National Fuel Gas (NFG) 10-K 16 Nov 18 2018 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2018	Oct. 31, 2018	Mar. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	NATIONAL FUEL GAS CO
Entity Central Index Key	70,145
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		85,963,834
Entity Public Float			$ 4,333,193,000
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false

Consolidated Statements Of Inco

Consolidated Statements Of Income And Earnings Reinvested In The Business - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
INCOME
Operating Revenues	$ 1,592,668	$ 1,579,881	$ 1,452,416
Operating Expenses:
Property, Franchise and Other Taxes	84,393	84,995	81,714
Depreciation, Depletion and Amortization	240,961	224,195	249,417
Impairment of Oil and Gas Producing Properties	0	0	948,307
Total Operating Expenses	1,105,582	1,027,036	1,868,934
Operating Income (Loss)	487,086	552,845	(416,518)
Other Income (Expense):
Other Income	4,697	7,043	9,820
Interest Income	6,766	4,113	4,235
Interest Expense on Long-Term Debt	(110,946)	(116,471)	(117,347)
Other Interest Expense	(3,576)	(3,366)	(3,697)
Income (Loss) Before Income Taxes	384,027	444,164	(523,507)
Income Tax Expense (Benefit)	(7,494)	160,682	(232,549)
Net Income (Loss) Available for Common Stock	391,521	283,482	(290,958)
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	851,669	676,361	1,103,200
Beginning Retained Earnings Unappropriated And Current Period Net Income Loss	1,243,190	959,843	812,242
Dividends on Common Stock	(144,290)	(140,090)	(135,881)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	0	31,916	0
Balance at End of Year	$ 1,098,900	$ 851,669	$ 676,361
Earnings Per Common Share, Basic:
Net Income (Loss) Available for Common Stock (in dollars per share)	$ 4.56	$ 3.32	$ (3.43)
Earnings Per Common Share, Diluted:
Net Income (Loss) Available for Common Stock (in dollars per share)	$ 4.53	$ 3.30	$ (3.43)
Weighted Average Number of Shares Outstanding:
Used in Basic Calculation	85,830,597	85,364,929	84,847,993
Used in Diluted Calculation	86,439,698	86,021,386	84,847,993
Utility and Energy Marketing [Member]
INCOME
Operating Revenues	$ 812,474	$ 755,485	$ 624,602
Operating Expenses:
Operation and Maintenance	200,780	199,293	192,512
Exploration and Production and Other [Member]
INCOME
Operating Revenues	569,808	617,666	611,766
Operating Expenses:
Operation and Maintenance	141,381	145,099	160,201
Pipeline and Storage and Gathering [Member]
INCOME
Operating Revenues	210,386	206,730	216,048
Operating Expenses:
Operation and Maintenance	100,245	98,200	88,801
Purchased Gas [Member]
Operating Expenses:
Purchased Gas	$ 337,822	$ 275,254	$ 147,982

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net Income (Loss) Available for Common Stock	$ 391,521	$ 283,482	$ (290,958)
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	6,225	15,661	(21,378)
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	9,704	13,433	10,068
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	132	4,008	1,524
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(74,103)	5,347	60,493
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	(430)	(1,575)	(1,374)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	1,189	(81,605)	(220,919)
Other Comprehensive Income (Loss), Before Tax	(57,283)	(44,731)	(171,586)
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	1,582	6,175	(8,351)
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	2,437	4,929	3,723
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(15)	1,505	592
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(22,547)	2,009	18,648
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	(158)	(580)	(527)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(955)	(34,286)	(86,659)
Income Taxes - Net	(19,656)	(20,248)	(72,574)
Other Comprehensive Loss	(37,627)	(24,483)	(99,012)
Comprehensive Income (Loss)	$ 353,894	$ 258,999	$ (389,970)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017
ASSETS
Property, Plant and Equipment		$ 10,439,839	$ 9,945,560
Less - Accumulated Depreciation, Depletion and Amortization		5,462,696	5,271,486
Property, Plant and Equipment, Net, Total		4,977,143	4,674,074
Current Assets
Cash and Temporary Cash Investments		229,606	555,530
Hedging Collateral Deposits	[1]	3,441	1,741
Receivables - Net of Allowance for Uncollectible Accounts of $24,537 and $22,526, Respectively		141,498	112,383
Unbilled Revenue		24,182	22,883
Gas Stored Underground		37,813	35,689
Materials and Supplies - at average cost		35,823	33,926
Unrecovered Purchased Gas Costs		4,204	4,623
Other Current Assets		68,024	51,505
Total Current Assets		544,591	818,280
Other Assets
Recoverable Future Taxes		115,460	181,363
Unamortized Debt Expense		15,975	1,159
Other Regulatory Assets		112,918	174,433
Deferred Charges		40,025	30,047
Other Investments		132,545	125,265
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		82,733	56,370
Fair Value of Derivative Financial Instruments		9,518	36,111
Other		102	742
Total Other Assets		514,752	610,966
Total Assets		6,036,486	6,103,320
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 85,956,814 Shares and 85,543,125 Shares, Respectively		85,957	85,543
Paid In Capital		820,223	796,646
Earnings Reinvested in the Business		1,098,900	851,669
Accumulated Other Comprehensive Loss		(67,750)	(30,123)
Total Comprehensive Shareholders' Equity		1,937,330	1,703,735
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,131,365	2,083,681
Total Capitalization		4,068,695	3,787,416
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		0	0
Current Portion of Long-Term Debt	[2]	0	300,000
Accounts Payable		160,031	126,443
Amounts Payable to Customers		3,394	0
Dividends Payable		36,532	35,500
Interest Payable on Long-Term Debt		19,062	35,031
Customer Advances		13,609	15,701
Customer Security Deposits		25,703	20,372
Other Accruals and Current Liabilities		132,693	111,889
Fair Value of Derivative Financial Instruments		49,036	1,103
Total Current and Accrued Liabilities		440,060	646,039
Deferred Credits
Deferred Income Taxes		512,686	891,287
Taxes Refundable to Customers		370,628	95,739
Cost of Removal Regulatory Liability		212,311	204,630
Other Regulatory Liabilities		146,743	113,716
Pension and Other Post-Retirement Liabilities		66,103	149,079
Asset Retirement Obligations		108,235	106,395
Other Deferred Credits		111,025	109,019
Total Deferred Credits		1,527,731	1,669,865
Commitments and Contingencies (Note I)		0	0
Total Capitalization and Liabilities		$ 6,036,486	$ 6,103,320
[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]	Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes that were scheduled to mature in April 2018. The Company redeemed those notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 24,537	$ 22,526
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	85,956,814	85,543,125
Common Stock, Shares Outstanding	85,956,814	85,543,125

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Operating Activities
Net Income (Loss) Available for Common Stock	$ 391,521	$ 283,482	$ (290,958)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	0	0	948,307
Depreciation, Depletion and Amortization	240,961	224,195	249,417
Deferred Income Taxes	(18,153)	117,975	(246,794)
Excess Tax Benefits Associated with Stock-Based Compensation Awards	0	0	(1,868)
Stock-Based Compensation	15,762	12,262	5,755
Other	16,133	16,476	12,620
Change in:
Hedging Collateral Deposits	(1,700)	(257)	9,640
Receivables and Unbilled Revenue	(30,882)	(3,380)	(6,408)
Gas Stored Underground and Materials and Supplies	(4,021)	(1,417)	(3,532)
Unrecovered Purchased Gas Costs	419	(2,183)	(2,440)
Other Current Assets	(16,519)	7,849	3,179
Accounts Payable	17,962	17,192	(40,664)
Amounts Payable to Customers	3,394	(19,537)	(37,241)
Customer Advances	(2,092)	939	(1,474)
Customer Security Deposits	5,331	4,353	(471)
Other Accruals and Current Liabilities	3,865	27,004	3,453
Other Assets	(9,556)	(2,885)	1,941
Other Liabilities	1,178	2,183	(13,483)
Net Cash Provided by Operating Activities	613,603	684,251	588,979
Investing Activities
Capital Expenditures	(584,004)	(450,335)	(581,576)
Net Proceeds from Sale of Oil and Gas Producing Properties	55,506	26,554	137,316
Other	(389)	1,216	(9,236)
Net Cash Used in Investing Activities	(528,887)	(422,565)	(453,496)
Financing Activities
Excess Tax Benefits Associated with Stock-Based Compensation Awards	0	0	1,868
Net Proceeds from Issuance of Long-Term Debt	295,020	295,151	0
Reduction of Long-Term Debt	(566,512)	0	0
Net Proceeds from Issuance of Common Stock	4,110	7,784	13,849
Dividends Paid on Common Stock	(143,258)	(139,063)	(134,824)
Net Cash Provided by (Used in) Financing Activities	(410,640)	163,872	(119,107)
Net Increase (Decrease) in Cash and Temporary Cash Investments	(325,924)	425,558	16,376
Cash and Temporary Cash Investments At Beginning of Year	555,530	129,972	113,596
Cash and Temporary Cash Investments At End of Year	229,606	555,530	129,972
Supplemental Disclosure of Cash Flow Information
Cash Paid for Interest	126,079	116,894	119,563
Cash Paid for Income Taxes	31,771	34,826	34,240
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities
Non-Cash Capital Expenditures	88,813	72,216	60,434
Receivable from Sale of Oil and Gas Producing Properties	$ 0	$ 0	$ 19,543

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Regulation The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion. Revenue Recognition The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. 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 Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services. In the Company’s Gathering segment, revenue is recorded at the point at which gathered volumes are delivered into interstate pipelines. The Company’s Utility segment records revenue for gas sales and transportation in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of 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 Company’s Energy Marketing segment records revenue for gas sales in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of 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. 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 C — 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 December 31st, and applied to customer bills annually, beginning March 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. For further discussion of capitalized costs, refer to Note L — 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 natural 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, 2018, the ceiling exceeded the book value of the oil and gas properties by $569.1 million . In adjusting estimated future net cash flows for hedging under the ceiling test, estimated future net cash flows were decreased by $25.1 million at September 30, 2018 and were increased by $30.5 million and $215.3 million at September 30, 2017 and 2016 , 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 natural 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. On December 1, 2015, Seneca and IOG CRV - Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG holds an 80% working interest in all of the joint development wells. In total, IOG has funded $305.5 million as of September 30. 2018 for its 80% working interest in the 75 joint development wells, which includes $181.2 million of cash ( $137.3 million in fiscal 2016, $26.6 million in fiscal 2017 and $17.3 million in fiscal 2018) included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016, fiscal 2017 and for fiscal 2018, respectively. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. As the fee-owner of the property’s mineral rights, Seneca currently retains a 7.5% royalty interest and the remaining 20% working interest ( 26% net revenue interest) in 48 of the joint development wells. Effective June 1, 2018, actual production for 8 of the joint development wells did not meet production targets, which resulted in an adjustment to Seneca’s royalty interest from 7.5% to 4.98% with no change to the 20% working interest ( 23.98% net revenue interest). In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return. The principal assets of the Utility and Pipeline and Storage 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. 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 2018 2017 (Thousands) Exploration and Production $ 5,222,037 $ 4,925,409 Pipeline and Storage 2,110,714 2,002,736 Gathering 527,188 484,768 Utility 2,104,437 2,045,074 Energy Marketing 3,604 3,564 All Other and Corporate 108,691 109,128 $ 10,076,671 $ 9,570,679 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2018 2017 2016 Exploration and Production, per Mcfe(1) $ 0.70 $ 0.65 $ 0.87 Pipeline and Storage 2.2 % 2.2 % 2.4 % Gathering 3.4 % 3.4 % 4.0 % Utility 2.8 % 2.8 % 2.7 % Energy Marketing 7.7 % 7.9 % 7.9 % All Other and Corporate 2.2 % 1.3 % 1.8 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note L — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.67 , $0.63 and $0.85 per Mcfe of production in 2018 , 2017 and 2016 , respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2018 and 2017 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, 2018 , 2017 and 2016 , 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 Unrealized gains or losses from the Company’s investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion. The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude 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 F — 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, purchased gas expense or operation and maintenance expense on the Consolidated Statements of Income. Reference is made to Note G — 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 G — 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, 2018, 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, 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 ) Year Ended September 30, 2017 Balance at October 1, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) Other Comprehensive Gains and Losses Before Reclassifications 3,338 2,503 9,486 15,327 Amounts Reclassified From Other Comprehensive Loss (47,319 ) (995 ) 8,504 (39,810 ) Balance at September 30, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) 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 and $1.2 million at September 30, 2018 and 2017, respectively. The total amount for accumulated losses was $45.6 million and $57.3 million at September 30, 2018 and 2017, respectively. 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, 2018 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 (Loss) is Presented 2018 2017 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $423 $83,983 Operating Revenues Commodity Contracts 952 (1,921 ) Purchased Gas Foreign Currency Contracts (2,564 ) (457 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale 430 1,575 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit (258 ) (288 ) (1) Net Actuarial Loss (9,446 ) (13,145 ) (1) (10,463 ) 69,747 Total Before Income Tax 1,324 (29,937 ) Income Tax Expense ($9,139 ) $39,810 Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details. Gas Stored Underground In the Utility segment, gas stored underground in the amount of $27.6 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 2018, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $40.2 million at September 30, 2018. All other gas stored underground, which is in the Energy Marketing segment, 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, 2018, the remaining weighted average amortization period for such costs was approximately 8 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. Consolidated Statement of Cash Flows For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. Hedging Collateral Deposits This 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 instrument liability or asset balances. Other Current Assets The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2018 2017 (Thousands) Prepayments $ 11,126 $ 10,927 Prepaid Property and Other Taxes 14,088 13,974 Federal Income Taxes Receivable 22,457 — State Income Taxes Receivable 8,822 9,689 Fair Values of Firm Commitments 1,739 1,031 Regulatory Assets 9,792 15,884 $ 68,024 $ 51,505 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2018 2017 (Thousands) Accrued Capital Expenditures $ 38,354 $ 37,382 Regulatory Liabilities 57,425 34,059 Federal Income Taxes Payable — 1,775 Other 36,914 38,673 $ 132,693 $ 111,889 Customer Advances The Company’s Utility and Energy Marketing segments have 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, 2018 and 2017, customers in the balanced billing programs had advanced excess funds of $13.6 million and $15.7 million , respectively. Customer Security Deposits The Company, in its Utility, Pipeline and Storage, and Energy Marketing 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, 2018 and 2017, the Company had received customer security deposits amounting to $25.7 million and $20.4 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 stock options, SARs, restricted stock units and performance shares. For the years ended September 30, 2018 and 2017, 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. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 317,899 securities and 157,649 securities excluded as being antidilutive for the years ended September 30, 2018 and 2017, respectively. As the Company recognized a net loss for the year ended September 30, 2016, the aforementioned potentially dilutive securities, amounting to 431,408 securities, were not recognized in the diluted earnings per share calculation for 2016. 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 non-performance 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 non-performance based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and non-performance 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 E — 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 In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The Company adopted this authoritative guidance effective October 1, 2018 using the modified retrospective method of adoption. Detailed review of the impact of the guidance on each of the Company’s revenue streams was completed. Based on that review, the Company did not identify any changes to net income, cash flows or the timing of revenue recognition. The Company will be enhancing its financial statement disclosures to comply with the new authoritative guidance for the quarter ending December 31, 2018. 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 will be, as called for by the modified retrospective method of adoption, recording a cumulative effect adjustment for the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount. In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, requiring organizations 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

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable. The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool). In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains, services and other components of the pipeline system in the Utility segment, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment. The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe. On June 30, 2016, Seneca sold the majority of its Upper Devonian wells in Pennsylvania. While the proceeds from the sale were not significant, it did result in a $58.4 million reduction of its Asset Retirement Obligation at September 30, 2016, which is reflected in Liabilities Settled in the table below. The following is a reconciliation of the change in the Company’s asset retirement obligations: Year Ended September 30 2018 2017 2016 (Thousands) Balance at Beginning of Year $ 106,395 $ 112,330 $ 156,805 Liabilities Incurred 5,597 2,963 2,719 Revisions of Estimates (419 ) (10,578 ) 16,721 Liabilities Settled (12,858 ) (4,967 ) (72,215 ) Accretion Expense 9,520 6,647 8,300 Balance at End of Year $ 108,235 $ 106,395 $ 112,330

Regulatory Matters

Regulatory Matters	12 Months Ended
	Sep. 30, 2018
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 2018 2017 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note H) $ 62,703 $ 125,175 Post-Retirement Benefit Costs(2) (Note H) 11,160 13,886 Recoverable Future Taxes (Note D) 115,460 181,363 Environmental Site Remediation Costs(2) (Note I) 20,308 19,665 Asset Retirement Obligations(2) (Note B) 15,495 12,764 Unamortized Debt Expense (Note A) 15,975 1,159 Other(3) 13,044 18,827 Total Regulatory Assets 254,145 372,839 Less: Amounts Included in Other Current Assets (9,792 ) (15,884 ) Total Long-Term Regulatory Assets $ 244,353 $ 356,955 At September 30 2018 2017 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 212,311 $ 204,630 Taxes Refundable to Customers (Note D) 370,628 95,739 Post-Retirement Benefit Costs (Note H) 134,387 102,891 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 3,394 — Other(4) 69,781 44,884 Total Regulatory Liabilities 790,501 448,144 Less: Amounts included in Current and Accrued Liabilities (60,819 ) (34,059 ) Total Long-Term Regulatory Liabilities $ 729,682 $ 414,085 (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) $9,792 and $15,884 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,252 and $2,943 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively. (4) $57,425 and $34,059 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $12,356 and $10,825 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2018 and 2017, 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 B — 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% . On August 9, 2018, in response to the enactment of the 2017 Tax Reform Act, the NYPSC issued an Order Determining Rate Treatment of Tax Changes directing utilities to make compliance filings effective October 1, 2018 to begin providing sur-credits to customers reflecting tax savings associated with the 2017 Tax Reform Act. In compliance with that order, Distribution Corporation filed the necessary tariff amendments to implement the sur-credit effective October 1, 2018. At September 30, 2018, a refund provision of $9.1 million associated with the impact of the 2017 Tax Reform Act in the New York jurisdiction was included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. Refer to Note D — Income Taxes for further discussion of the 2017 Tax Reform Act. 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. In response to the issuance of the 2017 Tax Reform Act, the PaPUC issued an Order to Distribution Corporation on May 17, 2018, requiring that Distribution Corporation file a tariff supplement establishing temporary rates to implement refunds of 2.2% on customer rates beginning July 1, 2018. In compliance with the May 17, 2018 PaPUC Order, Distribution Corporation filed a subsequent tariff supplement adjusting the negative surcharge in connection with the start of its new fiscal year, with the new rates effective October 1, 2018 and subject to reconciliation. At September 30, 2018, a refund provision of $3.4 million associated with the impact of the 2017 Tax Reform Act in the Pennsylvania jurisdiction was included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. Refer to Note D — Income Taxes for further discussion of the 2017 Tax Reform Act. FERC Jurisdiction Supply Corporation currently has no active rate case on file. Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019. The FERC’s July 2018 Final Rule in RM18-11-000, et. al, (Order No. 849) requires pipelines to file a new form isolating the tax impact to each pipeline and also to make an election regarding the action the pipelines will take to address the lower tax rates, one of which is filing a Section 4 rate proceeding. Supply Corporation is required to address the Order by December 6, 2018. At this point, the Company cannot predict the outcome of any action taken pursuant to the Order. Refer to Note D — Income Taxes for further discussion of the 2017 Tax Reform Act. Empire filed a Section 4 rate case on June 29, 2018, proposing rate increases to be effective August 1, 2018. The proposed rates reflect an annual cost of service of $71.5 million , a rate base of $246.8 million and a proposed return on equity of 14% . The FERC has accepted the filed rates and suspended the effective date of the increases until January 1, 2019, when the increased rates will be made effective, subject to refund. Since Empire has filed a rate case, it is not obligated to make a filing under RM18-11-000.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2018
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 (which includes the potential sequestration of the refunds of the AMT credit carryovers as described below) 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. For further discussion, refer to Note C — Regulatory Matters. 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 $84.2 million of AMT credit carryovers that are expected to be utilized or refunded between fiscal 2019 and fiscal 2022. 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. During the year ended September 30, 2018, the Company recorded a $5.0 million estimate for the potential sequestration of AMT credit refunds. 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. The Company has determined a reasonable estimate for the measurement of the changes in deferred income taxes (noted above), which have been reflected as provisional amounts in the September 30, 2018 financial statements. The final determination of the impact of the income tax effects of these items will require further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal/state regulatory guidance, and possible technical corrections, which, if issued, the Company expects to finalize within SAB 118’s measurement period (quarter ended December 31, 2018). Any subsequent guidance 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 2018 2017 2016 (Thousands) Current Income Taxes — Federal $ 2,025 $ 32,034 $ (6,658 ) State 8,634 10,673 20,903 Deferred Income Taxes — Federal (38,927 ) 103,046 (164,818 ) State 20,774 14,929 (81,976 ) (7,494 ) 160,682 (232,549 ) Deferred Investment Tax Credit (105 ) (173 ) (348 ) Total Income Taxes $ (7,599 ) $ 160,509 $ (232,897 ) Presented as Follows: Other Income $ (105 ) $ (173 ) $ (348 ) Income Tax Expense (Benefit) (7,494 ) 160,682 (232,549 ) Total Income Taxes $ (7,599 ) $ 160,509 $ (232,897 ) Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income (loss) before income taxes. The following is a reconciliation of this difference: Year Ended September 30 2018 2017 2016 (Thousands) U.S. Income (Loss) Before Income Taxes $ 383,922 $ 443,991 $ (523,855 ) Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate(1) $ 94,061 $ 155,397 $ (183,349 ) Impact of 2017 Tax Reform Act(2) (112,598 ) — — State Income Taxes (Benefit)(3) 22,203 16,641 (39,697 ) Federal Tax Credits (6,576 ) (6,679 ) (3,262 ) Miscellaneous (4,689 ) (4,850 ) (6,589 ) Total Income Taxes $ (7,599 ) $ 160,509 $ (232,897 ) (1) For fiscal 2018, represents the blended rate of 24.5% . Calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters. (2) 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 described above. (3) The state income taxes (benefit) shown above includes income tax benefits related to state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes. Significant components of the Company’s deferred tax liabilities and assets were as follows: At September 30 2018 2017 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 770,794 $ 1,141,432 Pension and Other Post-Retirement Benefit Costs 39,541 79,516 Other 49,734 77,046 Total Deferred Tax Liabilities 860,069 1,297,994 Deferred Tax Assets: Pension and Other Post-Retirement Benefit Costs (62,969 ) (123,532 ) Tax Loss and Credit Carryforwards (214,128 ) (200,344 ) Other (75,286 ) (82,831 ) Total Gross Deferred Tax Assets (352,383 ) (406,707 ) Valuation Allowance 5,000 — Total Deferred Tax Assets (347,383 ) (406,707 ) Total Net Deferred Income Taxes $ 512,686 $ 891,287 As explained in Note A — Summary of Significant Accounting Policies under the heading "New Authoritative Accounting and Financial Reporting Guidance," 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 $370.6 million and $95.7 million at September 30, 2018 and 2017, 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 $115.5 million and $181.4 million at September 30, 2018 and 2017, respectively. The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2018 2017 2016 (Thousands) Balance at Beginning of Year $ 1,251 $ 396 $ 5,085 Additions for Tax Positions of Prior Years — 1,251 396 Reductions for Tax Positions of Prior Years (788 ) (396 ) (1,314 ) Reductions Related to Settlements with Taxing Authorities (463 ) — (3,771 ) Balance at End of Year $ — $ 1,251 $ 396 The IRS is currently conducting examinations of the Company for fiscal 2018 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 2009, fiscal 2015 and later years. 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 the final guidance. The Company is awaiting the issuance of IRS guidance addressing the issue for natural gas utilities. 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. As of September 30, 2018, the Company has the following carryforwards available: Jurisdiction Tax Attribute Amount (Thousands) Expires Federal Pre-Fiscal 2018 Net Operating Loss $ 191,006 (1) 2029-2037 Federal Post-Fiscal 2017 Net Operating Loss 58,334 Unlimited Pennsylvania Net Operating Loss 351,879 2029-2038 California Net Operating Loss 191,468 2029-2038 Federal Alternative Minimum Tax Credit 84,185 (2) Unlimited California Alternative Minimum Tax Credit 6,983 Unlimited Federal Enhanced Oil Recovery Credit 18,160 2029-2038 California Enhanced Oil Recovery Credit 7,613 2019-2033 Federal R&D Tax Credit 5,876 2031-2037 Federal Charitable Contributions 3,067 2023 (1) Approximately $1.8 million of the federal Net Operating Loss carryforward is subject to certain annual limitations. (2) The $5.0 million estimate recorded for the potential sequestration of AMT credit refunds is not included in this amount.

Capitalization And Short-Term B

Capitalization And Short-Term Borrowings	12 Months Ended
	Sep. 30, 2018
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, 2015 84,594 $ 84,594 $ 744,274 $ 1,103,200 $ 93,372 Net Income (Loss) Available for Common Stock (290,958 ) Dividends Declared on Common Stock ($1.60 Per Share) (135,881 ) Other Comprehensive Loss, Net of Tax (99,012 ) Share-Based Payment Expense(2) 4,843 Common Stock Issued Under Stock and Benefit Plans(1) 525 525 22,047 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(2) 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(2) 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 (3) $ (67,750 ) (1) Paid in Capital includes tax benefits of $1.9 million for September 30, 2016, related to stock-based compensation. (2) 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. (3) 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, 2018, $954.7 million 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 2018, the Company issued 138,997 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 75,745 original issue shares of common stock for the Company's 401(k) plans. During 2018, the Company issued 75,971 original issue shares of common stock as a result of SARs exercises, 72,918 original issue shares of common stock for restricted stock units that vested and 79,079 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 2018, 57,065 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 28,044 original issue shares of common stock during 2018. 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, 2018, 2017 and 2016 was approximately $14.2 million , $10.8 million and $4.8 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, 2018, 2017 and 2016 was approximately $3.4 million , $4.4 million and $1.9 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 , $0.1 million and $0.1 million was capitalized under these rules during the years ended September 30, 2018, 2017 and 2016, respectively. The tax benefit recognized from stock-based compensation exercises and vestings was $1.0 million for the year ended September 30, 2018. SARs Transactions for 2018 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, 2017 1,505,911 $ 48.64 Granted in 2018 — $ — Exercised in 2018 (206,823 ) $ 35.70 Forfeited in 2018 — $ — Expired in 2018 — $ — Outstanding at September 30, 2018 1,299,088 $ 50.70 1.77 $ 8,199 SARs exercisable at September 30, 2018 1,299,088 $ 50.70 1.77 $ 8,199 Shares available for future grant at September 30, 2018(1) 1,478,086 (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, 2017 and 2016. The Company’s SARs include both performance based and non-performance 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, 2018, 2017 and 2016 totaled approximately $4.4 million , $1.6 million , and $0.4 million , respectively. For the years ended September 30, 2017 and 2016, 5,000 SARs and 113,082 SARs, respectively, became fully vested. There were no SARs that became fully vested during the year ended September 30, 2018, and all SARs outstanding have been fully vested since fiscal 2017. The total fair value of the SARs that became vested during the years ended September 30, 2017 and 2016 was approximately $0.1 million and $1.2 million , respectively. Restricted Share Awards Transactions for 2018 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, 2017 20,000 $ 47.46 Granted in 2018 — $ — Vested in 2018 — $ — Forfeited in 2018 — $ — Outstanding at September 30, 2018 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, 2017 and 2016. As of September 30, 2018, unrecognized compensation expense related to restricted share awards totaled approximately $0.2 million , which will be recognized over a weighted average period of 2.1 years . Vesting restrictions for the 20,000 outstanding shares of non-vested restricted stock at September 30, 2018 will lapse in 2021. Restricted Stock Units Transactions for 2018 involving non-performance 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, 2017 233,199 $ 48.99 Granted in 2018 89,672 $ 51.23 Vested in 2018 (72,918 ) $ 53.73 Forfeited in 2018 (4,637 ) $ 46.04 Outstanding at September 30, 2018 245,316 $ 48.45 The Company also granted 87,143 and 101,943 non-performance based restricted stock units during the years ended September 30, 2017 and 2016, respectively. The weighted average fair value of such non-performance based restricted stock units granted in 2017 and 2016 was $52.13 per share and $35.89 per share, respectively. As of September 30, 2018, unrecognized compensation expense related to non-performance based restricted stock units totaled approximately $5.0 million , which will be recognized over a weighted average period of 2.2 years . Vesting restrictions for the non-performance based restricted stock units outstanding at September 30, 2018 will lapse as follows: 2019 — 80,354 units; 2020 — 68,189 units; 2021 — 57,175 units; 2022 - 26,448 units; and 2023 - 13,150 units. Performance Shares Transactions for 2018 involving performance shares for all plans are summarized as follows: Number of Performance Shares Weighted Average Fair Value per Award Outstanding at September 30, 2017 527,748 $ 45.44 Granted in 2018 208,588 $ 50.95 Vested in 2018 (79,079 ) $ 65.38 Forfeited in 2018 (15,967 ) $ 57.15 Outstanding at September 30, 2018 641,290 $ 44.49 The Company also granted 184,148 and 309,996 performance shares during the years ended September 30, 2017 and 2016, respectively. The weighted average grant date fair value of such performance shares granted in 2017 and 2016 was $56.39 per share and $30.71 per share, respectively. As of September 30, 2018, unrecognized compensation expense related to performance shares totaled approximately $11.2 million , which will be recognized over a weighted average period of 1.7 years . Vesting restrictions for the outstanding performance shares at September 30, 2018 will lapse as follows: 2019 - 253,704 shares; 2020 - 181,446 shares; and 2021 - 206,140 shares. Half of the performance shares granted during the years ended September 30, 2018, 2017 and 2016 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 2018, 2017 and 2016 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, 2018, 2017 and 2016 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 2018, 2017 and 2016 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 2018 2017 2016 Risk-Free Interest Rate 1.96 % 1.54 % 1.26 % Remaining Term at Date of Grant (Years) 2.78 2.79 2.79 Expected Volatility 22.0 % 22.6 % 20.5 % Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2018, 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 2018 2017 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(3)(4): 3.75% to 5.20% due December 2021 to September 2028 2,050,000 2,300,000 Total Long-Term Debt 2,149,000 2,399,000 Less Unamortized Discount and Debt Issuance Costs 17,635 15,319 Less Current Portion(2) — 300,000 $ 2,131,365 $ 2,083,681 (1) The Medium-Term Notes and Notes are unsecured. (2) Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes that were scheduled to mature in April 2018. The Company redeemed those notes on October 18, 2017 for $307.0 million , plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017. (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% , 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). 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. On September 27, 2017, the Company issued $300.0 million of 3.95% notes due September 15, 2027. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $295.2 million . The proceeds of this debt issuance were used to redeem $300.0 million of 6.50% notes in October 2017, as discussed above in a footnote to the table of long-term debt outstanding. As of September 30, 2018, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2019, 2020 and 2021, $500.0 million in 2022, $549.0 million in 2023, 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 an uncommitted line of credit with a financial institution for general corporate purposes. Borrowings under this uncommitted line of credit would be made at competitive market rates. The uncommitted credit line is revocable at the option of the financial institution and is reviewed on an annual basis. The Company anticipates that its uncommitted line of credit generally will be renewed or substantially replaced by a similar line. 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, 2018, the commercial paper program was backed by the Credit Agreement. The Company did not have any outstanding commercial paper or short term notes payable to banks at September 30, 2018 and 2017. 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, 2018, the Company’s debt to capitalization ratio (as calculated under the facility) was .52 . The constraints specified in the Credit Agreement would have permitted an additional $1.46 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, 2018, the Company did not have any debt outstanding under the Credit Agreement. Under the Company’s existing indenture covenants at September 30, 2018, the Company would have been permitted to issue up to a maximum of $714.0 million 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, 2018) 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, 2018
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, 2018 and 2017. 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, 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 At Fair Value as of September 30, 2017 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 $ 527,978 $ — $ — $ — $ 527,978 Derivative Financial Instruments: Commodity Futures Contracts — Gas 1,483 — — (963 ) 520 Over the Counter Swaps — Gas and Oil — 38,977 — (4,206 ) 34,771 Foreign Currency Contracts — 1,227 — (407 ) 820 Other Investments: Balanced Equity Mutual Fund 37,033 — — — 37,033 Fixed Income Mutual Fund 45,727 — — — 45,727 Common Stock — Financial Services Industry 3,150 — — — 3,150 Hedging Collateral Deposits 1,741 — — — 1,741 Total $ 617,112 $ 40,204 $ — $ (5,576 ) $ 651,740 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 963 $ — $ — $ (963 ) $ — Over the Counter Swaps — Gas and Oil — 5,309 — (4,206 ) 1,103 Foreign Currency Contracts — 407 — (407 ) — Total $ 963 $ 5,716 $ — $ (5,576 ) $ 1,103 Total Net Assets/(Liabilities) $ 616,149 $ 34,488 $ — $ — $ 650,637 (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, 2018 and 2017, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits of $3.4 million (at September 30, 2018) and $1.7 million (at September 30, 2017), 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, 2018 and 2017 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the crude oil price swap agreements used in the Company’s Exploration and Production segment 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, 2018, 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, 2018 and 2017, there were no assets or liabilities measured at fair value and classified as Level 3. For the years ended September 30, 2018 and September 30, 2017, no transfers in or out of Level 1 or Level 2 occurred.

Financial Instruments

Financial Instruments	12 Months Ended
	Sep. 30, 2018
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 2018 Carrying Amount 2018 Fair Value 2017 Carrying 2017 Fair (Thousands) Long-Term Debt $ 2,131,365 $ 2,121,861 $ 2,383,681 $ 2,523,639 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 2018 2017 (Thousands) Life Insurance Contracts $ 39,970 $ 39,355 Equity Mutual Fund 38,468 37,033 Fixed Income Mutual Fund 51,331 45,727 Marketable Equity Securities 2,776 3,150 $ 132,545 $ 125,265 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. The gross unrealized gain on the equity mutual fund was $10.7 million and $9.9 million at September 30, 2018 and 2017, respectively. A sale of shares in the equity mutual fund during the year ended September 30, 2018 resulted in $1.5 million of cash proceeds and a realized gain of $0.4 million . The gross unrealized loss on the fixed income mutual fund was $0.8 million and less than $0.1 million at September 30, 2018 and 2017, respectively. A sale of shares in the fixed income mutual fund during the year ended September 30, 2018 resulted in $1.5 million of cash proceeds and a realized loss of less than $0.1 million . The gross unrealized gain on the marketable equity securities was $1.8 million and $2.2 million at September 30, 2018 and 2017, respectively. 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 the Energy Marketing segment. 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 length 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 8 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, 2018 and September 30, 2017 . 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 effective portion of 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. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. As of September 30, 2018 , the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding: Commodity Units Natural Gas 120.1 Bcf (short positions) Natural Gas 1.8 Bcf (long positions) Crude Oil 4,188,000 Bbls (short positions) As of September 30, 2018 , the Company was hedging a total of $86.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions). As of September 30, 2018 , the Company had $37.4 million ( $28.6 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $23.7 million ( $17.0 million after tax) of such unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2018 and 2017 (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, 2018 2017 2018 2017 2018 2017 Commodity Contracts $ (70,905 ) $ 2,811 Operating Revenue $ 423 $ 83,983 Operating Revenue $ (782 ) $ (100 ) Commodity Contracts 701 (164 ) Purchased Gas 952 (1,921 ) Not Applicable — — Foreign Currency Contracts (3,899 ) 2,700 Operation and Maintenance Expense (2,564 ) (457 ) Not Applicable — — Total $ (74,103 ) $ 5,347 $ (1,189 ) $ 81,605 $ (782 ) $ (100 ) 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, 2018 , the Company’s Energy Marketing segment had fair value hedges covering approximately 27.7 Bcf ( 27.1 Bcf of fixed price sales commitments and 0.6 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, 2018 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2018 (In thousands) Commodity Contracts Operating Revenues $ (1,289 ) $ 1,289 Commodity Contracts Purchased Gas (238 ) 238 $ (1,527 ) $ 1,527 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 three 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, 2018 . The maximum credit exposure per counterparty in a gain position at September 30, 2018 was $5.6 million . As of September 30, 2018 , 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, 2018 , 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, 2018 , the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $9.0 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). At September 30, 2018 , the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $40.3 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, 2018 . For its exchange traded futures contracts, the Company was required to post $3.4 million in hedging collateral deposits as of September 30, 2018 . 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. The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note A under Hedging Collateral Deposits.

Retirement Plan And Other Post-

Retirement Plan And Other Post-Retirement Benefits	12 Months Ended
	Sep. 30, 2018
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 $3.5 million , $2.9 million and $2.6 million for the years ended September 30, 2018 , 2017 and 2016 , 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 $6.2 million , $5.9 million , and $5.9 million for the years ended September 30, 2018 , 2017 and 2016 , 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 2018 , 2017 and 2016 . Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2018 2017 2016 2018 2017 2016 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 1,054,826 $ 1,097,421 $ 1,026,190 $ 462,619 $ 526,138 $ 464,987 Service Cost 9,921 11,969 11,710 1,830 2,449 2,331 Interest Cost 33,006 38,383 42,315 14,801 19,007 20,386 Plan Participants’ Contributions — — — 2,894 2,717 2,558 Retiree Drug Subsidy Receipts — — — 1,545 1,553 1,925 Actuarial (Gain) Loss (50,218 ) (32,466 ) 76,309 (21,039 ) (62,215 ) 60,402 Benefits Paid (61,845 ) (60,481 ) (59,103 ) (26,664 ) (27,030 ) (26,451 ) Benefit Obligation at End of Period $ 985,690 $ 1,054,826 $ 1,097,421 $ 435,986 $ 462,619 $ 526,138 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 910,719 $ 869,775 $ 834,870 $ 514,017 $ 494,320 $ 477,959 Actual Return on Plan Assets 42,652 84,279 87,008 20,657 40,157 37,415 Employer Contributions 32,980 17,146 7,000 2,896 3,853 2,839 Plan Participants’ Contributions — — — 2,894 2,717 2,558 Benefits Paid (61,845 ) (60,481 ) (59,103 ) (26,664 ) (27,030 ) (26,451 ) Fair Value of Assets at End of Period $ 924,506 $ 910,719 $ 869,775 $ 513,800 $ 514,017 $ 494,320 Net Amount Recognized at End of Period (Funded Status) $ (61,184 ) $ (144,107 ) $ (227,646 ) $ 77,814 $ 51,398 $ (31,818 ) Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (61,184 ) $ (144,107 ) $ (227,646 ) $ (4,919 ) $ (4,972 ) $ (49,467 ) Non-Current Assets — — — 82,733 56,370 17,649 Net Amount Recognized at End of Period $ (61,184 ) $ (144,107 ) $ (227,646 ) $ 77,814 $ 51,398 $ (31,818 ) Accumulated Benefit Obligation $ 946,763 $ 1,010,179 $ 1,039,408 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 4.30 % 3.77 % 3.60 % 4.31 % 3.81 % 3.70 % 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 2018 2017 2016 2018 2017 2016 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 9,921 $ 11,969 $ 11,710 $ 1,830 $ 2,449 $ 2,331 Interest Cost 33,006 38,383 42,315 14,801 19,007 20,386 Expected Return on Plan Assets (61,715 ) (59,718 ) (59,369 ) (31,482 ) (31,458 ) (31,535 ) Amortization of Prior Service Cost (Credit) 938 1,058 1,234 (429 ) (429 ) (912 ) Recognition of Actuarial Loss(1) 37,205 42,687 32,248 10,558 18,415 5,530 Net Amortization and Deferral for Regulatory Purposes 9,027 469 3,957 15,028 6,108 17,123 Net Periodic Benefit Cost $ 28,382 $ 34,848 $ 32,095 $ 10,306 $ 14,092 $ 12,923 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 3.77 % 3.60 % 4.25 % 3.81 % 3.70 % 4.50 % Effective Rate for Interest on Benefit Obligations 3.23 % 3.60 % 4.25 % 3.29 % 3.70 % 4.50 % Effective Discount Rate for Service Cost 4.00 % 3.60 % 4.25 % 4.10 % 3.70 % 4.50 % Effective Rate for Interest on Service Cost 3.73 % 3.60 % 4.25 % 3.98 % 3.70 % 4.50 % Expected Return on Plan Assets 7.00 % 7.00 % 7.25 % 6.25 % 6.50 % 6.75 % Rate of Compensation Increase 4.70 % 4.70 % 4.75 % 4.70 % 4.70 % 4.75 % (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 $6.8 million , $7.6 million and $7.5 million in 2018 , 2017 and 2016 , respectively. The accumulated benefit obligations for the plans were $70.6 million , $72.5 million and $72.4 million at September 30, 2018 , 2017 and 2016 , respectively. The projected benefit obligations for the plans were $86.1 million , $88.9 million and $91.7 million at September 30, 2018 , 2017 and 2016 , respectively. At September 30, 2018 , $11.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $74.6 million is 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. At September 30, 2016 , $9.8 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $81.9 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 4.02% , 3.22% and 2.80% as of September 30, 2018 , 2017 and 2016 , respectively and the weighted average rates of compensation increase for these plans were 7.75% , 7.75% and 7.75% as of September 30, 2018 , 2017 and 2016 , respectively. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2018 , the changes in such amounts during 2018 , as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2019 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 Gain (Loss) $ (135,527 ) $ 1,193 $ (22,818 ) Prior Service (Cost) Credit (5,195 ) 3,258 — Net Amount Recognized $ (140,722 ) $ 4,451 $ (22,818 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2018(1) Decrease (Increase) in Actuarial Loss, excluding amortization(2) $ 31,155 $ 10,213 $ (2,035 ) Change due to Amortization of Actuarial Loss 37,205 10,558 3,549 Prior Service (Cost) Credit 938 (429 ) — Net Change $ 69,298 $ 20,342 $ 1,514 Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (32,096 ) $ (5,962 ) $ (3,558 ) Prior Service (Cost) Credit (826 ) 429 — Net Amount Expected to be Recognized $ (32,922 ) $ (5,533 ) $ (3,558 ) (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, 2018 , the Company recorded a $75.3 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $15.9 million (pre-tax) increase to Accumulated Other Comprehensive Income. 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 mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2018 by $3.3 million . Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2018 by $11.2 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 effect of the discount rate change for the Retirement Plan in 2016 was to increase the projected benefit obligation of the Retirement Plan by $78.5 million . The Company made cash contributions totaling $33.0 million to the Retirement Plan during the year ended September 30, 2018. The Company expects that the annual contribution to the Retirement Plan in 2019 will be in the range of $29.0 million to $35.0 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: $65.7 million in 2019; $65.9 million in 2020; $66.3 million in 2021; $66.5 million in 2022; $66.6 million in 2023; and $330.9 million in the five years thereafter. 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 retiree drug subsidy assumptions based on actual experience. The effect of the discount rate change in 2016 was to increase the other post-retirement benefit obligation by $49.4 million . Other actuarial experience increased the other post-retirement benefit obligation in 2016 by $11.0 million primarily attributable to a revision in assumed per-capita claims cost, premiums, participant 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 2019 $ 27,821 $ (1,858 ) 2020 $ 28,692 $ (1,996 ) 2021 $ 29,455 $ (2,128 ) 2022 $ 29,979 $ (2,260 ) 2023 $ 30,426 $ (2,386 ) 2024 through 2028 $ 153,855 $ (13,325 ) Assumed health care cost trend rates as of September 30 were: 2018 2017 2016 Rate of Medical Cost Increase for Pre Age 65 Participants 5.59 % (1) 5.67 % (1) 5.75 % (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 7.89 % (1) 8.45 % (1) 9.00 % (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 7.18 % (1) 7.33 % (1) 7.20 % (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, 2018 would increase by $51.3 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 2018 by $2.9 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, 2018 would decrease by $42.8 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 2018 by $2.1 million . The Company made cash contributions totaling $2.8 million to its VEBA trusts during the year ended September 30, 2018 . In addition, the Company made direct payments of $0.1 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2018 . The Company expects that the annual contribution to its VEBA trusts in 2019 will be in the range of $2.5 million to $4.0 million . Investment Valuation The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note F — 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, 2018 and 2017 , 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): Total Fair Value Amounts at September 30, 2018 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 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) Retirement Plan Investments Domestic Equities(1) $ 290,716 $ 209,421 $ — $ — $ 81,295 International Equities(2) 123,069 — — — 123,069 Global Equities(3) 121,008 — — — 121,008 Domestic Fixed Income(4) 348,501 1,664 346,837 — — International Fixed Income(5) 422 422 — — — Global Fixed Income(6) 75,428 — — — 75,428 Real Estate 3,391 — — 3,391 — Cash Held in Collective Trust Funds 26,058 — — — 26,058 Total Retirement Plan Investments 988,593 211,507 346,837 3,391 426,858 401(h) Investments (64,728 ) (14,026 ) (23,001 ) (225 ) (27,476 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 923,865 $ 197,481 $ 323,836 $ 3,166 $ 399,382 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (13,146 ) Total Retirement Plan Assets $ 910,719 (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 an exchange traded fund. (6) Global Fixed Income securities are comprised of a collective trust fund. (7) Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient. 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 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 $ 130,864 $ — $ — $ — $ 130,864 Collective Trust Funds — International Equities 52,063 — — — 52,063 Exchange Traded Funds — Fixed Income 256,099 256,099 — — — Cash Held in Collective Trust Funds 9,569 — — — 9,569 Total VEBA Trust Investments 448,595 256,099 — — 192,496 401(h) Investments 64,728 14,026 23,001 225 27,476 Total Investments (including 401(h) Investments) $ 513,323 $ 270,125 $ 23,001 $ 225 $ 219,972 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 694 Total Other Post-Retirement Benefit Assets $ 514,017 (1) Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient. 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, 2018 and September 30, 2017 , 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, 2016 $ 2,970 $ (188 ) $ 2,782 Unrealized Gains/(Losses) 421 (37 ) 384 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 Other Post-Retirement Benefit Level 3 Assets (Thousands) 401(h) Investments Balance at September 30, 2016 $ 188 Unrealized Gains/(Losses) 37 Balance at September 30, 2017 225 Unrealized Gains/(Losses) 19 Sales (26 ) Balance at September 30, 2018 $ 218 The Company’s assumption regarding the expected long-term rate of return on plan assets is 6.75% (Retirement Plan) and 6.00% (other post-retirement benefits), effective for fiscal 2019. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets. The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). The target allocation for the Retirement Plan and the VEBA trusts (including 401(h) accounts) is 30 - 50% equity securities, 50 - 70% fixed income securities (including return-seeking investments) and 0 - 15% other (including return-seeking investments). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity. Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis. The Company determines the service and interest cost components of net periodic benefit cost using the spot rate approach, which uses individual spot rates along the yield curve that correspond to the timing of each benefit payment in order to determine the discount rate. The individual spot rates along the yield curve are determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile are excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Sep. 30, 2018
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, 2018, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $7.6 million , which includes a $4.1 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, 2018. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 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 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. On April 7, 2017, 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 on January 27, 2017). On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the United States Court of Appeals for the Second Circuit of the NYDEC's Notice of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. On August 6, 2018, 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. Rehearing requests have been filed at FERC. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the target in-service date for the project is expected to be no earlier than the first half of fiscal 2022. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of September 30, 2018 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming construction of the pipeline, as well as a scenario where the project does not proceed. Further developments or indicators of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $76.2 million at September 30, 2018 . The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet. Other The Company, in its Utility segment, Energy Marketing segment, and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $297.9 million in 2019, $102.9 million in 2020, $86.6 million in 2021, $152.5 million in 2022, $162.8 million in 2023 and $1,606.0 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 compressors, drilling rigs, buildings and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $18.6 million in 2019, $4.6 million in 2020, $4.0 million in 2021, $3.2 million in 2022, $2.7 million in 2023 and $12.4 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, 2018, the future contractual commitments related to the system modernization and expansion projects are $105.1 million in 2019, $6.8 million in 2020, $6.1 million in 2021, $5.1 million in 2022, $3.4 million in 2023 and $13.3 million thereafter. The Company, in its Exploration and Production segment, has entered into contractual obligations associated with hydraulic fracturing and fuel. The future contractual commitments are $86.2 million in 2019 and $24.8 million in 2020. There are no contractual commitments extending beyond 2020. The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note C — 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, 2018
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information The Company reports financial results for five segments: Exploration and Production, Pipeline and Storage, Gathering, Utility and Energy Marketing. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas and oil reserves in 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 along with exploration and production companies from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points for 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 Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers. 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, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. Year Ended September 30, 2018 Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 564,547 $ 210,345 $ 41 $ 674,726 $ 137,748 $ 1,587,407 $ 4,601 $ 660 $ 1,592,668 Intersegment Revenues $ — $ 89,981 $ 107,856 $ 12,800 $ 826 $ 211,463 $ — $ (211,463 ) $ — Interest Income $ 1,479 $ 2,748 $ 1,106 $ 1,591 $ 685 $ 7,609 $ 388 $ (1,231 ) $ 6,766 Interest Expense $ 54,288 $ 31,383 $ 9,560 $ 26,753 $ 22 $ 122,006 $ — $ (7,484 ) $ 114,522 Depreciation, Depletion and Amortization $ 124,274 $ 43,463 $ 17,313 $ 53,253 $ 275 $ 238,578 $ 1,627 $ 756 $ 240,961 Income Tax Expense (Benefit) $ (41,962 ) $ 17,806 $ (17,677 ) $ 15,258 $ 632 $ (25,943 ) $ 1,493 $ 16,956 $ (7,494 ) Segment Profit: Net Income (Loss) $ 180,632 $ 97,246 $ 83,519 $ 51,217 $ 373 $ 412,987 $ (112 ) $ (21,354 ) $ 391,521 Expenditures for Additions to Long-Lived Assets $ 380,677 $ 92,832 $ 61,728 $ 85,648 $ 40 $ 620,925 $ 1 $ (20,324 ) $ 600,602 At September 30, 2018 (Thousands) Segment Assets $ 1,568,563 $ 1,848,180 $ 533,608 $ 1,921,971 $ 50,971 $ 5,923,293 $ 78,109 $ 35,084 $ 6,036,486 Year Ended September 30, 2017 Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Elimination Total Consolidated (Thousands) Revenue from External Customers(1) $ 614,599 $ 206,615 $ 115 $ 626,899 $ 128,586 $ 1,576,814 $ 2,173 $ 894 $ 1,579,881 Intersegment Revenues $ — $ 87,810 $ 107,566 $ 13,072 $ 794 $ 209,242 $ — $ (209,242 ) $ — Interest Income $ 707 $ 1,467 $ 994 $ 1,051 $ 571 $ 4,790 $ 213 $ (890 ) $ 4,113 Interest Expense $ 53,702 $ 33,717 $ 9,142 $ 28,492 $ 47 $ 125,100 $ — $ (5,263 ) $ 119,837 Depreciation, Depletion and Amortization $ 112,565 $ 41,196 $ 16,162 $ 52,582 $ 279 $ 222,784 $ 661 $ 750 $ 224,195 Income Tax Expense (Benefit) $ 66,093 $ 40,947 $ 29,694 $ 24,894 $ 891 $ 162,519 $ (247 ) $ (1,590 ) $ 160,682 Segment Profit: Net Income (Loss) $ 129,326 $ 68,446 $ 40,377 $ 46,935 $ 1,509 $ 286,593 $ (342 ) $ (2,769 ) $ 283,482 Expenditures for Additions to Long-Lived Assets $ 253,057 $ 95,336 $ 32,645 $ 80,867 $ 36 $ 461,941 $ 39 $ 137 $ 462,117 At September 30, 2017 (Thousands) Segment Assets $ 1,407,152 $ 1,929,788 $ 580,051 $ 2,013,123 $ 60,937 $ 5,991,051 $ 76,861 $ 35,408 $ 6,103,320 Year Ended September 30, 2016 Exploration Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 607,113 $ 215,674 $ 374 $ 531,024 $ 93,578 $ 1,447,763 $ 3,753 $ 900 $ 1,452,416 Intersegment Revenues $ — $ 90,755 $ 89,073 $ 13,123 $ 884 $ 193,835 $ — $ (193,835 ) $ — Interest Income $ 858 $ 770 $ 297 $ 1,737 $ 422 $ 4,084 $ 117 $ 34 $ 4,235 Interest Expense $ 55,434 $ 33,327 $ 8,872 $ 27,582 $ 49 $ 125,264 $ — $ (4,220 ) $ 121,044 Depreciation, Depletion and Amortization $ 139,963 $ 43,273 $ 15,282 $ 48,618 $ 278 $ 247,414 $ 1,260 $ 743 $ 249,417 Income Tax Expense (Benefit) $ (334,029 ) $ 50,241 $ 24,334 $ 25,602 $ 2,460 $ (231,392 ) $ 561 $ (1,718 ) $ (232,549 ) Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ 948,307 $ — $ — $ — $ — $ 948,307 $ — $ — $ 948,307 Segment Profit: Net Income (Loss) $ (452,842 ) $ 76,610 $ 30,499 $ 50,960 $ 4,348 $ (290,425 ) $ 778 $ (1,311 ) $ (290,958 ) Expenditures for Additions to Long-Lived Assets $ 256,104 $ 114,250 $ 54,293 $ 98,007 $ 34 $ 522,688 $ 37 $ 326 $ 523,051 At September 30, 2016 (Thousands) Segment Assets $ 1,323,081 $ 1,680,734 $ 534,259 $ 2,021,514 $ 63,392 $ 5,622,980 $ 77,138 $ (63,731 ) $ 5,636,387 (1) All Revenue from External Customers originated in the United States. Geographic Information At September 30 2018 2017 2016 (Thousands) Long-Lived Assets: United States $ 5,491,895 $ 5,285,040 $ 5,223,356

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Sep. 30, 2018
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) 2018 9/30/2018 $ 289,196 $ 80,629 $ 37,995 (1) $ 0.44 $ 0.44 6/30/2018 $ 342,912 $ 107,760 $ 63,025 $ 0.73 $ 0.73 3/31/2018 $ 540,905 $ 156,702 $ 91,847 (2) $ 1.07 $ 1.06 12/31/2017 $ 419,655 $ 141,995 $ 198,654 (3) $ 2.32 $ 2.30 2017 9/30/2017 $ 286,937 $ 87,395 $ 45,577 $ 0.53 $ 0.53 6/30/2017 $ 348,369 $ 123,354 $ 59,714 $ 0.70 $ 0.69 3/31/2017 $ 522,075 $ 169,957 $ 89,283 $ 1.05 $ 1.04 12/31/2016 $ 422,500 $ 172,139 $ 88,908 $ 1.04 $ 1.04 (1) 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. (2) 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. (3) Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.

Supplementary Information For O

Supplementary Information For Oil And Gas Producing Activities	12 Months Ended
	Sep. 30, 2018
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 2018 2017 (Thousands) Proved Properties(1) $ 5,114,753 $ 4,832,301 Unproved Properties 62,234 80,932 5,176,987 4,913,233 Less — Accumulated Depreciation, Depletion and Amortization 3,862,687 3,765,710 $ 1,314,300 $ 1,147,523 (1) Includes asset retirement costs of $44.3 million and $54.4 million at September 30, 2018 and 2017, 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 2023. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2020. Following is a summary of costs excluded from amortization at September 30, 2018: Total as of September 30, 2018 Year Costs Incurred 2018 2017 2016 Prior (Thousands) Acquisition Costs $ 39,681 $ — $ — $ — $ 39,681 Development Costs 14,824 11,115 236 2,886 587 Exploration Costs 7,606 — 32 7,574 — Capitalized Interest 123 20 — 103 — $ 62,234 $ 11,135 $ 268 $ 10,563 $ 40,268 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2018 2017 2016 (Thousands) United States Property Acquisition Costs: Proved $ 1,544 $ 8,908 $ 1,342 Unproved 4,286 262 2,165 Exploration Costs(1) 29,365 40,975 27,561 Development Costs(2) 332,496 200,639 219,386 Asset Retirement Costs (10,107 ) (9,175 ) (49,653 ) $ 357,584 $ 241,609 $ 200,801 (1) Amounts for 2018, 2017 and 2016 include capitalized interest of zero , $0.3 million and $0.3 million , respectively. (2) Amounts for 2018, 2017 and 2016 include capitalized interest of $0.3 million , $0.2 million and $0.2 million , respectively. For the years ended September 30, 2018, 2017 and 2016, the Company spent $182.3 million , $101.1 million and $92.8 million , respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2018 2017 2016 United States (Thousands, except per Mcfe amounts) Operating Revenues: Natural Gas (includes transfers to operations of $2,134, $2,357 and $1,765, respectively)(1) $ 390,642 $ 399,975 $ 282,619 Oil, Condensate and Other Liquids 168,254 126,517 103,533 Total Operating Revenues(2) 558,896 526,492 386,152 Production/Lifting Costs 162,721 165,991 153,914 Franchise/Ad Valorem Taxes 14,355 15,372 13,794 Purchased Emission Allowance Expense 1,883 1,391 700 Accretion Expense 4,266 4,896 6,663 Depreciation, Depletion and Amortization ($0.67, $0.63 and $0.85 per Mcfe of production, respectively) 119,946 108,471 136,579 Impairment of Oil and Gas Producing Properties — — 948,307 Income Tax Expense (Benefit) 72,723 86,657 (368,940 ) Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 183,002 $ 143,714 $ (504,865 ) (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 G — 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 2004 and with over 5 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, 2018 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, 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, 2015 2,092,782 49,346 2,142,128 Extensions and Discoveries 185,347 (1) — 185,347 Revisions of Previous Estimates (245,029 ) (3,132 ) (248,161 ) Production (140,457 ) (2) (3,090 ) (143,547 ) Sale of Minerals in Place (261,192 ) — (261,192 ) 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 Proved Developed Reserves: September 30, 2015 1,267,498 49,346 1,316,844 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 Proved Undeveloped Reserves: September 30, 2015 825,284 — 825,284 September 30, 2016 541,959 — 541,959 September 30, 2017 610,018 — 610,018 September 30, 2018 750,810 — 750,810 (1) Extensions and discoveries include 179 Bcf (during 2016), 181 Bcf (during 2017) and 274 Bcf (during 2018), of Marcellus Shale gas in the Appalachian region. Extensions and discoveries include 6 Bcf (during 2016), 205 Bcf (during 2017) and 248 Bcf (during 2018), of Utica Shale gas in the Appalachian region. (2) Production includes 135,598 MMcf (during 2016), 145,452 MMcf (during 2017) and 150,196 MMcf (during 2018), from Marcellus Shale fields (which exceed 15% of total reserves). Production includes 9,409 MMcf (during 2018), from Utica Shale fields (which exceed 15% of total reserves). Oil Mbbl U.S. Appalachian Region West Coast Region Total Company Proved Developed and Undeveloped Reserves: September 30, 2015 220 33,502 33,722 Extensions and Discoveries — 530 530 Revisions of Previous Estimates (46 ) (2,201 ) (2,247 ) Production (28 ) (2,895 ) (2,923 ) Sales of Minerals in Place (73 ) — (73 ) 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 Proved Developed Reserves: September 30, 2015 220 33,150 33,370 September 30, 2016 73 28,698 28,771 September 30, 2017 28 29,771 29,799 September 30, 2018 14 26,689 26,703 Proved Undeveloped Reserves: September 30, 2015 — 352 352 September 30, 2016 — 238 238 September 30, 2017 — 408 408 September 30, 2018 — 960 960 The Company’s proved undeveloped (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 Company’s PUD reserves increased from 543 Bcfe at September 30, 2016 to 612 Bcfe at September 30, 2017. PUD reserves in the Marcellus Shale decreased from 542 Bcfe at September 30, 2016 to 456 Bcfe at September 30, 2017. The Company’s total PUD reserves were 28% of total proved reserves at September 30, 2017, down from 29% of total proved reserves at September 30, 2016. 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 the joint development agreement, previously discussed. The increase in PUD reserves in 2017 of 69 Bcfe was a result of 269 Bcfe in new PUD reserve additions ( 113 Bcfe from the Marcellus Shale, 154 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 13 Bcfe in upward revisions to remaining PUD reserves, partially offset by 159 Bcfe in PUD conversions to developed reserves ( 158 Bcfe from the Marcellus Shale and 1 Bcfe from the West Coast region) and 54 Bcfe in PUD reserves removed. In the Eastern Development Area, Marcellus Shale PUD reserves of 36 Bcfe were removed due to development timing no longer scheduled to meet the five year requirement for proved reserves. Seneca successfully leased an adjacent tract to these wells in 2017 and intends to develop the wells now with longer laterals drilled into this adjacent tract. These development plans are not expected to commence within the five year time horizon from original booking. Marcellus Shale PUD reserves of 18 Bcfe were removed as part of Seneca’s transition toward a Utica focused development program in the Western Development Area, where certain Marcellus well locations were replaced with Utica well locations in the Company's development plan. 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 booked 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. The Company invested $101 million during the year ended September 30, 2017 to convert 147 Bcfe of Marcellus Shale PUD reserves to developed reserves. This represents 27% of the net PUD reserves booked at September 30, 2016. In fiscal 2017, the Company developed 37 (or 41% ) of its well locations with net PUD reserves recorded at September 30, 2016. The vast majority of these wells were in the Appalachian region. In 2019, the Company estimates that it will invest approximately $210 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 51% of its beginning year PUD reserves in fiscal 2014, 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 and 51% of its beginning year PUD reserves in fiscal 2018. At September 30, 2018, 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 2018 2017 2016 (Thousands) United States Future Cash Inflows $ 7,822,855 $ 6,144,317 $ 3,768,463 Less: Future Production Costs 2,606,411 2,378,262 1,994,916 Future Development Costs 559,707 411,578 375,152 Future Income Tax Expense at Applicable Statutory Rate 1,125,910 1,160,469 303,397 Future Net Cash Flows 3,530,827 2,194,008 1,094,998 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,810,522 1,080,962 452,470 Standardized Measure of Discounted Future Net Cash Flows $ 1,720,305 $ 1,113,046 $ 642,528 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2018 2017 2016 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,113,046 $ 642,528 $ 1,323,034 Sales, Net of Production Costs (381,775 ) (345,075 ) (218,444 ) Net Changes in Prices, Net of Production Costs 541,021 828,187 (1,066,593 ) Extensions and Discoveries 212,494 170,500 47,742 Changes in Estimated Future Development Costs (43,771 ) 8,816 143,752 Sales of Minerals in Place (100,816 ) (9,849 ) (95,849 ) Previously Estimated Development Costs Incurred 182,348 101,134 92,840 Net Change in Income Taxes at Applicable Statutory Rate 55,558 (393,353 ) 387,739 Revisions of Previous Quantity Estimates 61,363 39,078 6,202 Accretion of Discount and Other 80,837 71,080 22,105 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,720,305 $ 1,113,046 $ 642,528

Valuation And Qualifying Accoun

Valuation And Qualifying Accounts	12 Months Ended
	Sep. 30, 2018
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, 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 Year Ended September 30, 2016 Allowance for Uncollectible Accounts $ 29,029 $ 6,819 $ 1,521 $ 16,260 $ 21,109 (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. (3) Valuation allowance recorded to reflect the potential sequestration of estimated alternative minimum tax credit refunds as a result of the 2017 Tax Reform Act.

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Regulation	Regulation The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note C — Regulatory Matters for further discussion.
Revenue Recognition	Revenue Recognition The Company’s Exploration and Production segment records revenue based on entitlement, which means that revenue is recorded based on the actual amount of gas or oil that is delivered to a pipeline and the Company’s ownership interest in the producing well. 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 Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services. Revenue from reservation charges on firm contracted capacity is recognized through equal monthly charges over the contract period regardless of the amount of gas that is transported or stored. Commodity charges on firm contracted capacity and interruptible contracts are recognized as revenue when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage field. The point of delivery into the pipeline or injection or withdrawal from storage is the point at which ownership and risk of loss transfers to the buyer of such transportation and storage services. In the Company’s Gathering segment, revenue is recorded at the point at which gathered volumes are delivered into interstate pipelines. The Company’s Utility segment records revenue for gas sales and transportation in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of 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 Company’s Energy Marketing segment records revenue for gas sales in the period that gas is delivered to customers. This includes the recording of receivables for gas delivered but not yet billed to customers based on the Company's estimate of the amount of 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.
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 C — 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 December 31st, and applied to customer bills annually, beginning March 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. For further discussion of capitalized costs, refer to Note L — 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 natural 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, 2018, the ceiling exceeded the book value of the oil and gas properties by $569.1 million . In adjusting estimated future net cash flows for hedging under the ceiling test, estimated future net cash flows were decreased by $25.1 million at September 30, 2018 and were increased by $30.5 million and $215.3 million at September 30, 2017 and 2016 , 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 natural 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. On December 1, 2015, Seneca and IOG CRV - Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG holds an 80% working interest in all of the joint development wells. In total, IOG has funded $305.5 million as of September 30. 2018 for its 80% working interest in the 75 joint development wells, which includes $181.2 million of cash ( $137.3 million in fiscal 2016, $26.6 million in fiscal 2017 and $17.3 million in fiscal 2018) included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016, fiscal 2017 and for fiscal 2018, respectively. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. As the fee-owner of the property’s mineral rights, Seneca currently retains a 7.5% royalty interest and the remaining 20% working interest ( 26% net revenue interest) in 48 of the joint development wells. Effective June 1, 2018, actual production for 8 of the joint development wells did not meet production targets, which resulted in an adjustment to Seneca’s royalty interest from 7.5% to 4.98% with no change to the 20% working interest ( 23.98% net revenue interest). In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return. The principal assets of the Utility and Pipeline and Storage 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. 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 2018 2017 (Thousands) Exploration and Production $ 5,222,037 $ 4,925,409 Pipeline and Storage 2,110,714 2,002,736 Gathering 527,188 484,768 Utility 2,104,437 2,045,074 Energy Marketing 3,604 3,564 All Other and Corporate 108,691 109,128 $ 10,076,671 $ 9,570,679 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2018 2017 2016 Exploration and Production, per Mcfe(1) $ 0.70 $ 0.65 $ 0.87 Pipeline and Storage 2.2 % 2.2 % 2.4 % Gathering 3.4 % 3.4 % 4.0 % Utility 2.8 % 2.8 % 2.7 % Energy Marketing 7.7 % 7.9 % 7.9 % All Other and Corporate 2.2 % 1.3 % 1.8 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note L — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.67 , $0.63 and $0.85 per Mcfe of production in 2018 , 2017 and 2016 , respectively.
Goodwill	Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2018 and 2017 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, 2018 , 2017 and 2016 , 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 Unrealized gains or losses from the Company’s investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (securities available for sale) are recorded as a component of accumulated other comprehensive income (loss). Reference is made to Note G — Financial Instruments for further discussion. The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude 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 F — 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, purchased gas expense or operation and maintenance expense on the Consolidated Statements of Income. Reference is made to Note G — 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 G — 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, 2018, 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, 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 ) Year Ended September 30, 2017 Balance at October 1, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) Other Comprehensive Gains and Losses Before Reclassifications 3,338 2,503 9,486 15,327 Amounts Reclassified From Other Comprehensive Loss (47,319 ) (995 ) 8,504 (39,810 ) Balance at September 30, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) 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 and $1.2 million at September 30, 2018 and 2017, respectively. The total amount for accumulated losses was $45.6 million and $57.3 million at September 30, 2018 and 2017, respectively.
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, 2018 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 (Loss) is Presented 2018 2017 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $423 $83,983 Operating Revenues Commodity Contracts 952 (1,921 ) Purchased Gas Foreign Currency Contracts (2,564 ) (457 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale 430 1,575 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit (258 ) (288 ) (1) Net Actuarial Loss (9,446 ) (13,145 ) (1) (10,463 ) 69,747 Total Before Income Tax 1,324 (29,937 ) Income Tax Expense ($9,139 ) $39,810 Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — 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 $27.6 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 2018, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $40.2 million at September 30, 2018. All other gas stored underground, which is in the Energy Marketing segment, 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, 2018, the remaining weighted average amortization period for such costs was approximately 8 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.
Consolidated Statement Of Cash Flows	Consolidated Statement of Cash Flows For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
Hedging Collateral Deposits	Hedging Collateral Deposits This 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 instrument 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 2018 2017 (Thousands) Prepayments $ 11,126 $ 10,927 Prepaid Property and Other Taxes 14,088 13,974 Federal Income Taxes Receivable 22,457 — State Income Taxes Receivable 8,822 9,689 Fair Values of Firm Commitments 1,739 1,031 Regulatory Assets 9,792 15,884 $ 68,024 $ 51,505
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 2018 2017 (Thousands) Accrued Capital Expenditures $ 38,354 $ 37,382 Regulatory Liabilities 57,425 34,059 Federal Income Taxes Payable — 1,775 Other 36,914 38,673 $ 132,693 $ 111,889
Customer Advances	Customer Advances The Company’s Utility and Energy Marketing segments have 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, 2018 and 2017, customers in the balanced billing programs had advanced excess funds of $13.6 million and $15.7 million , respectively.
Customer Security Deposits	Customer Security Deposits The Company, in its Utility, Pipeline and Storage, and Energy Marketing 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, 2018 and 2017, the Company had received customer security deposits amounting to $25.7 million and $20.4 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 stock options, SARs, restricted stock units and performance shares. For the years ended September 30, 2018 and 2017, 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. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 317,899 securities and 157,649 securities excluded as being antidilutive for the years ended September 30, 2018 and 2017, respectively. As the Company recognized a net loss for the year ended September 30, 2016, the aforementioned potentially dilutive securities, amounting to 431,408 securities, were not recognized in the diluted earnings per share calculation for 2016.
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 non-performance 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 non-performance based restricted stock units do not entitle the participants to dividend and voting rights. The accounting for performance based and non-performance 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 E — 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	New Authoritative Accounting and Financial Reporting Guidance In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The Company adopted this authoritative guidance effective October 1, 2018 using the modified retrospective method of adoption. Detailed review of the impact of the guidance on each of the Company’s revenue streams was completed. Based on that review, the Company did not identify any changes to net income, cash flows or the timing of revenue recognition. The Company will be enhancing its financial statement disclosures to comply with the new authoritative guidance for the quarter ending December 31, 2018. 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 will be, as called for by the modified retrospective method of adoption, recording a cumulative effect adjustment for the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount. In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, requiring organizations 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 organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the provisions of the revised guidance. In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million . The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows were applied prospectively at the time of adoption. 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 new guidance will be effective as of the Company’s first quarter of fiscal 2019. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for the components of the Company's net periodic pension cost and net periodic postretirement benefit cost. 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 new guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company anticipates early adoption and is currently awaiting regulatory approval of the reclassification to retained earnings from the FERC for the Company’s Pipeline and Storage segment.

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Schedule Of Depreciable Plant By Segment	The following is a summary of depreciable plant by segment: As of September 30 2018 2017 (Thousands) Exploration and Production $ 5,222,037 $ 4,925,409 Pipeline and Storage 2,110,714 2,002,736 Gathering 527,188 484,768 Utility 2,104,437 2,045,074 Energy Marketing 3,604 3,564 All Other and Corporate 108,691 109,128 $ 10,076,671 $ 9,570,679
Average Depreciation Depletion And Amortization Rates	Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2018 2017 2016 Exploration and Production, per Mcfe(1) $ 0.70 $ 0.65 $ 0.87 Pipeline and Storage 2.2 % 2.2 % 2.4 % Gathering 3.4 % 3.4 % 4.0 % Utility 2.8 % 2.8 % 2.7 % Energy Marketing 7.7 % 7.9 % 7.9 % All Other and Corporate 2.2 % 1.3 % 1.8 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note L — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.67 , $0.63 and $0.85 per Mcfe of production in 2018 , 2017 and 2016 , respectively.
Components Of Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2018, 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, 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 ) Year Ended September 30, 2017 Balance at October 1, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) Other Comprehensive Gains and Losses Before Reclassifications 3,338 2,503 9,486 15,327 Amounts Reclassified From Other Comprehensive Loss (47,319 ) (995 ) 8,504 (39,810 ) Balance at September 30, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 )
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, 2018 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 (Loss) is Presented 2018 2017 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $423 $83,983 Operating Revenues Commodity Contracts 952 (1,921 ) Purchased Gas Foreign Currency Contracts (2,564 ) (457 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale 430 1,575 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit (258 ) (288 ) (1) Net Actuarial Loss (9,446 ) (13,145 ) (1) (10,463 ) 69,747 Total Before Income Tax 1,324 (29,937 ) Income Tax Expense ($9,139 ) $39,810 Net of Tax (1) These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details.
Schedule Of Other Current Assets	The components of the Company’s Other Current Assets are as follows: Year Ended September 30 2018 2017 (Thousands) Prepayments $ 11,126 $ 10,927 Prepaid Property and Other Taxes 14,088 13,974 Federal Income Taxes Receivable 22,457 — State Income Taxes Receivable 8,822 9,689 Fair Values of Firm Commitments 1,739 1,031 Regulatory Assets 9,792 15,884 $ 68,024 $ 51,505
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 2018 2017 (Thousands) Accrued Capital Expenditures $ 38,354 $ 37,382 Regulatory Liabilities 57,425 34,059 Federal Income Taxes Payable — 1,775 Other 36,914 38,673 $ 132,693 $ 111,889

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Sep. 30, 2018
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 2018 2017 2016 (Thousands) Balance at Beginning of Year $ 106,395 $ 112,330 $ 156,805 Liabilities Incurred 5,597 2,963 2,719 Revisions of Estimates (419 ) (10,578 ) 16,721 Liabilities Settled (12,858 ) (4,967 ) (72,215 ) Accretion Expense 9,520 6,647 8,300 Balance at End of Year $ 108,235 $ 106,395 $ 112,330

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2018
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 2018 2017 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note H) $ 62,703 $ 125,175 Post-Retirement Benefit Costs(2) (Note H) 11,160 13,886 Recoverable Future Taxes (Note D) 115,460 181,363 Environmental Site Remediation Costs(2) (Note I) 20,308 19,665 Asset Retirement Obligations(2) (Note B) 15,495 12,764 Unamortized Debt Expense (Note A) 15,975 1,159 Other(3) 13,044 18,827 Total Regulatory Assets 254,145 372,839 Less: Amounts Included in Other Current Assets (9,792 ) (15,884 ) Total Long-Term Regulatory Assets $ 244,353 $ 356,955 At September 30 2018 2017 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 212,311 $ 204,630 Taxes Refundable to Customers (Note D) 370,628 95,739 Post-Retirement Benefit Costs (Note H) 134,387 102,891 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 3,394 — Other(4) 69,781 44,884 Total Regulatory Liabilities 790,501 448,144 Less: Amounts included in Current and Accrued Liabilities (60,819 ) (34,059 ) Total Long-Term Regulatory Liabilities $ 729,682 $ 414,085 (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) $9,792 and $15,884 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,252 and $2,943 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively. (4) $57,425 and $34,059 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $12,356 and $10,825 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2018
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 2018 2017 2016 (Thousands) Current Income Taxes — Federal $ 2,025 $ 32,034 $ (6,658 ) State 8,634 10,673 20,903 Deferred Income Taxes — Federal (38,927 ) 103,046 (164,818 ) State 20,774 14,929 (81,976 ) (7,494 ) 160,682 (232,549 ) Deferred Investment Tax Credit (105 ) (173 ) (348 ) Total Income Taxes $ (7,599 ) $ 160,509 $ (232,897 ) Presented as Follows: Other Income $ (105 ) $ (173 ) $ (348 ) Income Tax Expense (Benefit) (7,494 ) 160,682 (232,549 ) Total Income Taxes $ (7,599 ) $ 160,509 $ (232,897 )
Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate	The following is a reconciliation of this difference: Year Ended September 30 2018 2017 2016 (Thousands) U.S. Income (Loss) Before Income Taxes $ 383,922 $ 443,991 $ (523,855 ) Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate(1) $ 94,061 $ 155,397 $ (183,349 ) Impact of 2017 Tax Reform Act(2) (112,598 ) — — State Income Taxes (Benefit)(3) 22,203 16,641 (39,697 ) Federal Tax Credits (6,576 ) (6,679 ) (3,262 ) Miscellaneous (4,689 ) (4,850 ) (6,589 ) Total Income Taxes $ (7,599 ) $ 160,509 $ (232,897 ) (1) For fiscal 2018, represents the blended rate of 24.5% . Calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters. (2) 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 described above. (3) The state income taxes (benefit) shown above includes income tax benefits related to state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes.
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 2018 2017 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 770,794 $ 1,141,432 Pension and Other Post-Retirement Benefit Costs 39,541 79,516 Other 49,734 77,046 Total Deferred Tax Liabilities 860,069 1,297,994 Deferred Tax Assets: Pension and Other Post-Retirement Benefit Costs (62,969 ) (123,532 ) Tax Loss and Credit Carryforwards (214,128 ) (200,344 ) Other (75,286 ) (82,831 ) Total Gross Deferred Tax Assets (352,383 ) (406,707 ) Valuation Allowance 5,000 — Total Deferred Tax Assets (347,383 ) (406,707 ) Total Net Deferred Income Taxes $ 512,686 $ 891,287
Reconciliation Of The Change In Unrecognized Tax Benefits	The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2018 2017 2016 (Thousands) Balance at Beginning of Year $ 1,251 $ 396 $ 5,085 Additions for Tax Positions of Prior Years — 1,251 396 Reductions for Tax Positions of Prior Years (788 ) (396 ) (1,314 ) Reductions Related to Settlements with Taxing Authorities (463 ) — (3,771 ) Balance at End of Year $ — $ 1,251 $ 396
Summary of Operating Loss and Tax Credit Carryforwards	As of September 30, 2018, the Company has the following carryforwards available: Jurisdiction Tax Attribute Amount (Thousands) Expires Federal Pre-Fiscal 2018 Net Operating Loss $ 191,006 (1) 2029-2037 Federal Post-Fiscal 2017 Net Operating Loss 58,334 Unlimited Pennsylvania Net Operating Loss 351,879 2029-2038 California Net Operating Loss 191,468 2029-2038 Federal Alternative Minimum Tax Credit 84,185 (2) Unlimited California Alternative Minimum Tax Credit 6,983 Unlimited Federal Enhanced Oil Recovery Credit 18,160 2029-2038 California Enhanced Oil Recovery Credit 7,613 2019-2033 Federal R&D Tax Credit 5,876 2031-2037 Federal Charitable Contributions 3,067 2023 (1) Approximately $1.8 million of the federal Net Operating Loss carryforward is subject to certain annual limitations. (2) The $5.0 million estimate recorded for the potential sequestration of AMT credit refunds is not included in this amount.

Capitalization And Short-Term_2

Capitalization And Short-Term Borrowings (Tables)	12 Months Ended
	Sep. 30, 2018
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, 2015 84,594 $ 84,594 $ 744,274 $ 1,103,200 $ 93,372 Net Income (Loss) Available for Common Stock (290,958 ) Dividends Declared on Common Stock ($1.60 Per Share) (135,881 ) Other Comprehensive Loss, Net of Tax (99,012 ) Share-Based Payment Expense(2) 4,843 Common Stock Issued Under Stock and Benefit Plans(1) 525 525 22,047 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(2) 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(2) 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 (3) $ (67,750 ) (1) Paid in Capital includes tax benefits of $1.9 million for September 30, 2016, related to stock-based compensation. (2) 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. (3) 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, 2018, $954.7 million of accumulated earnings was free of such limitations.
Schedule Of Share-Based Compensation For SARs	Transactions for 2018 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, 2017 1,505,911 $ 48.64 Granted in 2018 — $ — Exercised in 2018 (206,823 ) $ 35.70 Forfeited in 2018 — $ — Expired in 2018 — $ — Outstanding at September 30, 2018 1,299,088 $ 50.70 1.77 $ 8,199 SARs exercisable at September 30, 2018 1,299,088 $ 50.70 1.77 $ 8,199 Shares available for future grant at September 30, 2018(1) 1,478,086 (1) Includes shares available for options, SARs, restricted stock and performance share grants.
Schedule Of Share-Based Compensation For Restricted Share Awards	Transactions for 2018 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, 2017 20,000 $ 47.46 Granted in 2018 — $ — Vested in 2018 — $ — Forfeited in 2018 — $ — Outstanding at September 30, 2018 20,000 $ 47.46
Schedule Of Share-Based Compensation For Non-Performance Based Restricted Stock Units	Transactions for 2018 involving non-performance 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, 2017 233,199 $ 48.99 Granted in 2018 89,672 $ 51.23 Vested in 2018 (72,918 ) $ 53.73 Forfeited in 2018 (4,637 ) $ 46.04 Outstanding at September 30, 2018 245,316 $ 48.45
Schedule of Share-based Compensation for Performance Shares	Transactions for 2018 involving performance shares for all plans are summarized as follows: Number of Performance Shares Weighted Average Fair Value per Award Outstanding at September 30, 2017 527,748 $ 45.44 Granted in 2018 208,588 $ 50.95 Vested in 2018 (79,079 ) $ 65.38 Forfeited in 2018 (15,967 ) $ 57.15 Outstanding at September 30, 2018 641,290 $ 44.49
Schedule Of Long-Term Debt	The outstanding long-term debt is as follows: At September 30 2018 2017 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(3)(4): 3.75% to 5.20% due December 2021 to September 2028 2,050,000 2,300,000 Total Long-Term Debt 2,149,000 2,399,000 Less Unamortized Discount and Debt Issuance Costs 17,635 15,319 Less Current Portion(2) — 300,000 $ 2,131,365 $ 2,083,681 (1) The Medium-Term Notes and Notes are unsecured. (2) Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes that were scheduled to mature in April 2018. The Company redeemed those notes on October 18, 2017 for $307.0 million , plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017. (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% , 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).
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 2018 2017 2016 Risk-Free Interest Rate 1.96 % 1.54 % 1.26 % Remaining Term at Date of Grant (Years) 2.78 2.79 2.79 Expected Volatility 22.0 % 22.6 % 20.5 % Expected Dividend Yield (Quarterly) N/A N/A N/A

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2018
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, 2018 and 2017. 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, 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 At Fair Value as of September 30, 2017 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 $ 527,978 $ — $ — $ — $ 527,978 Derivative Financial Instruments: Commodity Futures Contracts — Gas 1,483 — — (963 ) 520 Over the Counter Swaps — Gas and Oil — 38,977 — (4,206 ) 34,771 Foreign Currency Contracts — 1,227 — (407 ) 820 Other Investments: Balanced Equity Mutual Fund 37,033 — — — 37,033 Fixed Income Mutual Fund 45,727 — — — 45,727 Common Stock — Financial Services Industry 3,150 — — — 3,150 Hedging Collateral Deposits 1,741 — — — 1,741 Total $ 617,112 $ 40,204 $ — $ (5,576 ) $ 651,740 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 963 $ — $ — $ (963 ) $ — Over the Counter Swaps — Gas and Oil — 5,309 — (4,206 ) 1,103 Foreign Currency Contracts — 407 — (407 ) — Total $ 963 $ 5,716 $ — $ (5,576 ) $ 1,103 Total Net Assets/(Liabilities) $ 616,149 $ 34,488 $ — $ — $ 650,637 (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, 2018
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 2018 Carrying Amount 2018 Fair Value 2017 Carrying 2017 Fair (Thousands) Long-Term Debt $ 2,131,365 $ 2,121,861 $ 2,383,681 $ 2,523,639
Schedule of Other Investments	The components of the Company's Other Investments are as follows (in thousands): At September 30 2018 2017 (Thousands) Life Insurance Contracts $ 39,970 $ 39,355 Equity Mutual Fund 38,468 37,033 Fixed Income Mutual Fund 51,331 45,727 Marketable Equity Securities 2,776 3,150 $ 132,545 $ 125,265
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, 2018 and 2017 (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, 2018 2017 2018 2017 2018 2017 Commodity Contracts $ (70,905 ) $ 2,811 Operating Revenue $ 423 $ 83,983 Operating Revenue $ (782 ) $ (100 ) Commodity Contracts 701 (164 ) Purchased Gas 952 (1,921 ) Not Applicable — — Foreign Currency Contracts (3,899 ) 2,700 Operation and Maintenance Expense (2,564 ) (457 ) Not Applicable — — Total $ (74,103 ) $ 5,347 $ (1,189 ) $ 81,605 $ (782 ) $ (100 )
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, 2018 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2018 (In thousands) Commodity Contracts Operating Revenues $ (1,289 ) $ 1,289 Commodity Contracts Purchased Gas (238 ) 238 $ (1,527 ) $ 1,527

Retirement Plan And Other Pos_2

Retirement Plan And Other Post-Retirement Benefits (Tables)	12 Months Ended
	Sep. 30, 2018
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 2018 , 2017 and 2016 . Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2018 2017 2016 2018 2017 2016 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 1,054,826 $ 1,097,421 $ 1,026,190 $ 462,619 $ 526,138 $ 464,987 Service Cost 9,921 11,969 11,710 1,830 2,449 2,331 Interest Cost 33,006 38,383 42,315 14,801 19,007 20,386 Plan Participants’ Contributions — — — 2,894 2,717 2,558 Retiree Drug Subsidy Receipts — — — 1,545 1,553 1,925 Actuarial (Gain) Loss (50,218 ) (32,466 ) 76,309 (21,039 ) (62,215 ) 60,402 Benefits Paid (61,845 ) (60,481 ) (59,103 ) (26,664 ) (27,030 ) (26,451 ) Benefit Obligation at End of Period $ 985,690 $ 1,054,826 $ 1,097,421 $ 435,986 $ 462,619 $ 526,138 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 910,719 $ 869,775 $ 834,870 $ 514,017 $ 494,320 $ 477,959 Actual Return on Plan Assets 42,652 84,279 87,008 20,657 40,157 37,415 Employer Contributions 32,980 17,146 7,000 2,896 3,853 2,839 Plan Participants’ Contributions — — — 2,894 2,717 2,558 Benefits Paid (61,845 ) (60,481 ) (59,103 ) (26,664 ) (27,030 ) (26,451 ) Fair Value of Assets at End of Period $ 924,506 $ 910,719 $ 869,775 $ 513,800 $ 514,017 $ 494,320 Net Amount Recognized at End of Period (Funded Status) $ (61,184 ) $ (144,107 ) $ (227,646 ) $ 77,814 $ 51,398 $ (31,818 ) Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (61,184 ) $ (144,107 ) $ (227,646 ) $ (4,919 ) $ (4,972 ) $ (49,467 ) Non-Current Assets — — — 82,733 56,370 17,649 Net Amount Recognized at End of Period $ (61,184 ) $ (144,107 ) $ (227,646 ) $ 77,814 $ 51,398 $ (31,818 ) Accumulated Benefit Obligation $ 946,763 $ 1,010,179 $ 1,039,408 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 4.30 % 3.77 % 3.60 % 4.31 % 3.81 % 3.70 % 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 2018 2017 2016 2018 2017 2016 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 9,921 $ 11,969 $ 11,710 $ 1,830 $ 2,449 $ 2,331 Interest Cost 33,006 38,383 42,315 14,801 19,007 20,386 Expected Return on Plan Assets (61,715 ) (59,718 ) (59,369 ) (31,482 ) (31,458 ) (31,535 ) Amortization of Prior Service Cost (Credit) 938 1,058 1,234 (429 ) (429 ) (912 ) Recognition of Actuarial Loss(1) 37,205 42,687 32,248 10,558 18,415 5,530 Net Amortization and Deferral for Regulatory Purposes 9,027 469 3,957 15,028 6,108 17,123 Net Periodic Benefit Cost $ 28,382 $ 34,848 $ 32,095 $ 10,306 $ 14,092 $ 12,923 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Effective Discount Rate for Benefit Obligations 3.77 % 3.60 % 4.25 % 3.81 % 3.70 % 4.50 % Effective Rate for Interest on Benefit Obligations 3.23 % 3.60 % 4.25 % 3.29 % 3.70 % 4.50 % Effective Discount Rate for Service Cost 4.00 % 3.60 % 4.25 % 4.10 % 3.70 % 4.50 % Effective Rate for Interest on Service Cost 3.73 % 3.60 % 4.25 % 3.98 % 3.70 % 4.50 % Expected Return on Plan Assets 7.00 % 7.00 % 7.25 % 6.25 % 6.50 % 6.75 % Rate of Compensation Increase 4.70 % 4.70 % 4.75 % 4.70 % 4.70 % 4.75 % (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 2018 , the changes in such amounts during 2018 , as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2019 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 Gain (Loss) $ (135,527 ) $ 1,193 $ (22,818 ) Prior Service (Cost) Credit (5,195 ) 3,258 — Net Amount Recognized $ (140,722 ) $ 4,451 $ (22,818 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2018(1) Decrease (Increase) in Actuarial Loss, excluding amortization(2) $ 31,155 $ 10,213 $ (2,035 ) Change due to Amortization of Actuarial Loss 37,205 10,558 3,549 Prior Service (Cost) Credit 938 (429 ) — Net Change $ 69,298 $ 20,342 $ 1,514 Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (32,096 ) $ (5,962 ) $ (3,558 ) Prior Service (Cost) Credit (826 ) 429 — Net Amount Expected to be Recognized $ (32,922 ) $ (5,533 ) $ (3,558 ) (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 2019 $ 27,821 $ (1,858 ) 2020 $ 28,692 $ (1,996 ) 2021 $ 29,455 $ (2,128 ) 2022 $ 29,979 $ (2,260 ) 2023 $ 30,426 $ (2,386 ) 2024 through 2028 $ 153,855 $ (13,325 )
Schedule Of Health Care Cost Trend Rates	Assumed health care cost trend rates as of September 30 were: 2018 2017 2016 Rate of Medical Cost Increase for Pre Age 65 Participants 5.59 % (1) 5.67 % (1) 5.75 % (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 7.89 % (1) 8.45 % (1) 9.00 % (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 7.18 % (1) 7.33 % (1) 7.20 % (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	Total Fair Value Amounts at September 30, 2018 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 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) Retirement Plan Investments Domestic Equities(1) $ 290,716 $ 209,421 $ — $ — $ 81,295 International Equities(2) 123,069 — — — 123,069 Global Equities(3) 121,008 — — — 121,008 Domestic Fixed Income(4) 348,501 1,664 346,837 — — International Fixed Income(5) 422 422 — — — Global Fixed Income(6) 75,428 — — — 75,428 Real Estate 3,391 — — 3,391 — Cash Held in Collective Trust Funds 26,058 — — — 26,058 Total Retirement Plan Investments 988,593 211,507 346,837 3,391 426,858 401(h) Investments (64,728 ) (14,026 ) (23,001 ) (225 ) (27,476 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 923,865 $ 197,481 $ 323,836 $ 3,166 $ 399,382 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (13,146 ) Total Retirement Plan Assets $ 910,719 (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 an exchange traded fund. (6) Global Fixed Income securities are comprised of a collective trust fund. (7) Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.
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, 2016 $ 2,970 $ (188 ) $ 2,782 Unrealized Gains/(Losses) 421 (37 ) 384 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
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule Of Fair Value Of Plan Assets	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 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 $ 130,864 $ — $ — $ — $ 130,864 Collective Trust Funds — International Equities 52,063 — — — 52,063 Exchange Traded Funds — Fixed Income 256,099 256,099 — — — Cash Held in Collective Trust Funds 9,569 — — — 9,569 Total VEBA Trust Investments 448,595 256,099 — — 192,496 401(h) Investments 64,728 14,026 23,001 225 27,476 Total Investments (including 401(h) Investments) $ 513,323 $ 270,125 $ 23,001 $ 225 $ 219,972 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 694 Total Other Post-Retirement Benefit Assets $ 514,017 (1) Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.
Schedule Of Significant Unobservable Input Changes In Plan Assets	Other Post-Retirement Benefit Level 3 Assets (Thousands) 401(h) Investments Balance at September 30, 2016 $ 188 Unrealized Gains/(Losses) 37 Balance at September 30, 2017 225 Unrealized Gains/(Losses) 19 Sales (26 ) Balance at September 30, 2018 $ 218

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment Information By Segment	Year Ended September 30, 2018 Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 564,547 $ 210,345 $ 41 $ 674,726 $ 137,748 $ 1,587,407 $ 4,601 $ 660 $ 1,592,668 Intersegment Revenues $ — $ 89,981 $ 107,856 $ 12,800 $ 826 $ 211,463 $ — $ (211,463 ) $ — Interest Income $ 1,479 $ 2,748 $ 1,106 $ 1,591 $ 685 $ 7,609 $ 388 $ (1,231 ) $ 6,766 Interest Expense $ 54,288 $ 31,383 $ 9,560 $ 26,753 $ 22 $ 122,006 $ — $ (7,484 ) $ 114,522 Depreciation, Depletion and Amortization $ 124,274 $ 43,463 $ 17,313 $ 53,253 $ 275 $ 238,578 $ 1,627 $ 756 $ 240,961 Income Tax Expense (Benefit) $ (41,962 ) $ 17,806 $ (17,677 ) $ 15,258 $ 632 $ (25,943 ) $ 1,493 $ 16,956 $ (7,494 ) Segment Profit: Net Income (Loss) $ 180,632 $ 97,246 $ 83,519 $ 51,217 $ 373 $ 412,987 $ (112 ) $ (21,354 ) $ 391,521 Expenditures for Additions to Long-Lived Assets $ 380,677 $ 92,832 $ 61,728 $ 85,648 $ 40 $ 620,925 $ 1 $ (20,324 ) $ 600,602 At September 30, 2018 (Thousands) Segment Assets $ 1,568,563 $ 1,848,180 $ 533,608 $ 1,921,971 $ 50,971 $ 5,923,293 $ 78,109 $ 35,084 $ 6,036,486 Year Ended September 30, 2017 Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Elimination Total Consolidated (Thousands) Revenue from External Customers(1) $ 614,599 $ 206,615 $ 115 $ 626,899 $ 128,586 $ 1,576,814 $ 2,173 $ 894 $ 1,579,881 Intersegment Revenues $ — $ 87,810 $ 107,566 $ 13,072 $ 794 $ 209,242 $ — $ (209,242 ) $ — Interest Income $ 707 $ 1,467 $ 994 $ 1,051 $ 571 $ 4,790 $ 213 $ (890 ) $ 4,113 Interest Expense $ 53,702 $ 33,717 $ 9,142 $ 28,492 $ 47 $ 125,100 $ — $ (5,263 ) $ 119,837 Depreciation, Depletion and Amortization $ 112,565 $ 41,196 $ 16,162 $ 52,582 $ 279 $ 222,784 $ 661 $ 750 $ 224,195 Income Tax Expense (Benefit) $ 66,093 $ 40,947 $ 29,694 $ 24,894 $ 891 $ 162,519 $ (247 ) $ (1,590 ) $ 160,682 Segment Profit: Net Income (Loss) $ 129,326 $ 68,446 $ 40,377 $ 46,935 $ 1,509 $ 286,593 $ (342 ) $ (2,769 ) $ 283,482 Expenditures for Additions to Long-Lived Assets $ 253,057 $ 95,336 $ 32,645 $ 80,867 $ 36 $ 461,941 $ 39 $ 137 $ 462,117 At September 30, 2017 (Thousands) Segment Assets $ 1,407,152 $ 1,929,788 $ 580,051 $ 2,013,123 $ 60,937 $ 5,991,051 $ 76,861 $ 35,408 $ 6,103,320 Year Ended September 30, 2016 Exploration Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated (Thousands) Revenue from External Customers(1) $ 607,113 $ 215,674 $ 374 $ 531,024 $ 93,578 $ 1,447,763 $ 3,753 $ 900 $ 1,452,416 Intersegment Revenues $ — $ 90,755 $ 89,073 $ 13,123 $ 884 $ 193,835 $ — $ (193,835 ) $ — Interest Income $ 858 $ 770 $ 297 $ 1,737 $ 422 $ 4,084 $ 117 $ 34 $ 4,235 Interest Expense $ 55,434 $ 33,327 $ 8,872 $ 27,582 $ 49 $ 125,264 $ — $ (4,220 ) $ 121,044 Depreciation, Depletion and Amortization $ 139,963 $ 43,273 $ 15,282 $ 48,618 $ 278 $ 247,414 $ 1,260 $ 743 $ 249,417 Income Tax Expense (Benefit) $ (334,029 ) $ 50,241 $ 24,334 $ 25,602 $ 2,460 $ (231,392 ) $ 561 $ (1,718 ) $ (232,549 ) Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ 948,307 $ — $ — $ — $ — $ 948,307 $ — $ — $ 948,307 Segment Profit: Net Income (Loss) $ (452,842 ) $ 76,610 $ 30,499 $ 50,960 $ 4,348 $ (290,425 ) $ 778 $ (1,311 ) $ (290,958 ) Expenditures for Additions to Long-Lived Assets $ 256,104 $ 114,250 $ 54,293 $ 98,007 $ 34 $ 522,688 $ 37 $ 326 $ 523,051 At September 30, 2016 (Thousands) Segment Assets $ 1,323,081 $ 1,680,734 $ 534,259 $ 2,021,514 $ 63,392 $ 5,622,980 $ 77,138 $ (63,731 ) $ 5,636,387 (1) All Revenue from External Customers originated in the United States.
Schedule Of Long-Lived Assets, By Geographical Areas	Geographic Information At September 30 2018 2017 2016 (Thousands) Long-Lived Assets: United States $ 5,491,895 $ 5,285,040 $ 5,223,356

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Sep. 30, 2018
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) 2018 9/30/2018 $ 289,196 $ 80,629 $ 37,995 (1) $ 0.44 $ 0.44 6/30/2018 $ 342,912 $ 107,760 $ 63,025 $ 0.73 $ 0.73 3/31/2018 $ 540,905 $ 156,702 $ 91,847 (2) $ 1.07 $ 1.06 12/31/2017 $ 419,655 $ 141,995 $ 198,654 (3) $ 2.32 $ 2.30 2017 9/30/2017 $ 286,937 $ 87,395 $ 45,577 $ 0.53 $ 0.53 6/30/2017 $ 348,369 $ 123,354 $ 59,714 $ 0.70 $ 0.69 3/31/2017 $ 522,075 $ 169,957 $ 89,283 $ 1.05 $ 1.04 12/31/2016 $ 422,500 $ 172,139 $ 88,908 $ 1.04 $ 1.04 (1) 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. (2) 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. (3) Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.

Supplementary Information For_2

Supplementary Information For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Sep. 30, 2018
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 2018 2017 (Thousands) Proved Properties(1) $ 5,114,753 $ 4,832,301 Unproved Properties 62,234 80,932 5,176,987 4,913,233 Less — Accumulated Depreciation, Depletion and Amortization 3,862,687 3,765,710 $ 1,314,300 $ 1,147,523 (1) Includes asset retirement costs of $44.3 million and $54.4 million at September 30, 2018 and 2017, respectively.
Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization	Following is a summary of costs excluded from amortization at September 30, 2018: Total as of September 30, 2018 Year Costs Incurred 2018 2017 2016 Prior (Thousands) Acquisition Costs $ 39,681 $ — $ — $ — $ 39,681 Development Costs 14,824 11,115 236 2,886 587 Exploration Costs 7,606 — 32 7,574 — Capitalized Interest 123 20 — 103 — $ 62,234 $ 11,135 $ 268 $ 10,563 $ 40,268
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 2018 2017 2016 (Thousands) United States Property Acquisition Costs: Proved $ 1,544 $ 8,908 $ 1,342 Unproved 4,286 262 2,165 Exploration Costs(1) 29,365 40,975 27,561 Development Costs(2) 332,496 200,639 219,386 Asset Retirement Costs (10,107 ) (9,175 ) (49,653 ) $ 357,584 $ 241,609 $ 200,801 (1) Amounts for 2018, 2017 and 2016 include capitalized interest of zero , $0.3 million and $0.3 million , respectively. (2) Amounts for 2018, 2017 and 2016 include capitalized interest of $0.3 million , $0.2 million and $0.2 million , respectively.
Results Of Operations For Producing Activities	Results of Operations for Producing Activities Year Ended September 30 2018 2017 2016 United States (Thousands, except per Mcfe amounts) Operating Revenues: Natural Gas (includes transfers to operations of $2,134, $2,357 and $1,765, respectively)(1) $ 390,642 $ 399,975 $ 282,619 Oil, Condensate and Other Liquids 168,254 126,517 103,533 Total Operating Revenues(2) 558,896 526,492 386,152 Production/Lifting Costs 162,721 165,991 153,914 Franchise/Ad Valorem Taxes 14,355 15,372 13,794 Purchased Emission Allowance Expense 1,883 1,391 700 Accretion Expense 4,266 4,896 6,663 Depreciation, Depletion and Amortization ($0.67, $0.63 and $0.85 per Mcfe of production, respectively) 119,946 108,471 136,579 Impairment of Oil and Gas Producing Properties — — 948,307 Income Tax Expense (Benefit) 72,723 86,657 (368,940 ) Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 183,002 $ 143,714 $ (504,865 ) (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 G — 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, 2015 2,092,782 49,346 2,142,128 Extensions and Discoveries 185,347 (1) — 185,347 Revisions of Previous Estimates (245,029 ) (3,132 ) (248,161 ) Production (140,457 ) (2) (3,090 ) (143,547 ) Sale of Minerals in Place (261,192 ) — (261,192 ) 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 Proved Developed Reserves: September 30, 2015 1,267,498 49,346 1,316,844 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 Proved Undeveloped Reserves: September 30, 2015 825,284 — 825,284 September 30, 2016 541,959 — 541,959 September 30, 2017 610,018 — 610,018 September 30, 2018 750,810 — 750,810 (1) Extensions and discoveries include 179 Bcf (during 2016), 181 Bcf (during 2017) and 274 Bcf (during 2018), of Marcellus Shale gas in the Appalachian region. Extensions and discoveries include 6 Bcf (during 2016), 205 Bcf (during 2017) and 248 Bcf (during 2018), of Utica Shale gas in the Appalachian region. (2) Production includes 135,598 MMcf (during 2016), 145,452 MMcf (during 2017) and 150,196 MMcf (during 2018), from Marcellus Shale fields (which exceed 15% of total reserves). Production includes 9,409 MMcf (during 2018), from Utica Shale fields (which exceed 15% of total reserves). Oil Mbbl U.S. Appalachian Region West Coast Region Total Company Proved Developed and Undeveloped Reserves: September 30, 2015 220 33,502 33,722 Extensions and Discoveries — 530 530 Revisions of Previous Estimates (46 ) (2,201 ) (2,247 ) Production (28 ) (2,895 ) (2,923 ) Sales of Minerals in Place (73 ) — (73 ) 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 Proved Developed Reserves: September 30, 2015 220 33,150 33,370 September 30, 2016 73 28,698 28,771 September 30, 2017 28 29,771 29,799 September 30, 2018 14 26,689 26,703 Proved Undeveloped Reserves: September 30, 2015 — 352 352 September 30, 2016 — 238 238 September 30, 2017 — 408 408 September 30, 2018 — 960 960
Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Year Ended September 30 2018 2017 2016 (Thousands) United States Future Cash Inflows $ 7,822,855 $ 6,144,317 $ 3,768,463 Less: Future Production Costs 2,606,411 2,378,262 1,994,916 Future Development Costs 559,707 411,578 375,152 Future Income Tax Expense at Applicable Statutory Rate 1,125,910 1,160,469 303,397 Future Net Cash Flows 3,530,827 2,194,008 1,094,998 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,810,522 1,080,962 452,470 Standardized Measure of Discounted Future Net Cash Flows $ 1,720,305 $ 1,113,046 $ 642,528
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 2018 2017 2016 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 1,113,046 $ 642,528 $ 1,323,034 Sales, Net of Production Costs (381,775 ) (345,075 ) (218,444 ) Net Changes in Prices, Net of Production Costs 541,021 828,187 (1,066,593 ) Extensions and Discoveries 212,494 170,500 47,742 Changes in Estimated Future Development Costs (43,771 ) 8,816 143,752 Sales of Minerals in Place (100,816 ) (9,849 ) (95,849 ) Previously Estimated Development Costs Incurred 182,348 101,134 92,840 Net Change in Income Taxes at Applicable Statutory Rate 55,558 (393,353 ) 387,739 Revisions of Previous Quantity Estimates 61,363 39,078 6,202 Accretion of Discount and Other 80,837 71,080 22,105 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,720,305 $ 1,113,046 $ 642,528

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, 2018	Sep. 30, 2017	Sep. 30, 2016	Oct. 01, 2018	Jun. 01, 2018	Jun. 13, 2016
Summary Of Significant Accounting Policies [Line Items]
Full cost ceiling test discount factor		10.00%
Amount full cost ceiling exceeds book value of oil and gas properties		$ 569,100
Increase (decrease) estimated future net cash flows		(25,100)	$ 30,500	$ 215,300
Net Proceeds from Sale of Oil and Gas Producing Properties		55,506	26,554	$ 137,316
Goodwill		5,476	5,476
Prior service cost		(1,000)	(1,200)
Gas stored underground		37,813	35,689
Customer Advances		13,609	15,701
Customer Security Deposits		$ 25,703	$ 20,372
Antidilutive securities		317,899	157,649	431,408
Impairment of Oil and Gas Producing Properties		$ 0	$ 0	$ 948,307
Receivable from Sale of Oil and Gas Producing Properties		0	0	19,543
Amount Exceeds LIFO Basis [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground		40,200
LIFO Method [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground		27,600
Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Net Proceeds from Sale of Oil and Gas Producing Properties		181,200
Net Proceeds from Sale of Oil and Gas Producing Properties		17,300	26,600	$ 137,300
IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working Interest In Joint Wells							80.00%
Internal Rate of Return							15.00%
Accumulated Losses [Member]
Summary Of Significant Accounting Policies [Line Items]
Accumulated losses		$ 45,600	57,300
Unamortized Debt Expense [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulated Reacquisition of Debt Cost Weighted Average Amortization Period		8 years
26 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed							48
23.98 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed						8
After Achieved Internal Rate of Return [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working Interest In Joint Wells							85.00%
Extended Agreement [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working Interest In Joint Wells							20.00%
Partner Net Revenue Interest in Joint Wells Production Not Met						23.98%
Royalty Interest							7.50%
Royalty Interest Production Not Met						4.98%
Partner Net Revenue Interest in Joint Wells							26.00%
Partner Working and Net Revenue Interest In Joint Wells							20.00%
Extended Agreement [Member] | IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed							75
Partner Amount Funded to Develop Joint Wells		$ 305,500
20 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed							19
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 Recognition and Measurement of Financial Assets and Liabilities [Member] | Scenario, Forecast [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance					$ 7,400
Guidance for Stock Based Compensation [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance			$ 31,900

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Schedule Of Depreciable Plant By Segment) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Depreciable plant	$ 10,076,671	$ 9,570,679
Utility [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,104,437	2,045,074
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,110,714	2,002,736
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciable plant	5,222,037	4,925,409
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Depreciable plant	3,604	3,564
Gathering [Member]
Segment Reporting Information [Line Items]
Depreciable plant	527,188	484,768
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Depreciable plant	$ 108,691	$ 109,128

Summary Of Significant Accoun_6

Summary Of Significant Accounting Policies (Average Depreciation Depletion And Amortization Rates) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe	[1]	$ 0.70	$ 0.65	$ 0.87
Utility [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.80%	2.80%	2.70%
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.20%	2.20%	2.40%
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		7.70%	7.90%	7.90%
Gathering [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		3.40%	3.40%	4.00%
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.20%	1.30%	1.80%
Oil And Gas Producing Properties [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe		$ 0.67	$ 0.63	$ 0.85
[1]	Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note L — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.67, $0.63 and $0.85 per Mcfe of production in 2018, 2017 and 2016, 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, 2018	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ (30,123)	$ (5,640)
Other Comprehensive Gains and Losses Before Reclassifications	(46,766)	15,327
Amounts Reclassified From Other Comprehensive Loss	9,139	(39,810)
Ending balance	(67,750)	(30,123)
Gains and Losses on Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	20,801	64,782
Other Comprehensive Gains and Losses Before Reclassifications	(51,556)	3,338
Amounts Reclassified From Other Comprehensive Loss	2,144	(47,319)
Ending balance	(28,611)	20,801
Gains and Losses on Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	7,562	6,054
Other Comprehensive Gains and Losses Before Reclassifications	147	2,503
Amounts Reclassified From Other Comprehensive Loss	(272)	(995)
Ending balance	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	(58,486)	(76,476)
Other Comprehensive Gains and Losses Before Reclassifications	4,643	9,486
Amounts Reclassified From Other Comprehensive Loss	7,267	8,504
Ending balance	$ (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, 2018		Jun. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ 289,196		$ 342,912	$ 540,905		$ 419,655		$ 286,937	$ 348,369	$ 522,075	$ 422,500	$ 1,592,668	$ 1,579,881	$ 1,452,416
Other Income													4,697	7,043	9,820
Income Before Income Taxes													384,027	444,164	(523,507)
Income Tax Expense													7,494	(160,682)	232,549
Net Income (Loss) Available for Common Stock		$ 37,995	[1]	$ 63,025	$ 91,847	[2]	$ 198,654	[3]	$ 45,577	$ 59,714	$ 89,283	$ 88,908	391,521	283,482	(290,958)
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													(10,463)	69,747
Income Tax Expense													1,324	(29,937)
Net Income (Loss) Available for Common Stock													(9,139)	39,810
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													430	1,575
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 Credit	[4]												(258)	(288)
Recognition of Net Actuarial Loss	[4]												(9,446)	(13,145)
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													423	83,983
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]
Operation and Maintenance													(2,564)	(457)
Purchased Gas [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Purchased Gas													337,822	275,254	$ 147,982
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													$ 952	$ (1,921)
[1]	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.
[2]	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.
[3]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[4]	These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note H — Retirement Plan and Other Post-Retirement Benefits for additional details.

Summary Of Significant Accoun_9

Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017
Summary Of Significant Accounting Policies [Line Items]
Prepayments		$ 11,126	$ 10,927
Prepaid Property and Other Taxes		14,088	13,974
Fair Values of Firm Commitments		1,739	1,031
Regulatory Assets	[1]	9,792	15,884
Other Current Assets		68,024	51,505
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		22,457	0
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		$ 8,822	$ 9,689
[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_10

Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liability	$ 60,819	$ 34,059
Other Accruals and Current Liabilities	132,693	111,889
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	38,354	37,382
Regulatory Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liability	57,425	34,059
Other Accruals [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	36,914	38,673
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	$ 0	$ 1,775

Asset Retirement Obligation (Na

Asset Retirement Obligation (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation [Line Items]
Liabilities Settled	$ 12,858	$ 4,967	$ 72,215
Upper Devonian Wells [Member]
Asset Retirement Obligation [Line Items]
Liabilities Settled			$ 58,400

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at Beginning of Year	$ 106,395	$ 112,330	$ 156,805
Liabilities Incurred	5,597	2,963	2,719
Revisions of Estimates	(419)	(10,578)	16,721
Liabilities Settled	(12,858)	(4,967)	(72,215)
Accretion Expense	9,520	6,647	8,300
Balance at End of Year	$ 108,235	$ 106,395	$ 112,330

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2018USD ($)
Regulatory Matters [Line Items]
Required Temporary Refund on Customer Rates	2.20%
Approved Return on Equity	8.70%
Empire [Member]
Regulatory Matters [Line Items]
Proposed Annual Cost of Service	$ 71.5
Proposed Rate Base	$ 246.8
Proposed Return on Equity	14.00%
2017 Tax Reform Act Regulatory Refund [Member] | New York [Member]
Regulatory Matters [Line Items]
Refund Provision Associated with Impact of 2017 Tax Reform	$ 9.1
2017 Tax Reform Act Regulatory Refund [Member] | Pennsylvania [Member]
Regulatory Matters [Line Items]
Refund Provision Associated with Impact of 2017 Tax Reform	$ 3.4

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2018	Sep. 30, 2017
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	$ 254,145	$ 372,839
Less: Amounts Included in Other Current Assets	[1]	(9,792)	(15,884)
Total Long-Term Regulatory Assets		112,918	174,433
Total Regulatory Liabilities		790,501	448,144
Less: Amounts Included in Current and Accrued Liabilities		(60,819)	(34,059)
Total Long-Term Regulatory Liabilities		146,743	113,716
Cost Of Removal Regulatory Liability [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		212,311	204,630
Taxes Refundable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		370,628	95,739
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		134,387	102,891
Amounts Payable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		3,394	0
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[2]	69,781	44,884
Total Long-Term Regulatory Liabilities		12,356	10,825
Non-Current Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Liabilities		729,682	414,085
Other Accruals and Current Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Current and Accrued Liabilities		(57,425)	(34,059)
Pension Costs Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	62,703	125,175
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	11,160	13,886
Recoverable Future Taxes [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	115,460	181,363
Environmental Site Remediation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	20,308	19,665
Asset Retirement Obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	15,495	12,764
Unamortized Debt Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	15,975	1,159
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	13,044	18,827
Total Long-Term Regulatory Assets		3,252	2,943
Long-Term Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Assets	[1]	244,353	356,955
Other Current Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Other Current Assets		$ (9,792)	$ (15,884)
[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]	$57,425 and $34,059 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $12,356 and $10,825 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively.
[3]	Included in Other Regulatory Assets on the Consolidated Balance Sheets.
[4]	$9,792 and $15,884 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $3,252 and $2,943 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2018 and 2017, respectively.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands		Oct. 01, 2018	Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Taxes [Line Items]
Federal Statutory Rate						24.50%	35.00%
Increase (Reduction) to Income Tax Expense Due to Remeasurement of Deferred Income Tax Assets and Liabilites			$ 3,500	$ 4,000	$ (111,000)	$ (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
Estimate for potential sequestration of AMT credit refunds						5,000
Taxes Refundable to Customers			370,628			370,628	$ 95,739
Recoverable Future Taxes			115,460			115,460	181,363
Deferred Income Taxes [Member]
Income Taxes [Line Items]
Taxes Refundable to Customers			370,600			370,600	95,700
Recoverable Future Taxes			115,500			115,500	181,400
Alternative Minimum Tax Credit [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards			84,200			84,200
Alternative Minimum Tax Credit [Member] | California [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards			6,983			6,983
Alternative Minimum Tax Credit [Member] | Federal [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards	[1]		$ 84,185			$ 84,185
Scenario, Forecast [Member]
Income Taxes [Line Items]
Federal Statutory Rate		21.00%
Guidance for Stock Based Compensation [Member]
Income Taxes [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance							$ 31,900
[1]	The $5.0 million estimate recorded for the potential sequestration of AMT credit refunds is not included in this amount.

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, 2018	Sep. 30, 2017	Sep. 30, 2016
Current Income Taxes [Abstract]
Federal	$ 2,025	$ 32,034	$ (6,658)
State	8,634	10,673	20,903
Deferred Income Taxes [Abstract]
Federal	(38,927)	103,046	(164,818)
State	20,774	14,929	(81,976)
Income Tax Expense (Benefit)	(7,494)	160,682	(232,549)
Deferred Investment Tax Credit	(105)	(173)	(348)
Total Income Taxes	(7,599)	160,509	(232,897)
Presented as Follows [Abstract]
Other Income	(105)	(173)	(348)
Income Tax Expense (Benefit)	$ (7,494)	$ 160,682	$ (232,549)

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate) (Details) - USD ($) $ in Thousands		Oct. 01, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Taxes [Line Items]
U.S. Income (Loss) Before Income Taxes			$ 383,922	$ 443,991	$ (523,855)
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate	[1]		94,061	155,397	(183,349)
Impact of 2017 Tax Reform Act	[2]		(112,598)	0	0
State Income Taxes (Benefit)	[3]		22,203	16,641	(39,697)
Federal Tax Credits			(6,576)	(6,679)	(3,262)
Miscellaneous			(4,689)	(4,850)	(6,589)
Total Income Taxes			$ (7,599)	$ 160,509	$ (232,897)
Federal Statutory Rate			24.50%	35.00%
Estimate for potential sequestration of AMT credit refunds			$ 5,000
Income tax benefit from blended tax rate			$ 9,100
Scenario, Forecast [Member]
Income Taxes [Line Items]
Federal Statutory Rate		21.00%
[1]	For fiscal 2018, represents the blended rate of 24.5%. Calculated as 35% for the first quarter of the fiscal year and 21% for the remaining three quarters.
[2]	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 described above.
[3]	The state income taxes (benefit) shown above includes income tax benefits related to state enhanced oil recovery tax credits and adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes.

Income Taxes (Significant Compo

Income Taxes (Significant Components Of Deferred Tax Liabilities And Assets) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Deferred Tax Liabilities [Abstract]
Property, Plant and Equipment	$ 770,794	$ 1,141,432
Pension and Other Post-Retirement Benefit Costs	39,541	79,516
Other	49,734	77,046
Total Deferred Tax Liabilities	860,069	1,297,994
Deferred Tax Assets [Abstract]
Pension and Other Post-Retirement Benefit Costs	(62,969)	(123,532)
Tax Loss and Credit Carryforwards	(214,128)	(200,344)
Other	(75,286)	(82,831)
Total Gross Deferred Tax Assets	(352,383)	(406,707)
Valuation Allowance	5,000	0
Total Deferred Tax Assets	(347,383)	(406,707)
Total Net Deferred Income Taxes	$ 512,686	$ 891,287

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Balance at Beginning of Year	$ 1,251	$ 396	$ 5,085
Additions for Tax Positions of Prior Years	0	1,251	396
Reductions for Tax Positions of Prior Years	(788)	(396)	(1,314)
Reductions Related to Settlements with Taxing Authorities	(463)	0	(3,771)
Balance at End of Year	$ 0	$ 1,251	$ 396

Income Taxes Income Taxes (Summ

Income Taxes Income Taxes (Summary of Operating Loss and Tax Credit Carryforwards) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2018USD ($)
Operating Loss Carryforwards [Line Items]
Charitable Contributions	$ 3,067
Federal net operating loss, certain annual limitations	1,800
Estimate for potential sequestration of AMT credit refunds	5,000
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss, subject to expiration	191,006	[1]
Net operating loss, not subject to expiration	58,334	[1]
Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	84,200
Alternative Minimum Tax Credit [Member] | Federal [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	84,185	[2]
Research and Development Tax Credit Carryforward [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	5,876
Enhanced Oil Recovery Credit [Member] | Federal [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	18,160
Pennsylvania [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	351,879
California [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	191,468
California [Member] | Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	6,983
California [Member] | Enhanced Oil Recovery Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	$ 7,613
[1]	Approximately $1.8 million of the federal Net Operating Loss carryforward is subject to certain annual limitations.
[2]	The $5.0 million estimate recorded for the potential sequestration of AMT credit refunds is not included in this amount.

Capitalization And Short-Term_3

Capitalization And Short-Term Borrowings (Narrative) (Details)	Aug. 17, 2018USD ($)	Sep. 27, 2017USD ($)	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2018USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / sharesshares	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 07, 2018USD ($)	Oct. 18, 2017USD ($)
Debt Instrument [Line Items]
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan | shares				138,997
Common stock issued for 401(k) plans | shares				75,745
Common stock shares issued due to SARs exercises | shares				75,971
Shares tendered | shares				57,065
Share-Based Payment Expense				$ 14,200,000	$ 10,800,000	$ 4,800,000
Tax benefit related to stock-based compensation expense				3,400,000	4,400,000	1,900,000
Capitalized stock-based compensation costs				100,000	100,000	100,000
Tax benefit from stock-based compensation exercises and vestings				1,000,000
Unamortized Debt Expense			$ 15,975,000	15,975,000	1,159,000
Gain (Loss) on Extinguishment of Debt				1,000,000
Net proceeds from issuance of long-term debt				295,020,000	295,151,000	$ 0
Principal amounts of long-term debt maturing in 2019			0	0
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 after 2023			1,100,000,000	1,100,000,000
Commercial paper, outstanding			0	0	0
Short-term notes payable outstanding			$ 0	$ 0	0
Committed credit facility 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				0.52
Additional borrowing			1,460,000,000	$ 1,460,000,000
Aggregated indebtedness				$ 40,000,000
Maximum debt increase under existing indenture covenants			$ 714,000,000
Preferred stock, shares authorized | shares			10,000,000	10,000,000
Preferred stock par value | $ / shares			$ 1	$ 1
Carrying Amount			$ 2,131,365,000	$ 2,131,365,000	$ 2,383,681,000
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				$ 4,400,000	$ 1,600,000	$ 400,000
Number of Awards Vested | shares				0	5,000	113,082
Equity instruments other than options, vested in period, total fair value					$ 100,000	$ 1,200,000
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			200,000	$ 200,000
Unrecognized compensation expense recognized weighted average period				2 years 1 month 13 days
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares				89,672	87,143	101,943
Weighted Average Fair Value per Award Granted | $ / shares				$ 51.23	$ 52.13	$ 35.89
Number of Awards Vested | shares				72,918
Unrecognized compensation expense			5,000,000	$ 5,000,000
Unrecognized compensation expense recognized weighted average period				2 years 2 months 13 days
Performance Shares [Member]
Debt Instrument [Line Items]
Common stock issued | shares				79,079
Number of Shares Granted | shares				208,588	184,148	309,996
Weighted Average Fair Value per Award Granted | $ / shares				$ 50.95	$ 56.39	$ 30.71
Number of Awards Vested | shares				79,079
Unrecognized compensation expense			11,200,000	$ 11,200,000
Unrecognized compensation expense recognized weighted average period				1 year 8 months 10 days
Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Common stock issued | shares				72,918
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued | shares				28,044
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%
Net proceeds from issuance of long-term debt		$ 295,200,000
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	$ 259,500,000
Unamortized Debt Expense			8,500,000	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
2019 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				80,354
2019 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				253,704
2020 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				68,189
2020 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				181,446
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				57,175
2021 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				206,140
2022 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				26,448
2023 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares				13,150

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, 2018		Jun. 30, 2018	Mar. 31, 2018	[2]	Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018		Sep. 30, 2017	Sep. 30, 2016
Schedule of Capitalization [Line Items]
Beginning balance (shares)							85,543,125						85,543,125
Beginning balance							$ 796,646						$ 796,646
Balance at Beginning of Year							851,669					$ 676,361	851,669		$ 676,361	$ 1,103,200
Beginning balance							(30,123)					(5,640)	(30,123)		(5,640)
Net Income (Loss) Available for Common Stock		$ 37,995	[1]	$ 63,025	$ 91,847		$ 198,654	[3]	$ 45,577	$ 59,714	$ 89,283	$ 88,908	391,521		283,482	(290,958)
Dividends Declared on Common Stock													(144,290)		(140,090)	(135,881)
Other Comprehensive Income (Loss), Net of Tax													(37,627)		(24,483)	(99,012)
Share-Based Payment Expense													$ 14,200		$ 10,800	4,800
Ending balance (Shares)		85,956,814							85,543,125				85,956,814		85,543,125
Ending balance		$ 820,223							$ 796,646				$ 820,223		$ 796,646
Balance at End of Year		1,098,900							851,669				1,098,900		851,669	676,361
Ending balance		(67,750)							$ (30,123)				$ (67,750)		$ (30,123)	$ (5,640)
Dividend per share													$ 1.68		$ 1.64	$ 1.60
Tax benefit related to stock-based compensation recorded to Paid in Capital																$ 1,900
Accumulated earnings free from limitations		$ 954,700											$ 954,700
Common Stock [Member]
Schedule of Capitalization [Line Items]
Beginning balance (shares)							85,543,000					85,119,000	85,543,000		85,119,000	84,594,000
Beginning balance (value)							$ 85,543					$ 85,119	$ 85,543		$ 85,119	$ 84,594
Common Stock Issued Under Stock and Benefit Plans (Shares)	[4]												414,000		424,000	525,000
Common Stock Issued Under Stock and Benefit Plans (Value)	[4]												$ 414		$ 424	$ 525
Ending balance (Shares)		85,957,000							85,543,000				85,957,000		85,543,000	85,119,000
Ending balance (Value)		$ 85,957							$ 85,543				$ 85,957		$ 85,543	$ 85,119
Paid In Capital [Member]
Schedule of Capitalization [Line Items]
Beginning balance							796,646					771,164	796,646		771,164	744,274
Share-Based Payment Expense	[5]												14,235		10,902	4,843
Common Stock Issued Under Stock and Benefit Plans (Value)	[4]												9,342		14,580	22,047
Ending balance		820,223							796,646				820,223		796,646	771,164
Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year							851,669					676,361	851,669		676,361	1,103,200
Net Income (Loss) Available for Common Stock													391,521		283,482	(290,958)
Dividends Declared on Common Stock													(144,290)		(140,090)	(135,881)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation									31,916						31,916
Balance at End of Year		1,098,900	[6]						851,669				1,098,900	[6]	851,669	676,361
Accumulated Other Comprehensive Income (Loss) [Member]
Schedule of Capitalization [Line Items]
Beginning balance							$ (30,123)					$ (5,640)	(30,123)		(5,640)	93,372
Other Comprehensive Income (Loss), Net of Tax													(37,627)		(24,483)	(99,012)
Ending balance		$ (67,750)							$ (30,123)				$ (67,750)		$ (30,123)	$ (5,640)
[1]	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.
[2]	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.
[3]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[4]	Paid in Capital includes tax benefits of $1.9 million for September 30, 2016, related to stock-based compensation.
[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, 2018, $954.7 million of accumulated earnings was free of such limitations.

Capitalization And Short-Term_5

Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Share Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Schedule of Capitalization [Line Items]
Number of Shares Exercised		75,971
Number of Shares available for future grant	[1]	1,478,086
Performance Shares [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		527,748
Number of Shares Granted		208,588	184,148	309,996
Number of Awards Vested		(79,079)
Number of Shares Forfeited		(15,967)
Number of Shares Outstanding, End of Year		641,290	527,748
Weighted Average Fair Value per Award, Beginning of Year		$ 45.44
Weighted Average Fair Value per Award Granted		50.95	$ 56.39	$ 30.71
Weighted Average Fair Value per Award Vested		65.38
Weighted Average Fair Value per Award Forfeited		57.15
Weighted Average Fair Value per Award, End of Year		$ 44.49	$ 45.44
Stock Appreciation Rights (SARs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		1,505,911
Number of Shares Granted		0	0	0
Number of Shares Exercised		(206,823)
Number of Awards Vested		0	(5,000)	(113,082)
Number of Shares Forfeited		0
Number of Shares Expired		0
Number of Shares Outstanding, End of Year		1,299,088	1,505,911
Number of SARs exercisable		1,299,088
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 48.64
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		35.70
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Expired		0
Weighted Average Exercise Price, Outstanding End of Year		50.70	$ 48.64
Weighted Average Exercise Price, SARs exercisable		$ 50.70
Weighted Average Remaining Contractual Life, Outstanding		1 year 9 months 6 days
Weighted Average Remaining Contractual Life, SARs exercisable		1 year 9 months 6 days
Aggregate Intrinsic Value Outstanding		$ 8,199
Aggregate Intrinsic Value, SARs exercisable		$ 8,199
[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, 2018	Sep. 30, 2017	Sep. 30, 2016
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	233,199
Number of Shares Granted	89,672	87,143	101,943
Number of Awards Vested	(72,918)
Number of Shares Forfeited	(4,637)
Number of Shares Outstanding, End of Year	245,316	233,199
Weighted Average Fair Value per Award, Beginning of Year	$ 48.99
Weighted Average Fair Value per Award Granted	51.23	$ 52.13	$ 35.89
Weighted Average Fair Value per Award Vested	53.73
Weighted Average Fair Value per Award Forfeited	46.04
Weighted Average Fair Value per Award, End of Year	$ 48.45	$ 48.99

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, 2018	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk Free Interest Rate	1.96%	1.54%	1.26%
Remaining Term at Date of Grant (Years)	2 years 9 months 12 days	2 years 9 months 14 days	2 years 9 months 14 days
Expected Volatility Rate	22.00%	22.60%	20.50%

Capitalization And Short-Term_8

Capitalization And Short-Term Borrowings (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Aug. 17, 2018	Oct. 18, 2017	Sep. 27, 2017
Debt Instrument [Line Items]
Total Long-Term Debt		$ 2,149,000	$ 2,399,000
Less Unamortized Discount and Debt Issuance Costs		17,635	15,319
Less Current Portion	[1]	0	300,000
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		$ 2,131,365	2,083,681
Maximum interest rate adjustment		2.00%
6.50% Notes Due April 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, face value			$ 300,000
Long-term debt, interest rate			6.50%
Debt Instrument redeemed					$ 307,000
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	$ 2,300,000
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%	8.75%
[1]	Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes that were scheduled to mature in April 2018. The Company redeemed those notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.
[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%, 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).

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($)		Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	[1]	$ 3,441,000	$ 1,741,000
Level 1 or Level 2 Transfers		0	0
Derivative Financial Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring 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		3,441,000	1,741,000
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		3,400,000	1,700,000
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, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 215,272	$ 527,978
Hedging Collateral Deposits	[1]	3,441	1,741
Total Assets	[1]	320,321	651,740
Total Liabilities	[1]	49,036	1,103
Total Net Assets/(Liabilities)	[1]	271,285	650,637
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0	520
Derivative Liability	[1]	1,337	0
Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	9,033	34,771
Derivative Liability	[1]	47,183	1,103
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0	820
Derivative Liability	[1]	516	0
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	38,468	37,033
Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	51,331	45,727
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	2,776	3,150
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		215,272	527,978
Hedging Collateral Deposits		3,441	1,741
Total Assets		312,363	617,112
Total Liabilities		2,412	963
Total Net Assets/(Liabilities)		309,951	616,149
Fair Value, Inputs, Level 1 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		1,075	1,483
Derivative Liability		2,412	963
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		38,468	37,033
Fair Value, Inputs, Level 1 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		51,331	45,727
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		2,776	3,150
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		26,517	40,204
Total Liabilities		65,183	5,716
Total Net Assets/(Liabilities)		(38,666)	34,488
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		26,074	38,977
Derivative Liability		64,224	5,309
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		443	1,227
Derivative Liability		959	407
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]	(18,559)	(5,576)
Total Liabilities	[1]	(18,559)	(5,576)
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]	(1,075)	(963)
Derivative Liability	[1]	(1,075)	(963)
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]	(17,041)	(4,206)
Derivative Liability	[1]	(17,041)	(4,206)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(443)	(407)
Derivative Liability	[1]	(443)	(407)
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, 2018USD ($)counterpartyMMcfbbl	Sep. 30, 2017USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Net hedging gains (losses) in accumulated other comprehensive income (loss)		$ (37,400,000)
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)		(28,600,000)
Pre-tax Net hedging gains (losses) reclassified within twelve months		(23,700,000)
After tax Net hedging gains (losses) reclassified within twelve months		(17,000,000)
Fair market value of derivative asset with a credit-risk related contingency		9,000,000
Fair market value of derivative liability with a credit-risk related contingency		40,300,000
Hedging collateral deposits	[1]	3,441,000	$ 1,741,000
Equity Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gross unrealized gain		10,700,000	9,900,000
Sales proceeds		1,500,000
Gross realized gain		400,000
Fixed Income Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gross unrealized loss		800,000	100,000
Sales proceeds		1,500,000
Gross realized loss		100,000
Insurance Company Stock [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gross unrealized gain		1,800,000	$ 2,200,000
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount		$ 86,500,000
Fair Value Hedges Mmcf [Member] | Energy Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf		27,700
Exchange-Traded Futures Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedging collateral deposits		$ 3,400,000
Fixed Price Sales Commitments MMCf [Member] | Energy Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf		27,100
Fixed Price Commitments Related To Withdrawal Of Storage Gas MMCf [Member] | Energy Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf		600
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		3
Credit risk exposure per counterparty		$ 3,000,000
Maximum credit risk exposure per counterparty		5,600,000
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		120,100
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		4,188,000
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		1,800
[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, 2018	Sep. 30, 2017
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,131,365	$ 2,383,681
Fair Value	$ 2,121,861	$ 2,523,639

Financial Instruments (Other In

Financial Instruments (Other Investments) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Sep. 30, 2017
Investment Holdings [Line Items]
Cash Surrender Value of Life Insurance	$ 39,970	$ 39,355
Other Investments	132,545	125,265
Equity Mutual Fund [Member]
Investment Holdings [Line Items]
Fair value	38,468	37,033
Fixed Income Mutual Fund [Member]
Investment Holdings [Line Items]
Fair value	51,331	45,727
Insurance Company Stock [Member]
Investment Holdings [Line Items]
Fair value	$ 2,776	$ 3,150

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, 2018	Sep. 30, 2017	Sep. 30, 2016
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)	$ (74,103)	$ 5,347	$ 60,493
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)	(1,189)	81,605
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	(782)	(100)
Foreign Currency Contracts [Member] | Operation and Maintenance Expense [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)	(3,899)	2,700
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)	(2,564)	(457)
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)	(70,905)	2,811
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)	423	83,983
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	(782)	(100)
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)	701	(164)
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)	952	(1,921)
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, 2018USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	$ (1,527)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	1,527
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(1,289)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	1,289
Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(238)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	$ 238

Retirement Plan And Other Pos_3

Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Increase to accumulated other comprehensive income	$ 57,283,000	$ 44,731,000	$ 171,586,000
Expected future benefit payments in year one	65,700,000
Expected future benefit payments in year two	65,900,000
Expected future benefit payments in year three	66,300,000
Expected future benefit payments in year four	66,500,000
Expected future benefit payments in year five	66,600,000
Expected future benefit payments in five years thereafter	330,900,000
Effect of one percentage point increase on accumulated postretirement benefit obligation	51,300,000
Effect of one percentage point increase on service and interest cost components	2,900,000
Effect of one percentage point decrease on accumulated postretirement benefit obligation	42,800,000
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	6,800,000	7,600,000	7,500,000
Accumulated benefit obligation	70,600,000	72,500,000	72,400,000
Benefit obligation	$ 86,100,000	$ 88,900,000	$ 91,700,000
Discount rate	4.02%	3.22%	2.80%
Rate of compensation increase	7.75%	7.75%	7.75%
Tax-Deferred Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	$ 6,200,000	$ 5,900,000	$ 5,900,000
Retirement Savings Account [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	3,500,000	2,900,000	2,600,000
Other Than Veba Trust And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	100,000
Non-Qualified Benefit Plans, Other Post-Retirement Benefit Plan And Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Decrease in other regulatory assets	75,300,000
Increase to accumulated other comprehensive income	15,900,000
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	28,382,000	34,848,000	32,095,000
Accumulated benefit obligation	946,763,000	1,010,179,000	1,039,408,000
Benefit obligation	$ 985,690,000	$ 1,054,826,000	$ 1,097,421,000	$ 1,026,190,000
Discount rate	4.30%	3.77%	3.60%
Rate of compensation increase	4.70%	4.70%	4.70%
Employer Contributions	$ 32,980,000	$ 17,146,000	$ 7,000,000
Expected long term rate of return on plan assets	7.00%	7.00%	7.25%
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 10,306,000	$ 14,092,000	$ 12,923,000
Benefit obligation	$ 435,986,000	$ 462,619,000	$ 526,138,000	$ 464,987,000
Discount rate	4.31%	3.81%	3.70%
Rate of compensation increase	4.70%	4.70%	4.70%
Employer Contributions	$ 2,896,000	$ 3,853,000	$ 2,839,000
Expected future benefit payments in year one	27,821,000
Expected future benefit payments in year two	28,692,000
Expected future benefit payments in year three	29,455,000
Expected future benefit payments in year four	29,979,000
Expected future benefit payments in year five	30,426,000
Expected future benefit payments in five years thereafter	$ 153,855,000
Expected long term rate of return on plan assets	6.25%	6.50%	6.75%
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	11,200,000
Other Actuarial Experience [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	7,300,000	$ (50,300,000)	$ 11,000,000
Mortality Improvement Projection Scale [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(3,300,000)
Mortality Improvement Projection Scale [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(2,400,000)	(5,700,000)
Discount Rate Change [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(58,100,000)	(20,500,000)	78,500,000
Discount Rate Change [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ (25,800,000)	(6,200,000)	49,400,000
Effective Fiscal 2019 [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	6.75%
Effective Fiscal 2019 [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	6.00%
Minimum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 29,000,000
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	$ 35,000,000
Maximum [Member] | VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 4,000,000
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	$ 11,500,000	14,100,000	9,800,000
Non-Current [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 74,600,000	$ 74,800,000	$ 81,900,000

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, 2018	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Non-Current Assets		$ 82,733	$ 56,370
Amortization period		10 years
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 1,054,826	1,097,421	$ 1,026,190
Service Cost		9,921	11,969	11,710
Interest Cost		33,006	38,383	42,315
Plan Participants' Contributions		0	0	0
Retiree Drug Subsidy Receipts		0	0	0
Actuarial (Gain) Loss		(50,218)	(32,466)	76,309
Benefits Paid		(61,845)	(60,481)	(59,103)
Benefit Obligation at End of Period		985,690	1,054,826	1,097,421
Fair Value of Assets at Beginning of Period		910,719	869,775	834,870
Actual Return on Plan Assets		42,652	84,279	87,008
Employer Contributions		32,980	17,146	7,000
Plan Participants' Contributions		0	0	0
Benefits Paid		(61,845)	(60,481)	(59,103)
Fair Value of Assets at End of Period		924,506	910,719	869,775
Net Amount Recognized at End of Period (Funded Status)		(61,184)	(144,107)	(227,646)
Non-Current Liabilities		(61,184)	(144,107)	(227,646)
Non-Current Assets		0	0	0
Accumulated Benefit Obligation		$ 946,763	$ 1,010,179	$ 1,039,408
Discount Rate		4.30%	3.77%	3.60%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Expected Return on Plan Assets		$ (61,715)	$ (59,718)	$ (59,369)
Amortization of Prior Service Cost (Credit)		938	1,058	1,234
Recognition of Actuarial Loss	[1]	37,205	42,687	32,248
Net Amortization and Deferral for Regulatory Purposes		9,027	469	3,957
Net Periodic Benefit Cost		$ 28,382	$ 34,848	$ 32,095
Effective Discount Rate for Benefit Obligations		3.77%	3.60%	4.25%
Effective Rate for Interest on Benefit Obligations		3.23%	3.60%	4.25%
Effective Discount Rate for Service Cost		4.00%	3.60%	4.25%
Effective Rate for Interest on Service Cost		3.73%	3.60%	4.25%
Expected Return on Plan Assets		7.00%	7.00%	7.25%
Rate of Compensation Increase		4.70%	4.70%	4.75%
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 462,619	$ 526,138	$ 464,987
Service Cost		1,830	2,449	2,331
Interest Cost		14,801	19,007	20,386
Plan Participants' Contributions		2,894	2,717	2,558
Retiree Drug Subsidy Receipts		1,545	1,553	1,925
Actuarial (Gain) Loss		(21,039)	(62,215)	60,402
Benefits Paid		(26,664)	(27,030)	(26,451)
Benefit Obligation at End of Period		435,986	462,619	526,138
Fair Value of Assets at Beginning of Period		514,017	494,320	477,959
Actual Return on Plan Assets		20,657	40,157	37,415
Employer Contributions		2,896	3,853	2,839
Plan Participants' Contributions		2,894	2,717	2,558
Benefits Paid		(26,664)	(27,030)	(26,451)
Fair Value of Assets at End of Period		513,800	514,017	494,320
Net Amount Recognized at End of Period (Funded Status)		77,814	51,398	(31,818)
Non-Current Liabilities		(4,919)	(4,972)	(49,467)
Non-Current Assets		$ 82,733	$ 56,370	$ 17,649
Discount Rate		4.31%	3.81%	3.70%
Rate of Compensation Increase		4.70%	4.70%	4.70%
Expected Return on Plan Assets		$ (31,482)	$ (31,458)	$ (31,535)
Amortization of Prior Service Cost (Credit)		(429)	(429)	(912)
Recognition of Actuarial Loss	[1]	10,558	18,415	5,530
Net Amortization and Deferral for Regulatory Purposes		15,028	6,108	17,123
Net Periodic Benefit Cost		$ 10,306	$ 14,092	$ 12,923
Effective Discount Rate for Benefit Obligations		3.81%	3.70%	4.50%
Effective Rate for Interest on Benefit Obligations		3.29%	3.70%	4.50%
Effective Discount Rate for Service Cost		4.10%	3.70%	4.50%
Effective Rate for Interest on Service Cost		3.98%	3.70%	4.50%
Expected Return on Plan Assets		6.25%	6.50%	6.75%
Rate of Compensation Increase		4.70%	4.70%	4.75%
[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, 2018USD ($)	[1]
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Gain (Loss)	$ (22,818)
Prior Service (Cost) Credit	0
Net Amount Recognized	(22,818)
Decrease (Increase) in Actuarial Loss, excluding amortization	(2,035)	[2]
Change due to Amortization of Actuarial Loss	3,549
Prior Service (Cost) Credit	0
Net Change	1,514
Net Actuarial Loss	(3,558)
Prior Service (Cost) Credit	0
Net Amount Expected to be Recognized	(3,558)
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Gain (Loss)	(135,527)
Prior Service (Cost) Credit	(5,195)
Net Amount Recognized	(140,722)
Decrease (Increase) in Actuarial Loss, excluding amortization	31,155	[2]
Change due to Amortization of Actuarial Loss	37,205
Prior Service (Cost) Credit	938
Net Change	69,298
Net Actuarial Loss	(32,096)
Prior Service (Cost) Credit	(826)
Net Amount Expected to be Recognized	(32,922)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Gain (Loss)	1,193
Prior Service (Cost) Credit	3,258
Net Amount Recognized	4,451
Decrease (Increase) in Actuarial Loss, excluding amortization	10,213	[2]
Change due to Amortization of Actuarial Loss	10,558
Prior Service (Cost) Credit	(429)
Net Change	20,342
Net Actuarial Loss	(5,962)
Prior Service (Cost) Credit	429
Net Amount Expected to be Recognized	$ (5,533)
[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) $ in Thousands	Sep. 30, 2018USD ($)
Defined Benefit Plan Disclosure [Line Items]
2019 - Benefit Payments	$ 65,700
2020 - Benefit Payments	65,900
2021 - Benefit Payments	66,300
2022 - Benefit Payments	66,500
2023 - Benefit Payments	66,600
2024 through 2028 - Benefit Payments	330,900
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
2019 - Benefit Payments	27,821
2019 - Subsidy Receipts	(1,858)
2020 - Benefit Payments	28,692
2020 - Subsidy Receipts	(1,996)
2021 - Benefit Payments	29,455
2021 - Subsidy Receipts	(2,128)
2022 - Benefit Payments	29,979
2022 - Subsidy Receipts	(2,260)
2023 - Benefit Payments	30,426
2023 - Subsidy Receipts	(2,386)
2024 through 2028 - Benefit Payments	153,855
2024 through 2028 - Subsidy Receipts	$ (13,325)

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, 2018	Sep. 30, 2017	Sep. 30, 2016
Retirement Benefits [Abstract]
Rate of Medical Cost Increase for Pre Age 65 Participants	[1]	5.59%	5.67%	5.75%
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]	7.89%	8.45%	9.00%
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]	7.18%	7.33%	7.20%
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, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ 924,506	$ 910,719	$ 869,775	$ 834,870
Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	223,300	290,716
Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	100,832	123,069
Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	85,942	121,008
Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	434,392	348,501
Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	416	422
Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	72,382	75,428
Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		53,878	3,391
Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		26,191	26,058
Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		997,333	988,593
Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(67,817)	(64,728)
Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		929,516	923,865
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		513,800	514,017	$ 494,320	$ 477,959
Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		7,894	9,569
Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		67,817	64,728
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		125,295	130,864
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		47,245	52,063
Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		265,667	256,099
Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		446,101	448,595
Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		513,918	513,323
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	139,885	209,421
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]	1,640	1,664
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	416	422
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		141,941	211,507
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(9,695)	(14,026)
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		132,246	197,481
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		9,695	14,026
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	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	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		265,667	256,099
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		265,667	256,099
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		275,362	270,125
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]	382,348	346,837
Fair Value, Inputs, Level 2 [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 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		382,348	346,837
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(26,114)	(23,001)
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		356,234	323,836
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		26,114	23,001
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	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	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		26,114	23,001
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		3,194	3,391
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		3,194	3,391
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(218)	(225)
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		2,976	3,166
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		218	225
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	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	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		218	225
Measured at NAV [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1],[7]	83,415	81,295
Measured at NAV [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2],[7]	100,832	123,069
Measured at NAV [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3],[7]	85,942	121,008
Measured at NAV [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4],[7]	50,404	0
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]	72,382	75,428
Measured at NAV [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	50,684	0
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]	26,191	26,058
Measured at NAV [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	469,850	426,858
Measured at NAV [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	(31,790)	(27,476)
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]	438,060	399,382
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]	7,894	9,569
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]	31,790	27,476
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	130,864
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	52,063
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]	180,434	192,496
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]	212,224	219,972
Miscellaneous Accruals, Interest Receivables, And Non-Interest Cash [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(5,010)	(13,146)
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		$ (118)	$ 694
[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 an exchange traded fund.
[6]	Global Fixed Income securities are comprised of a collective trust fund.
[7]	Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.

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, 2018	Sep. 30, 2017
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	$ 3,166	$ 2,782
Unrealized Gains/(Losses)	169	384
Sales	(359)
Balance, End of Year	2,976	3,166
Real Estate [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	3,391	2,970
Unrealized Gains/(Losses)	188	421
Sales	(385)
Balance, End of Year	3,194	3,391
Excluding 401(h) Investments [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	(225)	(188)
Unrealized Gains/(Losses)	(19)	(37)
Sales	26
Balance, End of Year	(218)	(225)
401(h) Investments [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	225	188
Unrealized Gains/(Losses)	19	37
Sales	(26)
Balance, End of Year	$ 218	$ 225

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2018USD ($)
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 7.6
Project Costs	76.2
Future purchase obligation first year	297.9
Future purchase obligation second year	102.9
Future purchase obligation third year	86.6
Future purchase obligation fourth year	152.5
Future purchase obligation fifth year	162.8
Future purchase obligation thereafter	1,606
Operating lease commitment first year	18.6
Operating lease commitment second year	4.6
Operating lease commitment third year	4
Operating lease commitment fourth year	3.2
Operating lease commitment fifth year	2.7
Operating lease commitment thereafter	12.4
Former Manufactured Gas Plant Site New York [Member]
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 4.1
Environmental Site Remediation Costs [Member]
Site Contingency [Line Items]
Rate recovery period	4 years
Pipeline And Storage, Gathering And Utility Segments [Member]
Site Contingency [Line Items]
Contract commitments first year	$ 105.1
Contract commitments second year	6.8
Contract commitments third year	6.1
Contractual commitments fourth year	5.1
Contractual commitments fifth year	3.4
Contractual commitments thereafter	13.3
Exploration And Production [Member]
Site Contingency [Line Items]
Contract commitments first year	86.2
Contract commitments second year	$ 24.8

Business Segment Information (N

Business Segment Information (Narrative) (Details)	12 Months Ended
	Sep. 30, 2018segment
Segment Reporting [Abstract]
Number of Reportable Segments	5

Business Segment Information (S

Business Segment Information (Segment Information By Segment) (Details) - USD ($) $ in Thousands		3 Months Ended											12 Months Ended
		Sep. 30, 2018		Jun. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Revenue		$ 289,196		$ 342,912	$ 540,905		$ 419,655		$ 286,937	$ 348,369	$ 522,075	$ 422,500	$ 1,592,668	$ 1,579,881	$ 1,452,416
Interest Income													6,766	4,113	4,235
Interest Expense													114,522	119,837	121,044
Depreciation, Depletion and Amortization													240,961	224,195	249,417
Income Tax Expense (Benefit)													(7,494)	160,682	(232,549)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties													0	0	948,307
Segment Profit: Net Income (Loss)		37,995	[1]	$ 63,025	$ 91,847	[2]	$ 198,654	[3]	45,577	$ 59,714	$ 89,283	$ 88,908	391,521	283,482	(290,958)
Expenditures for Additions to Long-Lived Assets													600,602	462,117	523,051
Segment Assets		6,036,486							6,103,320				6,036,486	6,103,320	5,636,387
Utility [Member]
Segment Reporting Information [Line Items]
Interest Income													1,591	1,051	1,737
Interest Expense													26,753	28,492	27,582
Depreciation, Depletion and Amortization													53,253	52,582	48,618
Income Tax Expense (Benefit)													15,258	24,894	25,602
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)													51,217	46,935	50,960
Expenditures for Additions to Long-Lived Assets													85,648	80,867	98,007
Segment Assets		1,921,971							2,013,123				1,921,971	2,013,123	2,021,514
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Interest Income													2,748	1,467	770
Interest Expense													31,383	33,717	33,327
Depreciation, Depletion and Amortization													43,463	41,196	43,273
Income Tax Expense (Benefit)													17,806	40,947	50,241
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)													97,246	68,446	76,610
Expenditures for Additions to Long-Lived Assets													92,832	95,336	114,250
Segment Assets		1,848,180							1,929,788				1,848,180	1,929,788	1,680,734
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Interest Income													1,479	707	858
Interest Expense													54,288	53,702	55,434
Depreciation, Depletion and Amortization													124,274	112,565	139,963
Income Tax Expense (Benefit)													(41,962)	66,093	(334,029)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															948,307
Segment Profit: Net Income (Loss)													180,632	129,326	(452,842)
Expenditures for Additions to Long-Lived Assets													380,677	253,057	256,104
Segment Assets		1,568,563							1,407,152				1,568,563	1,407,152	1,323,081
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Interest Income													685	571	422
Interest Expense													22	47	49
Depreciation, Depletion and Amortization													275	279	278
Income Tax Expense (Benefit)													632	891	2,460
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)													373	1,509	4,348
Expenditures for Additions to Long-Lived Assets													40	36	34
Segment Assets		50,971							60,937				50,971	60,937	63,392
Gathering [Member]
Segment Reporting Information [Line Items]
Interest Income													1,106	994	297
Interest Expense													9,560	9,142	8,872
Depreciation, Depletion and Amortization													17,313	16,162	15,282
Income Tax Expense (Benefit)													(17,677)	29,694	24,334
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)													83,519	40,377	30,499
Expenditures for Additions to Long-Lived Assets													61,728	32,645	54,293
Segment Assets		533,608							580,051				533,608	580,051	534,259
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Interest Income													7,609	4,790	4,084
Interest Expense													122,006	125,100	125,264
Depreciation, Depletion and Amortization													238,578	222,784	247,414
Income Tax Expense (Benefit)													(25,943)	162,519	(231,392)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															948,307
Segment Profit: Net Income (Loss)													412,987	286,593	(290,425)
Expenditures for Additions to Long-Lived Assets													620,925	461,941	522,688
Segment Assets		5,923,293							5,991,051				5,923,293	5,991,051	5,622,980
All Other [Member]
Segment Reporting Information [Line Items]
Interest Income													388	213	117
Interest Expense													0	0	0
Depreciation, Depletion and Amortization													1,627	661	1,260
Income Tax Expense (Benefit)													1,493	(247)	561
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)													(112)	(342)	778
Expenditures for Additions to Long-Lived Assets													1	39	37
Segment Assets		78,109							76,861				78,109	76,861	77,138
Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Interest Income													(1,231)	(890)	34
Interest Expense													(7,484)	(5,263)	(4,220)
Depreciation, Depletion and Amortization													756	750	743
Income Tax Expense (Benefit)													16,956	(1,590)	(1,718)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)													(21,354)	(2,769)	(1,311)
Expenditures for Additions to Long-Lived Assets													(20,324)	137	326
Segment Assets		$ 35,084							$ 35,408				35,084	35,408	(63,731)
Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												1,592,668	1,579,881	1,452,416
Revenue from External Customers [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												674,726	626,899	531,024
Revenue from External Customers [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												210,345	206,615	215,674
Revenue from External Customers [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												564,547	614,599	607,113
Revenue from External Customers [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												137,748	128,586	93,578
Revenue from External Customers [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												41	115	374
Revenue from External Customers [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												1,587,407	1,576,814	1,447,763
Revenue from External Customers [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												4,601	2,173	3,753
Revenue from External Customers [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue	[4]												660	894	900
Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue													0	0	0
Intersegment Revenues [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue													12,800	13,072	13,123
Intersegment Revenues [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue													89,981	87,810	90,755
Intersegment Revenues [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue													0	0	0
Intersegment Revenues [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenue													826	794	884
Intersegment Revenues [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue													107,856	107,566	89,073
Intersegment Revenues [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue													211,463	209,242	193,835
Intersegment Revenues [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue													0	0	0
Intersegment Revenues [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue													$ (211,463)	$ (209,242)	$ (193,835)
[1]	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.
[2]	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.
[3]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.
[4]	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, 2018	Sep. 30, 2017	Sep. 30, 2016
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-Lived Assets	$ 5,491,895	$ 5,285,040	$ 5,223,356

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, 2018		Jun. 30, 2018	Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Increase (Reduction) to Income Tax Expense Due to Remeasurement of Deferred Income Tax Assets and Liabilites	$ 3,500			$ 4,000		$ (111,000)						$ (103,500)
Operating Revenues	289,196		$ 342,912	540,905		419,655		$ 286,937	$ 348,369	$ 522,075	$ 422,500	1,592,668	$ 1,579,881	$ 1,452,416
Operating Income	80,629		107,760	156,702		141,995		87,395	123,354	169,957	172,139	487,086	552,845	(416,518)
Net Income Available for Common Stock	$ 37,995	[1]	$ 63,025	$ 91,847	[2]	$ 198,654	[3]	$ 45,577	$ 59,714	$ 89,283	$ 88,908	$ 391,521	$ 283,482	$ (290,958)
Earnings per Common Share, Basic	$ 0.44		$ 0.73	$ 1.07		$ 2.32		$ 0.53	$ 0.70	$ 1.05	$ 1.04	$ 4.56	$ 3.32	$ (3.43)
Earnings per Common Share, Diluted	$ 0.44		$ 0.73	$ 1.06		$ 2.30		$ 0.53	$ 0.69	$ 1.04	$ 1.04	$ 4.53	$ 3.30	$ (3.43)
[1]	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.
[2]	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.
[3]	Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.

Supplementary Information For_3

Supplementary Information For Oil And Gas Producing Activities (Narrative) (Details) $ in Millions, ft³ in Billions	12 Months Ended
	Sep. 30, 2018USD ($)ft³	Sep. 30, 2017USD ($)ft³	Sep. 30, 2016USD ($)ft³	Sep. 30, 2015	Sep. 30, 2014
Reserve Quantities [Line Items]
Amount spent for developing proved undeveloped reserves | $	$ 182.3	$ 101.1	$ 92.8
Proved Undeveloped Reserve (Volume)	757	612	543
Percentage of PUD reserves to the total proved reserves	30.00%	28.00%	29.00%
New PUD reserve additions	431	269
PUD Sales	57
PUD Upward Revisions	60	13
PUD conversions to developed reserves	284	159
Proved Undeveloped Reserves, Removed	5	54
Increase in Proved undeveloped (PUD) reserves	145	69
Investment made to convert proved undeveloped reserves to developed reserves | $	$ 182	$ 101
Conversion of undeveloped proved reserves to developed proved reserves	284	147
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year	46.00%	27.00%	25.00%	33.00%	51.00%
Well Locations Developed With Net PUD Reserves	53	37
Percent of Well Locations Developed With Net PUD Reserves	62.00%	41.00%
Arbitrary discount rate	10.00%
West Coast Region [Member]
Reserve Quantities [Line Items]
New PUD reserve additions	5	2
PUD conversions to developed reserves	2	1
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	394	456	542
New PUD reserve additions	229	113
PUD conversions to developed reserves	264	158
Utica Shale [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	357	154
New PUD reserve additions	197	154
PUD conversions to developed reserves	18
Will Not Meet 5 Year Requirement for Proved Reserves [Member] | Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Removed		36
Change in Development Plans [Member] | Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Removed		18
Total PUD Reserve Additions Estimated In The Next Fiscal Year [Member]
Reserve Quantities [Line Items]
Amount to be spent on developing proved undeveloped reserves | $	$ 210
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, 2018	Sep. 30, 2017
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved Properties	[1]	$ 5,114,753	$ 4,832,301
Unproved Properties		62,234	80,932
Capitalized Costs, Oil and Gas Producing Activities, Gross, Total		5,176,987	4,913,233
Less - Accumulated Depreciation, Depletion and Amortization		3,862,687	3,765,710
Capitalized Costs Oil And Gas Producing Activities Net		1,314,300	1,147,523
Asset retirement costs		$ 44,300	$ 54,400
[1]	Includes asset retirement costs of $44.3 million and $54.4 million at September 30, 2018 and 2017, 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, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	$ 0	$ 0	$ 0
Development Costs	11,115	236	2,886
Exploration Costs	0	32	7,574
Capitalized Interest	20	0	103
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	11,135	$ 268	$ 10,563
Capitalized Costs Of Unproved Properties Cumulative Balance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	39,681
Development Costs	14,824
Exploration Costs	7,606
Capitalized Interest	123
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	$ 62,234
Costs Incurred Prior To Fiscal 2016 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs				$ 39,681
Development Costs				587
Exploration Costs				0
Capitalized Interest				0
Capitalized Costs of Unproved Properties Excluded from Amortization, Total				$ 40,268

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, 2018	Sep. 30, 2017	Sep. 30, 2016
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved		$ 1,544	$ 8,908	$ 1,342
Unproved		4,286	262	2,165
Exploration Costs	[1]	29,365	40,975	27,561
Development Costs	[2]	332,496	200,639	219,386
Asset Retirement Costs		(10,107)	(9,175)	(49,653)
Total Property Acquisition Costs		357,584	241,609	200,801
Capitalized interest included in exploration costs		0	300	300
Capitalized interest included in development costs		$ 300	$ 200	$ 200
[1]	Amounts for 2018, 2017 and 2016 include capitalized interest of zero, $0.3 million and $0.3 million, respectively.
[2]	Amounts for 2018, 2017 and 2016 include capitalized interest of $0.3 million, $0.2 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, 2018	Sep. 30, 2017	Sep. 30, 2016
Reserve Quantities [Line Items]
Revenues from sales to affiliates		$ 0	$ 0	$ 0
Operating Revenues	[1]	558,896,000	526,492,000	386,152,000
Production/Lifting Costs		162,721,000	165,991,000	153,914,000
Franchise/Ad Valorem Taxes		14,355,000	15,372,000	13,794,000
Purchased Emission Allowance Expense		1,883,000	1,391,000	700,000
Accretion Expense		4,266,000	4,896,000	6,663,000
Depreciation, Depletion and Amortization ($0.67, $0.63 and $0.85 per Mcfe of production)		119,946,000	108,471,000	136,579,000
Impairment of Oil and Gas Producing Properties		0	0	948,307,000
Income Tax Expense (Benefit)		72,723,000	86,657,000	(368,940,000)
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)		183,002,000	143,714,000	(504,865,000)
Depreciation, Depletion and Amortization, per Mcfe of Production		0.67	0.63	0.85
Transfers to Entity's Other Operations		2,134,000	2,357,000	1,765,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Natural Gas (includes transfers to operations of $2,134, $2,357 and $1,765, respectively)	[2]	390,642,000	399,975,000	282,619,000
Oil, Condensate And Other Liquids [Member]
Reserve Quantities [Line Items]
Operating Revenues		$ 168,254,000	$ 126,517,000	$ 103,533,000
[1]	Exclusive of hedging gains and losses. See further discussion in Note G — 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, 2018MMcfft³MBbls	Sep. 30, 2017MMcfft³MBbls	Sep. 30, 2016MMcfft³MBbls	Sep. 30, 2015MMcfMBbls
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		757	612	543
Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		1,973,120	1,674,575	2,142,128
Extensions and Discoveries		521,694	386,657	185,347
Revisions of Previous Estimates		93,435	90,849	(248,161)
Production Volume		(162,906)	(157,088)	(143,547)
Sales of Minerals in Place		(68,001)	(21,873)	(261,192)
Proved Developed and Undeveloped Reserves		2,357,342	1,973,120	1,674,575
Proved Developed Reserves (Volume)		1,606,532	1,363,102	1,132,616	1,316,844
Proved Undeveloped Reserve (Volume)		750,810	610,018	541,959	825,284
Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		30,207	29,009	33,722
Extensions and Discoveries | MBbls		2,301	674	530
Revisions of Previous Estimates | MBbls		2,477	3,293	(2,247)
Production Volume		(2,535)	(2,740)	(2,923)
Sales of Minerals in Place | MBbls		(4,787)	(29)	(73)
Proved Developed and Undeveloped Reserves | MBbls		27,663	30,207	29,009
Proved Developed Reserves (Volume) | MBbls		26,703	29,799	28,771	33,370
Proved Undeveloped Reserve (Volume) | MBbls		960	408	238	352
West Coast Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		46,506	43,124	49,346
Extensions and Discoveries		0	8	0
Revisions of Previous Estimates		3,322	6,369	(3,132)
Production Volume		(2,407)	(2,995)	(3,090)
Sales of Minerals in Place		(10,581)	0	0
Proved Developed and Undeveloped Reserves		36,840	46,506	43,124
Proved Developed Reserves (Volume)		36,840	46,506	43,124	49,346
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		30,179	28,936	33,502
Extensions and Discoveries | MBbls		2,301	674	530
Revisions of Previous Estimates | MBbls		2,487	3,305	(2,201)
Production Volume		(2,531)	(2,736)	(2,895)
Sales of Minerals in Place | MBbls		(4,787)	0	0
Proved Developed and Undeveloped Reserves | MBbls		27,649	30,179	28,936
Proved Developed Reserves (Volume) | MBbls		26,689	29,771	28,698	33,150
Proved Undeveloped Reserve (Volume) | MBbls		960	408	238	352
Appalachian Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		1,926,614	1,631,451	2,092,782
Extensions and Discoveries	[1]	521,694	386,649	185,347
Revisions of Previous Estimates		90,113	84,480	(245,029)
Production Volume	[2]	(160,499)	(154,093)	(140,457)
Sales of Minerals in Place		(57,420)	(21,873)	(261,192)
Proved Developed and Undeveloped Reserves		2,320,502	1,926,614	1,631,451
Proved Developed Reserves (Volume)		1,569,692	1,316,596	1,089,492	1,267,498
Proved Undeveloped Reserve (Volume)		750,810	610,018	541,959	825,284
Appalachian Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		28	73	220
Extensions and Discoveries | MBbls		0	0	0
Revisions of Previous Estimates | MBbls		(10)	(12)	(46)
Production Volume		(4)	(4)	(28)
Sales of Minerals in Place | MBbls		0	(29)	(73)
Proved Developed and Undeveloped Reserves | MBbls		14	28	73
Proved Developed Reserves (Volume) | MBbls		14	28	73	220
Proved Undeveloped Reserve (Volume) | MBbls		0	0	0	0
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		394	456	542
Marcellus Shale Fields [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		274,000	181,000	179,000
Production Volume		(150,196)	(145,452)	(135,598)
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		357	154
Utica Shale [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		248,000	205,000	6,000
Production Volume		(9,409)
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15.00%
[1]	Extensions and discoveries include 179 Bcf (during 2016), 181 Bcf (during 2017) and 274 Bcf (during 2018), of Marcellus Shale gas in the Appalachian region. Extensions and discoveries include 6 Bcf (during 2016), 205 Bcf (during 2017) and 248 Bcf (during 2018), of Utica Shale gas in the Appalachian region.
[2]	Production includes 135,598 MMcf (during 2016), 145,452 MMcf (during 2017) and 150,196 MMcf (during 2018), from Marcellus Shale fields (which exceed 15% of total reserves). Production includes 9,409 MMcf (during 2018), from Utica Shale fields (which exceed 15% of total reserves).

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, 2018	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Future Cash Inflows	$ 7,822,855	$ 6,144,317	$ 3,768,463
Future Production Costs	2,606,411	2,378,262	1,994,916
Future Development Costs	559,707	411,578	375,152
Future Income Tax Expense at Applicable Statutory Rate	1,125,910	1,160,469	303,397
Future Net Cash Flows	3,530,827	2,194,008	1,094,998
10% Annual Discount for Estimated Timing of Cash Flows	1,810,522	1,080,962	452,470
Standardized Measure of Discounted Future Net Cash Flows	$ 1,720,305	$ 1,113,046	$ 642,528	$ 1,323,034

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, 2018	Sep. 30, 2017	Sep. 30, 2016
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$ 1,113,046	$ 642,528	$ 1,323,034
Sales, Net of Production Costs	(381,775)	(345,075)	(218,444)
Net Changes in Prices, Net of Production Costs	541,021	828,187	(1,066,593)
Extensions and Discoveries	212,494	170,500	47,742
Changes in Estimated Future Development Costs	(43,771)	8,816	143,752
Sales of Minerals in Place	(100,816)	(9,849)	(95,849)
Previously Estimated Development Costs Incurred	182,348	101,134	92,840
Net Change in Income Taxes at Applicable Statutory Rate	55,558	(393,353)	387,739
Revisions of Previous Quantity Estimates	61,363	39,078	6,202
Accretion of Discount and Other	80,837	71,080	22,105
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$ 1,720,305	$ 1,113,046	$ 642,528

Valuation And Qualifying Acco_2

Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Allowance for Uncollectible Accounts [Member]
Valuation and Qualifying Accounts [Line Items]
Balance at Beginning of Period		$ 22,526	$ 21,109	$ 29,029
Additions Charged to Costs and Expenses		10,905	6,301	6,819
Additions Charged to Other Accounts	[1]	1,967	1,774	1,521
Deductions	[2]	10,861	6,658	16,260
Balance at End of Period		24,537	22,526	$ 21,109
Valuation Allowance for Deferred Tax Assets [Member]
Valuation and Qualifying Accounts [Line Items]
Balance at Beginning of Period	[3]	0
Additions Charged to Costs and Expenses	[3]	5,000
Additions Charged to Other Accounts	[1],[3]	0
Deductions	[2],[3]	0
Balance at End of Period	[3]	$ 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.
[3]	Valuation allowance recorded to reflect the potential sequestration of estimated alternative minimum tax credit refunds as a result of the 2017 Tax Reform Act.