capitalization [Line Items]
Number of Shares available for future grant	[1]	1,225,831
Performance Shares [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		641,290
Number of Shares Granted		244,734	208,588	184,148
Number of Awards Vested		(281,882)
Number of Shares Forfeited		(109,806)
Change in Units Based on Performance Achieved		(28,178)
Number of Shares Outstanding, End of Year		522,514	641,290
Weighted Average Fair Value per Award, Beginning of Year		$ 44.49
Weighted Average Fair Value per Award Granted		55.67	$ 50.95	$ 56.39
Weighted Average Fair Value per Award Vested		31.16
Weighted Average Fair Value per Award Forfeited		54.19
Weighted Average Fair Value per Award, Change in Units Based on Performance Achieved		35.14
Weighted Average Fair Value per Award, End of Year		$ 54.37	$ 44.49
Stock Appreciation Rights (SARs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		1,299,088
Number of Shares Granted		0	0	0
Number of Shares Exercised		(528,456)
Number of Awards Vested		0	0	(5,000)
Number of Shares Forfeited		0
Number of Shares Expired		(37,500)
Number of Shares Outstanding, End of Year		733,132	1,299,088
Number of SARs exercisable		733,132
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 50.70
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		43.94
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Expired		63.87
Weighted Average Exercise Price, Outstanding End of Year		54.90	$ 50.70
Weighted Average Exercise Price, SARs exercisable		$ 54.90
Weighted Average Remaining Contractual Life, Outstanding		1 year 8 months 23 days
Weighted Average Remaining Contractual Life, SARs exercisable		1 year 8 months 23 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, 2019	Sep. 30, 2018	Sep. 30, 2017
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	245,316
Number of Shares Granted	123,939	89,672	87,143
Number of Awards Vested	(80,354)
Number of Shares Forfeited	(7,294)
Number of Shares Outstanding, End of Year	281,607	245,316
Weighted Average Fair Value per Award, Beginning of Year	$ 48.45
Weighted Average Fair Value per Award Granted	49.40	$ 51.23	$ 52.13
Weighted Average Fair Value per Award Vested	48.24
Weighted Average Fair Value per Award Forfeited	50.40
Weighted Average Fair Value per Award, End of Year	$ 48.88	$ 48.45

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, 2019	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk Free Interest Rate	2.61%	1.96%	1.54%
Remaining Term at Date of Grant (Years)	2 years 9 months 10 days	2 years 9 months 10 days	2 years 9 months 14 days
Expected Volatility Rate	20.20%	22.00%	22.60%

Capitalization And Short-Term_8

Capitalization And Short-Term Borrowings (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Aug. 17, 2018	Sep. 27, 2017
Debt Instrument [Line Items]
Total Long-Term Debt		$ 2,149,000	$ 2,149,000
Less Unamortized Discount and Debt Issuance Costs		15,282	17,635
Less Current Portion	[1]	0	0
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		$ 2,133,718	2,131,365
Maximum interest rate adjustment		2.00%
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%
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%
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 5.20% Due December 2021 To September 2028 [Member]
Debt Instrument [Line Items]
Notes	[2],[3],[4]	$ 2,050,000	$ 2,050,000
Percentage of principal amount		101.00%	101.00%
Minimum [Member] | 3.75% To 5.20% 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 5.20% Due December 2021 To September 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate		5.20%	5.20%
[1]	None of the Company's long-term debt at September 30, 2019 and 2018 will mature within the following twelve-month period.
[2]	The Medium-Term Notes and Notes are unsecured.
[3]	The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.
[4]	The interest rate payable on $300.0 million of 4.75% notes and $300.0 million of 3.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($)	Sep. 30, 2019		Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	$ 6,832,000	[1]	$ 3,441,000	[1]	$ 1,741,000	$ 1,484,000
Level 1 or Level 2 Transfers	0		0
Derivative Financial Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring 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 and Nonrecurring Basis [Line Items]
Hedging collateral deposits	6,832,000		3,441,000
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	6,800,000		3,400,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	$ 0		$ 0
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measures Of Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2019		Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 10,521		$ 215,272
Hedging Collateral Deposits		6,832	[1]	3,441	[1]	$ 1,741	$ 1,484
Total Assets	[1]	169,742		320,321
Total Liabilities	[1]	5,574		49,036
Total Net Assets/(Liabilities)	[1]	164,168		271,285
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0		0
Derivative Liability	[1]	5,094		1,337
Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	50,593		9,033
Derivative Liability	[1]	188		47,183
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(2,047)		0
Derivative Liability	[1]	292		516
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	40,660		38,468
Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	62,339		51,331
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	844		2,776
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		10,521		215,272
Hedging Collateral Deposits		6,832		3,441
Total Assets		123,251		312,363
Total Liabilities		7,149		2,412
Total Net Assets/(Liabilities)		116,102		309,951
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		1,075
Derivative Liability		7,149		2,412
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] | 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		40,660		38,468
Fair Value, Inputs, Level 1 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		62,339		51,331
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		844		2,776
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		0
Total Assets		52,081		26,517
Total Liabilities		4,015		65,183
Total Net Assets/(Liabilities)		48,066		(38,666)
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		0
Derivative Liability		0		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		52,076		26,074
Derivative Liability		1,671		64,224
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		5		443
Derivative Liability		2,344		959
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		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		0
Derivative Liability		0		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] | 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		0
Total Assets	[1]	(5,590)		(18,559)
Total Liabilities	[1]	(5,590)		(18,559)
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)		(1,075)
Derivative Liability	[1]	(2,055)		(1,075)
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]	(1,483)		(17,041)
Derivative Liability	[1]	(1,483)		(17,041)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(2,052)		(443)
Derivative Liability	[1]	(2,052)		(443)
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, 2019USD ($)counterpartyMMcfbbl		Sep. 30, 2018USD ($)	[1]	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Foreign Currency Forward Contract Hedge Duration	7 years
Net hedging gains (losses) in accumulated other comprehensive income (loss)	$ 47,400,000
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)	34,700,000
Pre-tax Net hedging gains (losses) reclassified within twelve months	39,100,000
After tax Net hedging gains (losses) reclassified within twelve months	28,600,000
Fair market value of derivative asset with a credit-risk related contingency	36,600,000
Fair market value of derivative liability with a credit-risk related contingency	400,000
Hedging collateral deposits	6,832,000	[1]	$ 3,441,000		$ 1,741,000	$ 1,484,000
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount	$ 81,600,000
Cash Flow and Fair Value Commodity Hedges [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedge Duration	5 years
Fair Value Hedges Mmcf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf	25,600
Exchange-Traded Futures Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedging collateral deposits	$ 6,800,000
Fixed Price Sales Commitments MMCf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf	25,200
Fixed Price Commitments Related To Withdrawal Of Storage Gas MMCf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf	400
Over the Counter Swaps 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	18
Number of counterparties in net gain position | counterparty	16
Credit risk exposure per counterparty	$ 3,000,000
Maximum credit risk exposure per counterparty	7,000,000
Collateral Received from Counterparties by the Company	0
Hedging collateral deposits	$ 0
Over the Counter Swaps 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 Short Position [Member] | Natural Gas MMCf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas | MMcf	105,200
Cash Flow Hedges Short Position [Member] | Crude Oil Bbls [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivative, crude oil | bbl	2,772,000
Cash Flow Hedges Long Position [Member] | Natural Gas MMCf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas | MMcf	2,700
[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, 2019	Sep. 30, 2018
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,133,718	$ 2,131,365
Fair Value	$ 2,257,085	$ 2,121,861

Financial Instruments (Other In

Financial Instruments (Other Investments) (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Sep. 30, 2018
Investment Holdings [Line Items]
Life Insurance Contracts	$ 41,074	$ 39,970
Other Investments	144,917	132,545
Equity Mutual Fund [Member]
Investment Holdings [Line Items]
Fair Value	40,660	38,468
Fixed Income Mutual Fund [Member]
Investment Holdings [Line Items]
Fair Value	62,339	51,331
Marketable Equity Securities [Member]
Investment Holdings [Line Items]
Fair Value	$ 844	$ 2,776

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, 2019	Sep. 30, 2018	Sep. 30, 2017
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) (Effective Portion)	$ 79,301	$ (74,103)	$ 5,347
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(5,464)	(1,189)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	2,096	(782)
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) (Effective Portion)	(2,646)	(3,899)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(822)	(2,564)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0	0
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) (Effective Portion)	82,984	(70,905)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(3,460)	423
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	2,096	(782)
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) (Effective Portion)	(1,037)	701
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(1,182)	952
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$ 0	$ 0

Financial Instruments (Schedu_2

Financial Instruments (Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2019USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	$ 1,941
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	(1,941)
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	2,606
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	(2,606)
Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(665)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	$ 665

Retirement Plan And Other Pos_3

Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Decrease to accumulated other comprehensive income	$ (36,270,000)	$ 57,283,000	$ 44,731,000
Effect of one percentage point increase on accumulated postretirement benefit obligation	60,800,000
Effect of one percentage point increase on service and interest cost components	2,700,000
Effect of one percentage point decrease on accumulated postretirement benefit obligation	49,100,000
Effect of one percentage point decrease on service and interest cost components	2,100,000
Benefit assets transferred	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	7,600,000	6,800,000	7,600,000
Accumulated benefit obligation	79,800,000	70,600,000	72,500,000
Benefit obligation	$ 99,500,000	$ 86,100,000	$ 88,900,000
Discount rate	2.77%	4.02%	3.22%
Rate of compensation increase	8.00%	7.75%	7.75%
Tax-Deferred Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	$ 6,400,000	$ 6,200,000	$ 5,900,000
Retirement Savings Account [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	3,900,000	3,500,000	2,900,000
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]
Increase in other regulatory assets	82,700,000
Decrease to accumulated other comprehensive income	36,800,000
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	19,907,000	28,382,000	34,848,000
Accumulated benefit obligation	1,053,914,000	946,763,000	1,010,179,000
Benefit obligation	$ 1,097,625,000	$ 985,690,000	$ 1,054,826,000	$ 1,097,421,000
Discount rate	3.15%	4.30%	3.77%
Rate of compensation increase	4.70%	4.70%	4.70%
Employer Contributions	$ 29,215,000	$ 32,980,000	$ 17,146,000
Expected future benefit payments in year one	66,300,000
Expected future benefit payments in year two	66,800,000
Expected future benefit payments in year three	67,100,000
Expected future benefit payments in year four	67,100,000
Expected future benefit payments in year five	67,100,000
Expected future benefit payments in five years thereafter	$ 328,700,000
Expected long term rate of return on plan assets	6.75%	7.00%	7.00%
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 10,521,000	$ 10,306,000	$ 14,092,000
Benefit obligation	$ 468,163,000	$ 435,986,000	$ 462,619,000	$ 526,138,000
Discount rate	3.17%	4.31%	3.81%
Rate of compensation increase	4.70%	4.70%	4.70%
Employer Contributions	$ 3,064,000	$ 2,896,000	$ 3,853,000
Expected future benefit payments in year one	27,998,000
Expected future benefit payments in year two	28,711,000
Expected future benefit payments in year three	29,142,000
Expected future benefit payments in year four	29,478,000
Expected future benefit payments in year five	29,631,000
Expected future benefit payments in five years thereafter	$ 147,138,000
Expected long term rate of return on plan assets	6.00%	6.25%	6.50%
VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	$ 2,800,000
Other Actuarial Experience [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	4,700,000
Other Actuarial Experience [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(18,900,000)	$ 7,300,000	$ (50,300,000)
Mortality Improvement Projection Scale [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(5,300,000)
Mortality Improvement Projection Scale [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(3,900,000)	(2,400,000)	(5,700,000)
Discount Rate Change [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	128,400,000	(58,100,000)	(20,500,000)
Discount Rate Change [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ 57,200,000	(25,800,000)	(6,200,000)
Effective Fiscal 2020 [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	6.40%
Effective Fiscal 2020 [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	5.70%
Minimum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 25,000,000
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	$ 30,000,000
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	$ 13,194,000	11,536,000	14,100,000
Non-Current [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 86,300,000	$ 74,600,000	$ 74,800,000

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, 2019	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Non-Current Assets		$ 60,517	$ 82,733
Amortization period		10 years
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 985,690	1,054,826	$ 1,097,421
Service Cost		8,482	9,921	11,969
Interest Cost		38,378	33,006	38,383
Plan Participants' Contributions		0	0	0
Retiree Drug Subsidy Receipts		0	0	0
Actuarial (Gain) Loss		127,748	(50,218)	(32,466)
Benefits Paid		(62,673)	(61,845)	(60,481)
Benefit Obligation at End of Period		1,097,625	985,690	1,054,826
Fair Value of Assets at Beginning of Period		924,506	910,719	869,775
Actual Return on Plan Assets		77,401	42,652	84,279
Employer Contributions		29,215	32,980	17,146
Plan Participants' Contributions		0	0	0
Benefits Paid		(62,673)	(61,845)	(60,481)
Fair Value of Assets at End of Period		968,449	924,506	910,719
Net Amount Recognized at End of Period (Funded Status)		(129,176)	(61,184)	(144,107)
Non-Current Liabilities		(129,176)	(61,184)	(144,107)
Non-Current Assets		0	0	0
Accumulated Benefit Obligation		$ 1,053,914	$ 946,763	$ 1,010,179
Discount Rate		3.15%	4.30%	3.77%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Expected Return on Plan Assets		$ (62,368)	$ (61,715)	$ (59,718)
Amortization of Prior Service Cost (Credit)		826	938	1,058
Recognition of Actuarial Loss	[1]	32,096	37,205	42,687
Net Amortization and Deferral for Regulatory Purposes		2,493	9,027	469
Net Periodic Benefit Cost		$ 19,907	$ 28,382	$ 34,848
Effective Discount Rate for Benefit Obligations		4.30%	3.77%	3.60%
Effective Rate for Interest on Benefit Obligations		4.03%	3.23%	3.60%
Effective Discount Rate for Service Cost		4.40%	4.00%	3.60%
Effective Rate for Interest on Service Cost		4.29%	3.73%	3.60%
Expected Return on Plan Assets		6.75%	7.00%	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		$ 435,986	$ 462,619	$ 526,138
Service Cost		1,519	1,830	2,449
Interest Cost		17,145	14,801	19,007
Plan Participants' Contributions		2,930	2,894	2,717
Retiree Drug Subsidy Receipts		1,855	1,545	1,553
Actuarial (Gain) Loss		34,401	(21,039)	(62,215)
Benefits Paid		(25,673)	(26,664)	(27,030)
Benefit Obligation at End of Period		468,163	435,986	462,619
Fair Value of Assets at Beginning of Period		513,800	514,017	494,320
Actual Return on Plan Assets		30,006	20,657	40,157
Employer Contributions		3,064	2,896	3,853
Plan Participants' Contributions		2,930	2,894	2,717
Benefits Paid		(25,673)	(26,664)	(27,030)
Fair Value of Assets at End of Period		524,127	513,800	514,017
Net Amount Recognized at End of Period (Funded Status)		55,964	77,814	51,398
Non-Current Liabilities		(4,553)	(4,919)	(4,972)
Non-Current Assets		$ 60,517	$ 82,733	$ 56,370
Discount Rate		3.17%	4.31%	3.81%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Expected Return on Plan Assets		$ (30,157)	$ (31,482)	$ (31,458)
Amortization of Prior Service Cost (Credit)		(429)	(429)	(429)
Recognition of Actuarial Loss	[1]	5,962	10,558	18,415
Net Amortization and Deferral for Regulatory Purposes		16,481	15,028	6,108
Net Periodic Benefit Cost		$ 10,521	$ 10,306	$ 14,092
Effective Discount Rate for Benefit Obligations		4.31%	3.81%	3.70%
Effective Rate for Interest on Benefit Obligations		4.05%	3.29%	3.70%
Effective Discount Rate for Service Cost		4.43%	4.10%	3.70%
Effective Rate for Interest on Service Cost		4.39%	3.98%	3.70%
Expected Return on Plan Assets		6.00%	6.25%	6.50%
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, 2019USD ($)	[1]
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	$ (33,477)
Prior Service (Cost) Credit	0
Net Amount Recognized	(33,477)
Increase in Actuarial Loss, excluding amortization	(14,217)	[2]
Change due to Amortization of Actuarial Loss	3,558
Prior Service (Cost) Credit	0
Net Change	(10,659)
Net Actuarial Loss	(5,341)
Prior Service (Cost) Credit	0
Net Amount Expected to be Recognized	(5,341)
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(216,146)
Prior Service (Cost) Credit	(4,370)
Net Amount Recognized	(220,516)
Increase in Actuarial Loss, excluding amortization	(112,715)	[2]
Change due to Amortization of Actuarial Loss	32,096
Prior Service (Cost) Credit	826
Net Change	(79,793)
Net Actuarial Loss	(39,384)
Prior Service (Cost) Credit	(729)
Net Amount Expected to be Recognized	(40,113)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(27,398)
Prior Service (Cost) Credit	2,829
Net Amount Recognized	(24,569)
Increase in Actuarial Loss, excluding amortization	(34,553)	[2]
Change due to Amortization of Actuarial Loss	5,962
Prior Service (Cost) Credit	(429)
Net Change	(29,020)
Net Actuarial Loss	(535)
Prior Service (Cost) Credit	429
Net Amount Expected to be Recognized	$ (106)
[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, 2019USD ($)
Defined Benefit Plan Disclosure [Line Items]
2020 - Benefit Payments	$ 27,998
2020 - Subsidy Receipts	(1,901)
2021 - Benefit Payments	28,711
2021 - Subsidy Receipts	(2,025)
2022 - Benefit Payments	29,142
2022 - Subsidy Receipts	(2,147)
2023 - Benefit Payments	29,478
2023 - Subsidy Receipts	(2,264)
2024 - Benefit Payments	29,631
2024 - Subsidy Receipts	(2,372)
2025 through 2029 - Benefit Payments	147,138
2025 through 2029 - Subsidy Receipts	$ (12,960)

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, 2019	Sep. 30, 2018	Sep. 30, 2017
Retirement Benefits [Abstract]
Rate of Medical Cost Increase for Pre Age 65 Participants	[1]	5.50%	5.59%	5.67%
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]	7.35%	7.89%	8.45%
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]	6.84%	7.18%	7.33%
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, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ 968,449	$ 924,506	$ 910,719	$ 869,775
Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	175,812	223,300
Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	81,631	100,832
Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	70,095	85,942
Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	493,839	434,392
Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	17,744	416
Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	75,329	72,382
Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		107,764	53,878
Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		18,310	26,191
Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		1,040,524	997,333
Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(73,688)	(67,817)
Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		966,836	929,516
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		524,127	513,800	$ 514,017	$ 494,320
Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		8,229	7,894
Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		73,688	67,817
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		167,966
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			125,295
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			47,245
Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		275,296	265,667
Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		451,491	446,101
Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		525,179	513,918
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	114,324	139,885
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]	1,784	1,640
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	416
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		116,108	141,941
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(8,205)	(9,695)
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		107,903	132,246
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		8,205	9,695
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
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			0
Fair Value, Inputs, Level 1 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			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		275,296	265,667
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		275,296	265,667
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		283,501	275,362
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]	439,255	382,348
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	17,744	0
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		456,999	382,348
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(32,295)	(26,114)
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		424,704	356,234
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		32,295	26,114
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
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			0
Fair Value, Inputs, Level 2 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			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		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		32,295	26,114
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		3,154	3,194
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		3,154	3,194
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(223)	(218)
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		2,931	2,976
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		223	218
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
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			0
Fair Value, Inputs, Level 3 [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments			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		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		223	218
Measured at NAV [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1],[7]	61,488	83,415
Measured at NAV [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2],[7]	81,631	100,832
Measured at NAV [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3],[7]	70,095	85,942
Measured at NAV [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4],[7]	52,800	50,404
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]	75,329	72,382
Measured at NAV [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	104,610	50,684
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]	18,310	26,191
Measured at NAV [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	464,263	469,850
Measured at NAV [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	(32,965)	(31,790)
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	[7]	431,298	438,060
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]	8,229	7,894
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]	32,965	31,790
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	[7]	167,966
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]		125,295
Measured at NAV [Member] | Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]		47,245
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	[7]	176,195	180,434
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	[7]	209,160	212,224
Miscellaneous Accruals, Interest Receivables, And Non-Interest Cash [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		1,613	(5,010)
Miscellaneous Accruals Including Current and Deferred Taxes Claims Incurred But Not Reported Administrative [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ (1,052)	$ (118)
[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, 2019	Sep. 30, 2018
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	$ 2,976	$ 3,166
Unrealized Gains/(Losses)	(42)	169
Sales	(3)	(359)
Balance, End of Year	2,931	2,976
Real Estate [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	3,194	3,391
Unrealized Gains/(Losses)	(37)	188
Sales	(3)	(385)
Balance, End of Year	3,154	3,194
Excluding 401(h) Investments [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	(218)	(225)
Unrealized Gains/(Losses)	(5)	(19)
Sales	0	26
Balance, End of Year	(223)	(218)
401(h) Investments [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	218	225
Unrealized Gains/(Losses)	5	19
Sales	0	(26)
Balance, End of Year	$ 223	$ 218

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2019USD ($)
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 7
Future purchase obligation first year	256.4
Future purchase obligation second year	78.5
Future purchase obligation third year	111.2
Future purchase obligation fourth year	110.8
Future purchase obligation fifth year	115.6
Future purchase obligation thereafter	1,098.8
Operating lease commitment first year	12.4
Operating lease commitment second year	2.8
Operating lease commitment third year	2.3
Operating lease commitment fourth year	2.3
Operating lease commitment fifth year	2.2
Operating lease commitment thereafter	9.7
Former Manufactured Gas Plant Site New York [Member]
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 3.8
Environmental Site Remediation Costs [Member]
Site Contingency [Line Items]
Rate recovery period	3 years
Pipeline And Storage, Gathering And Utility Segments [Member]
Site Contingency [Line Items]
Contract commitments first year	$ 97.5
Contract commitments second year	34.9
Contract commitments third year	6
Contract commitments fourth year	3.3
Contract commitments fifth year	3.3
Contract commitments thereafter	11.6
Exploration And Production [Member]
Site Contingency [Line Items]
Contract commitments first year	104.3
Contract commitments second year	22.2
Contract commitments third year	$ 1.7

Business Segment Information (N

Business Segment Information (Narrative) (Details)	12 Months Ended
	Sep. 30, 2019segment
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, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Revenue		$ 293,341	$ 357,200	$ 552,544	$ 490,247		$ 289,196		$ 342,912	$ 540,905		$ 419,655		$ 1,693,332	$ 1,592,668	$ 1,579,881
Interest Income														6,065	6,766	4,113
Interest Expense														106,756	114,522	119,837
Depreciation, Depletion and Amortization														275,660	240,961	224,195
Income Tax Expense (Benefit)														85,221	(7,494)	160,682
Segment Profit: Net Income (Loss)		47,282	$ 63,753	$ 90,595	$ 102,660	[1]	37,995	[2]	$ 63,025	$ 91,847	[3]	$ 198,654	[4]	304,290	391,521	283,482
Expenditures for Additions to Long-Lived Assets														781,246	600,602	462,117
Segment Assets		6,462,157					6,036,486							6,462,157	6,036,486	6,103,320
Utility [Member]
Segment Reporting Information [Line Items]
Revenue														727,442
Interest Income														1,809	1,591	1,051
Interest Expense														23,443	26,753	28,492
Depreciation, Depletion and Amortization														53,832	53,253	52,582
Income Tax Expense (Benefit)														13,967	15,258	24,894
Segment Profit: Net Income (Loss)														60,871	51,217	46,935
Expenditures for Additions to Long-Lived Assets														95,847	85,648	80,867
Segment Assets		1,991,338					1,921,971							1,991,338	1,921,971	2,013,123
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue														288,283
Interest Income														2,982	2,748	1,467
Interest Expense														29,142	31,383	33,717
Depreciation, Depletion and Amortization														44,947	43,463	41,196
Income Tax Expense (Benefit)														23,238	17,806	40,947
Segment Profit: Net Income (Loss)														74,011	97,246	68,446
Expenditures for Additions to Long-Lived Assets														143,005	92,832	95,336
Segment Assets		1,893,514					1,848,180							1,893,514	1,848,180	1,929,788
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue														632,740
Interest Income														1,107	1,479	707
Interest Expense														54,777	54,288	53,702
Depreciation, Depletion and Amortization														154,784	124,274	112,565
Income Tax Expense (Benefit)														32,978	(41,962)	66,093
Segment Profit: Net Income (Loss)														111,807	180,632	129,326
Expenditures for Additions to Long-Lived Assets														491,889	380,677	253,057
Segment Assets		1,972,776					1,568,563							1,972,776	1,568,563	1,407,152
Gathering [Member]
Segment Reporting Information [Line Items]
Revenue														127,075
Interest Income														546	1,106	994
Interest Expense														9,406	9,560	9,142
Depreciation, Depletion and Amortization														20,038	17,313	16,162
Income Tax Expense (Benefit)														20,895	(17,677)	29,694
Segment Profit: Net Income (Loss)														58,413	83,519	40,377
Expenditures for Additions to Long-Lived Assets														49,650	61,728	32,645
Segment Assets		547,995					533,608							547,995	533,608	580,051
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue														1,775,540
Interest Income														6,444	6,924	4,219
Interest Expense														116,768	121,984	125,053
Depreciation, Depletion and Amortization														273,601	238,303	222,505
Income Tax Expense (Benefit)														91,078	(26,575)	161,628
Segment Profit: Net Income (Loss)														305,102	412,614	285,084
Expenditures for Additions to Long-Lived Assets														780,391	620,885	461,905
Segment Assets		6,405,623					5,872,322							6,405,623	5,872,322	5,930,114
All Other [Member]
Segment Reporting Information [Line Items]
Revenue														149,709
Interest Income														1,291	1,073	784
Interest Expense														21	22	47
Depreciation, Depletion and Amortization														1,291	1,902	940
Income Tax Expense (Benefit)														(955)	2,125	644
Segment Profit: Net Income (Loss)														(1,811)	261	1,167
Expenditures for Additions to Long-Lived Assets														128	41	75
Segment Assets		122,241					129,080							122,241	129,080	137,798
Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue														(231,917)
Interest Income														(1,670)	(1,231)	(890)
Interest Expense														(10,033)	(7,484)	(5,263)
Depreciation, Depletion and Amortization														768	756	750
Income Tax Expense (Benefit)														(4,902)	16,956	(1,590)
Segment Profit: Net Income (Loss)														999	(21,354)	(2,769)
Expenditures for Additions to Long-Lived Assets														727	(20,324)	137
Segment Assets		$ (65,707)					$ 35,084							(65,707)	35,084	35,408
Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													1,693,332	1,592,668	1,579,881
Revenue from External Customers [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													715,813	674,726	626,899
Revenue from External Customers [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													195,808	210,345	206,615
Revenue from External Customers [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													632,740	564,547	614,599
Revenue from External Customers [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													11	41	115
Revenue from External Customers [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													1,544,372	1,449,659	1,448,228
Revenue from External Customers [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													148,582	142,349	130,759
Revenue from External Customers [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													378	660	894
Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue														0	0	0
Intersegment Revenues [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue														11,629	12,800	13,072
Intersegment Revenues [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue														92,475	89,981	87,810
Intersegment Revenues [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue														0	0	0
Intersegment Revenues [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue														127,064	107,856	107,566
Intersegment Revenues [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue														231,168	210,637	208,448
Intersegment Revenues [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue														1,127	826	794
Intersegment Revenues [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue														$ (232,295)	$ (211,463)	$ (209,242)
[1]	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.
[2]	Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[3]	Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated
[4]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated
[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, 2019	Sep. 30, 2018	Sep. 30, 2017
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-Lived Assets	$ 6,099,534	$ 5,491,895	$ 5,285,040

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, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Increase (Reduction) to Income Tax Expense Due to Remeasurement of Deferred Income Tax Assets and Liabilites				$ (5,000)		$ 3,500			$ 4,000		$ (111,000)		$ (5,000)	$ (103,500)
Operating Revenues	$ 293,341	$ 357,200	$ 552,544	490,247		289,196		$ 342,912	540,905		419,655		1,693,332	1,592,668	$ 1,579,881
Operating Income	83,940	112,827	153,359	161,683		84,662		114,003	171,589		149,469		511,809	519,723	593,778
Net Income Available for Common Stock	$ 47,282	$ 63,753	$ 90,595	$ 102,660	[1]	$ 37,995	[2]	$ 63,025	$ 91,847	[3]	$ 198,654	[4]	$ 304,290	$ 391,521	$ 283,482
Earnings per Common Share, Basic	$ 0.55	$ 0.74	$ 1.05	$ 1.19		$ 0.44		$ 0.73	$ 1.07		$ 2.32		$ 3.53	$ 4.56	$ 3.32
Earnings per Common Share, Diluted	$ 0.54	$ 0.73	$ 1.04	$ 1.18		$ 0.44		$ 0.73	$ 1.06		$ 2.30		$ 3.51	$ 4.53	$ 3.30
[1]	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.
[2]	Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[3]	Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated
[4]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated

Supplementary Information For_3

Supplementary Information For Oil And Gas Producing Activities (Narrative) (Details) $ in Millions, ft³ in Billions	12 Months Ended
	Sep. 30, 2019USD ($)ft³	Sep. 30, 2018USD ($)ft³	Sep. 30, 2017USD ($)ft³	Sep. 30, 2016	Sep. 30, 2015
Reserve Quantities [Line Items]
Amount spent for developing proved undeveloped reserves | $	$ 246	$ 182.3	$ 101.1
Proved Undeveloped Reserve (Volume)	1,018	757	612
Percentage of PUD reserves to the total proved reserves	33.00%	30.00%	28.00%
New PUD reserve additions	575	431
PUD Sales		57
PUD Upward Revisions	38	60
PUD conversions to developed reserves	297	284
Proved Undeveloped Reserves, Removed	55	5
PUD Well Locations Removed	6
Increase in Proved undeveloped (PUD) reserves	261	145
Investment made to convert proved undeveloped reserves to developed reserves | $	$ 246	$ 182
Conversion Of Undeveloped Proved Reserves To Developed Proved Reserves After Revisions	380
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year	39.00%	46.00%	27.00%	25.00%	33.00%
Well Locations Developed With Net PUD Reserves	56	53
Percent of Well Locations Developed With Net PUD Reserves	50.00%	62.00%
Upward Revisions to PUD Reserves Converted to Developed Reserves	83
Arbitrary discount rate	10.00%
West Coast Region [Member]
Reserve Quantities [Line Items]
New PUD reserve additions	2	5
PUD conversions to developed reserves	5	2
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	383	394	456
New PUD reserve additions	175	229
PUD conversions to developed reserves	186	264
Proved Undeveloped Reserves, Removed	13
PUD Well Locations Removed	2
Utica Shale [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	632	357	154
New PUD reserve additions	398	197
PUD conversions to developed reserves	106	18
Proved Undeveloped Reserves, Removed	42
PUD Well Locations Removed	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 | $	$ 251
Impact of JDA Sales [Member]
Reserve Quantities [Line Items]
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year		51.00%

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, 2019	Sep. 30, 2018
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved Properties	[1]	$ 5,623,623	$ 5,114,753
Unproved Properties		53,498	62,234
Capitalized Costs, Oil and Gas Producing Activities, Gross, Total		5,677,121	5,176,987
Less - Accumulated Depreciation, Depletion and Amortization		4,012,568	3,862,687
Capitalized Costs Oil And Gas Producing Activities Net		1,664,553	1,314,300
Asset retirement costs		$ 70,500	$ 44,300
[1]	Includes asset retirement costs of $70.5 million and $44.3 million at September 30, 2019 and 2018, 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, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	$ 0	$ 0	$ 0
Development Costs	17,819	481	43
Exploration Costs	0	0	32
Capitalized Interest	41	0	0
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	17,860	$ 481	$ 75
Capitalized Costs Of Unproved Properties Cumulative Balance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	24,265
Development Costs	21,483
Exploration Costs	7,606
Capitalized Interest	144
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	$ 53,498
Costs Incurred Prior To Fiscal 2017 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs				$ 24,265
Development Costs				3,140
Exploration Costs				7,574
Capitalized Interest				103
Capitalized Costs of Unproved Properties Excluded from Amortization, Total				$ 35,082

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, 2019	Sep. 30, 2018	Sep. 30, 2017
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved		$ 3,136	$ 1,544	$ 8,908
Unproved		3,679	4,286	262
Exploration Costs	[1]	2,060	29,365	40,975
Development Costs	[2]	468,498	332,496	200,639
Asset Retirement Costs		26,192
Asset Retirement Costs			(10,107)	(9,175)
Total Property Acquisition Costs		503,565	357,584	241,609
Capitalized interest included in exploration costs		0	0	300
Capitalized interest included in development costs		$ 200	$ 300	$ 200
[1]	Amounts for 2019, 2018 and 2017 include capitalized interest of zero , zero and $0.3 million , respectively.
[2]	Amounts for 2019, 2018 and 2017 include capitalized interest of $0.2 million , $0.3 million and $0.2 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, 2019	Sep. 30, 2018	Sep. 30, 2017
Reserve Quantities [Line Items]
Revenues from sales to affiliates		$ 0	$ 0	$ 0
Operating Revenues	[1]	630,126,000	558,896,000	526,492,000
Production/Lifting Costs		186,626,000	162,721,000	165,991,000
Franchise/Ad Valorem Taxes		17,673,000	14,355,000	15,372,000
Purchased Emission Allowance Expense		2,527,000	1,883,000	1,391,000
Accretion Expense		3,723,000	4,266,000	4,896,000
Depreciation, Depletion and Amortization ($0.71, $0.67 and $0.63 per Mcfe of production)		149,881,000	119,946,000	108,471,000
Income Tax Expense		64,652,000	72,723,000	86,657,000
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)		205,044,000	183,002,000	143,714,000
Depreciation, Depletion and Amortization, per Mcfe of Production		0.71	0.67	0.63
Transfers to Entity's Other Operations		2,532,000	2,134,000	2,357,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Gas (includes transfers to operations of $2,532, $2,134 and $2,357, respectively)	[2]	481,048,000	390,642,000	399,975,000
Oil, Condensate And Other Liquids [Member]
Reserve Quantities [Line Items]
Operating Revenues		$ 149,078,000	$ 168,254,000	$ 126,517,000
[1]	Exclusive of hedging gains and losses. See further discussion in Note H — 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, 2019MMcfMBblsft³	Sep. 30, 2018MMcfMBblsft³	Sep. 30, 2017MMcfMBblsft³	Sep. 30, 2016MMcfMBbls
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		1,018	757	612
Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		2,357,342	1,973,120	1,674,575
Extensions and Discoveries		686,549	521,694	386,657
Revisions of Previous Estimates		103,508	93,435	90,849
Production Volume		(197,880)	(162,906)	(157,088)
Sales of Minerals in Place			(68,001)	(21,873)
Proved Developed and Undeveloped Reserves		2,949,519	2,357,342	1,973,120
Proved Developed Reserves (Volume)		1,934,795	1,606,532	1,363,102	1,132,616
Proved Undeveloped Reserve (Volume)		1,014,724	750,810	610,018	541,959
Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		27,663	30,207	29,009
Extensions and Discoveries | MBbls		787	2,301	674
Revisions of Previous Estimates | MBbls		(1,254)	2,477	3,293
Production Volume		(2,323)	(2,535)	(2,740)
Sales of Minerals in Place | MBbls			(4,787)	(29)
Proved Developed and Undeveloped Reserves | MBbls		24,873	27,663	30,207
Proved Developed Reserves (Volume) | MBbls		24,259	26,703	29,799	28,771
Proved Undeveloped Reserve (Volume) | MBbls		614	960	408	238
West Coast Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		36,840	46,506	43,124
Extensions and Discoveries		0	0	8
Revisions of Previous Estimates		(1,233)	3,322	6,369
Production Volume		(1,974)	(2,407)	(2,995)
Sales of Minerals in Place			(10,581)	0
Proved Developed and Undeveloped Reserves		33,633	36,840	46,506
Proved Developed Reserves (Volume)		33,633	36,840	46,506	43,124
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		27,649	30,179	28,936
Extensions and Discoveries | MBbls		787	2,301	674
Revisions of Previous Estimates | MBbls		(1,256)	2,487	3,305
Production Volume		(2,320)	(2,531)	(2,736)
Sales of Minerals in Place | MBbls			(4,787)	0
Proved Developed and Undeveloped Reserves | MBbls		24,860	27,649	30,179
Proved Developed Reserves (Volume) | MBbls		24,246	26,689	29,771	28,698
Proved Undeveloped Reserve (Volume) | MBbls		614	960	408	238
Appalachian Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		2,320,502	1,926,614	1,631,451
Extensions and Discoveries	[1]	686,549	521,694	386,649
Revisions of Previous Estimates		104,741	90,113	84,480
Production Volume	[2]	(195,906)	(160,499)	(154,093)
Sales of Minerals in Place			(57,420)	(21,873)
Proved Developed and Undeveloped Reserves		2,915,886	2,320,502	1,926,614
Proved Developed Reserves (Volume)		1,901,162	1,569,692	1,316,596	1,089,492
Proved Undeveloped Reserve (Volume)		1,014,724	750,810	610,018	541,959
Appalachian Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		14	28	73
Extensions and Discoveries | MBbls		0	0	0
Revisions of Previous Estimates | MBbls		2	(10)	(12)
Production Volume		(3)	(4)	(4)
Sales of Minerals in Place | MBbls			0	(29)
Proved Developed and Undeveloped Reserves | MBbls		13	14	28
Proved Developed Reserves (Volume) | MBbls		13	14	28	73
Proved Undeveloped Reserve (Volume) | MBbls		0	0	0	0
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		383	394	456
Marcellus Shale Fields [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		175,000	274,000	181,000
Production Volume		(163,015)	(150,196)	(145,452)
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		632	357	154
Utica Shale [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		512,000	248,000	205,000
Production Volume		(32,095)	(9,409)
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15.00%
[1]	Extensions and discoveries include 181 Bcf (during 2017), 274 Bcf (during 2018) and 175 Bcf (during 2019), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 205 Bcf (during 2017), 248 Bcf (during 2018) and 512 Bcf (during 2019), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.
[2]	Production includes 145,452 MMcf (during 2017), 150,196 MMcf (during 2018) and 163,015 MMcf (during 2019), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018) and 32,095 MMcf (during 2019), 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, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Future Cash Inflows	$ 8,738,182	$ 7,822,855	$ 6,144,317
Future Production Costs	2,989,518	2,606,411	2,378,262
Future Development Costs	797,640	559,707	411,578
Future Income Tax Expense at Applicable Statutory Rate	1,159,882	1,125,910	1,160,469
Future Net Cash Flows	3,791,142	3,530,827	2,194,008
10% Annual Discount for Estimated Timing of Cash Flows	2,054,823	1,810,522	1,080,962
Standardized Measure of Discounted Future Net Cash Flows	$ 1,736,319	$ 1,720,305	$ 1,113,046	$ 642,528

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, 2019	Sep. 30, 2018	Sep. 30, 2017
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$ 1,720,305	$ 1,113,046	$ 642,528
Sales, Net of Production Costs	(425,773)	(381,775)	(345,075)
Net Changes in Prices, Net of Production Costs	(164,428)	541,021	828,187
Extensions and Discoveries	202,683	212,494	170,500
Changes in Estimated Future Development Costs	(69,254)	(43,771)	8,816
Sales of Minerals in Place	0	(100,816)	(9,849)
Previously Estimated Development Costs Incurred	245,964	182,348	101,134
Net Change in Income Taxes at Applicable Statutory Rate	21,370	55,558	(393,353)
Revisions of Previous Quantity Estimates	53,777	61,363	39,078
Accretion of Discount and Other	151,675	80,837	71,080
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$ 1,736,319	$ 1,720,305	$ 1,113,046

Valuation And Qualifying Acco_2

Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
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		24,537	$ 22,526	$ 21,109
Additions Charged to Costs and Expenses		10,184	10,905	6,301
Additions Charged to Other Accounts	[1]	1,707	1,967	1,774
Deductions	[2]	10,640	10,861	6,658
Balance at End of Period		25,788	24,537	22,526
Valuation Allowance for Deferred Tax Assets [Member]
Valuation and Qualifying Accounts [Line Items]
Balance at Beginning of Period	[3]	5,000	0
Additions Charged to Costs and Expenses	[3]	0	5,000
Additions Charged to Other Accounts	[1],[3]	0	0
Deductions	[2],[3]	5,000	0
Balance at End of Period	[3]	$ 0	$ 5,000	$ 0
[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 2019, there was a $5.0 million