National Fuel Gas (NFG) 10-K 17 Nov 17 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2017	Oct. 31, 2017	Mar. 31, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2,017
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		85,582,201
Entity Public Float			$ 4,970,818,000
Entity Current Reporting Status	Yes
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No

Consolidated Statements Of Inco

Consolidated Statements Of Income And Earnings Reinvested In The Business - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
INCOME
Operating Revenues	$ 1,579,881	$ 1,452,416	$ 1,760,913
Operating Expenses:
Purchased Gas	275,254	147,982	349,984
Property, Franchise and Other Taxes	84,995	81,714	89,564
Depreciation, Depletion and Amortization	224,195	249,417	336,158
Impairment of Oil and Gas Producing Properties	0	948,307	1,126,257
Total Operating Expenses	1,027,036	1,868,934	2,371,966
Operating Income (Loss)	552,845	(416,518)	(611,053)
Other Income (Expense):
Other Income	7,043	9,820	8,039
Interest Income	4,113	4,235	3,922
Interest Expense on Long-Term Debt	(116,471)	(117,347)	(95,916)
Other Interest Expense	(3,366)	(3,697)	(3,555)
Income (Loss) Before Income Taxes	444,164	(523,507)	(698,563)
Income Tax Expense (Benefit)	160,682	(232,549)	(319,136)
Net Income (Loss) Available for Common Stock	283,482	(290,958)	(379,427)
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	676,361	1,103,200	1,614,361
Beginning Retained Earnings Unappropriated And Current Period Net Income Loss	959,843	812,242	1,234,934
Dividends on Common Stock	(140,090)	(135,881)	(131,734)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	31,916	0	0
Balance at End of Year	$ 851,669	$ 676,361	$ 1,103,200
Earnings Per Common Share, Basic:
Net Income (Loss) Available for Common Stock (in usd per share)	$ 3.32	$ (3.43)	$ (4.50)
Earnings Per Common Share, Diluted:
Net Income (Loss) Available for Common Stock (in usd per share)	$ 3.30	$ (3.43)	$ (4.50)
Weighted Average Number of Shares Outstanding:
Used in Basic Calculation	85,364,929	84,847,993	84,387,755
Used in Diluted Calculation	86,021,386	84,847,993	84,387,755
Utility and Energy Marketing [Member]
INCOME
Operating Revenues	$ 755,485	$ 624,602	$ 860,618
Operating Expenses:
Operation and Maintenance	199,293	192,512	203,249
Exploration and Production and Other [Member]
INCOME
Operating Revenues	617,666	611,766	696,709
Operating Expenses:
Operation and Maintenance	145,099	160,201	184,024
Pipeline and Storage and Gathering [Member]
INCOME
Operating Revenues	206,730	216,048	203,586
Operating Expenses:
Operation and Maintenance	$ 98,200	$ 88,801	$ 82,730

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income (Loss) Available for Common Stock	$ 283,482	$ (290,958)	$ (379,427)
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	15,661	(21,378)	(31,538)
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	13,433	10,068	9,217
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	4,008	1,524	(3,234)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	5,347	60,493	381,018
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	(1,575)	(1,374)	(591)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(81,605)	(220,919)	(184,953)
Other Comprehensive Income (Loss), Before Tax	(44,731)	(171,586)	169,919
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	6,175	(8,351)	(11,922)
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	4,929	3,723	3,375
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	1,505	592	(1,195)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	2,009	18,648	160,872
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	(580)	(527)	(217)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(34,286)	(86,659)	(78,345)
Income Taxes - Net	(20,248)	(72,574)	72,568
Other Comprehensive Income (Loss)	(24,483)	(99,012)	97,351
Comprehensive Income (Loss)	$ 258,999	$ (389,970)	$ (282,076)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2017	Sep. 30, 2016
ASSETS
Property, Plant and Equipment		$ 9,945,560	$ 9,539,581
Less - Accumulated Depreciation, Depletion and Amortization		5,271,486	5,085,099
Property, Plant and Equipment, Net, Total		4,674,074	4,454,482
Cash and Temporary Cash Investments		555,530	129,972
Current Assets
Hedging Collateral Deposits	[1]	1,741	1,484
Receivables - Net of Allowance for Uncollectible Accounts of $22,526 and $21,109, Respectively		112,383	133,201
Unbilled Revenue		22,883	18,382
Gas Stored Underground		35,689	34,332
Materials and Supplies - at average cost		33,926	33,866
Unrecovered Purchased Gas Costs		4,623	2,440
Other Current Assets		51,505	59,354
Total Current Assets		818,280	413,031
Other Assets
Recoverable Future Taxes		181,363	177,261
Unamortized Debt Expense		1,159	1,688
Other Regulatory Assets		174,433	320,750
Deferred Charges		30,047	20,978
Other Investments		125,265	110,664
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		56,370	17,649
Fair Value of Derivative Financial Instruments		36,111	113,804
Other		742	604
Total Other Assets		610,966	768,874
Total Assets		6,103,320	5,636,387
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 85,543,125 Shares and 85,118,886 Shares, Respectively		85,543	85,119
Paid In Capital		796,646	771,164
Earnings Reinvested in the Business		851,669	676,361
Accumulated Other Comprehensive Loss		(30,123)	(5,640)
Total Comprehensive Shareholders' Equity		1,703,735	1,527,004
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,083,681	2,086,252
Total Capitalization		3,787,416	3,613,256
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		0	0
Current Portion of Long-Term Debt	[2]	300,000	0
Accounts Payable		126,443	108,056
Amounts Payable to Customers		0	19,537
Dividends Payable		35,500	34,473
Interest Payable on Long-Term Debt		35,031	34,900
Customer Advances		15,701	14,762
Customer Security Deposits		20,372	16,019
Other Accruals and Current Liabilities		111,889	74,430
Fair Value of Derivative Financial Instruments		1,103	1,560
Total Current and Accrued Liabilities		646,039	303,737
Deferred Credits
Deferred Income Taxes		891,287	823,795
Taxes Refundable to Customers		95,739	93,318
Cost of Removal Regulatory Liability		204,630	193,424
Other Regulatory Liabilities		113,716	99,789
Pension and Other Post-Retirement Liabilities		149,079	277,113
Asset Retirement Obligations		106,395	112,330
Other Deferred Credits		109,019	119,625
Total Deferred Credits		1,669,865	1,719,394
Commitments and Contingencies (Note I)		0	0
Total Capitalization and Liabilities		$ 6,103,320	$ 5,636,387
[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 scheduled to mature in April 2018. The Company redeemed these 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, 2017	Sep. 30, 2016
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 22,526	$ 21,109
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	85,543,125	85,118,886
Common Stock, Shares Outstanding	85,543,125	85,118,886

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Operating Activities
Net Income (Loss) Available for Common Stock	$ 283,482	$ (290,958)	$ (379,427)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	0	948,307	1,126,257
Depreciation, Depletion and Amortization	224,195	249,417	336,158
Deferred Income Taxes	117,975	(246,794)	(357,587)
Excess Tax Benefits Associated with Stock-Based Compensation Awards	0	(1,868)	(9,064)
Stock-Based Compensation	12,262	5,755	3,208
Other	16,476	12,620	9,823
Change in:
Hedging Collateral Deposits	(257)	9,640	(8,390)
Receivables and Unbilled Revenue	(3,380)	(6,408)	51,638
Gas Stored Underground and Materials and Supplies	(1,417)	(3,532)	3,438
Unrecovered Purchased Gas Costs	(2,183)	(2,440)	0
Other Current Assets	7,849	3,179	3,150
Accounts Payable	17,192	(40,664)	34,687
Amounts Payable to Customers	(19,537)	(37,241)	23,033
Customer Advances	939	(1,474)	(2,769)
Customer Security Deposits	4,353	(471)	729
Other Accruals and Current Liabilities	27,004	3,453	(7,173)
Other Assets	(2,885)	1,941	2,696
Other Liabilities	2,183	(13,483)	23,173
Net Cash Provided by Operating Activities	684,251	588,979	853,580
Investing Activities
Capital Expenditures	(450,335)	(581,576)	(1,018,179)
Net Proceeds from Sale of Oil and Gas Producing Properties	26,554	137,316	0
Other	1,216	(9,236)	(6,611)
Net Cash Used in Investing Activities	(422,565)	(453,496)	(1,024,790)
Financing Activities
Change in Notes Payable to Banks and Commercial Paper	0	0	(85,600)
Excess Tax Benefits Associated with Stock-Based Compensation Awards	0	1,868	9,064
Net Proceeds from Issuance of Long-Term Debt	295,151	0	444,635
Net Proceeds from Issuance of Common Stock	7,784	13,849	10,540
Dividends Paid on Common Stock	(139,063)	(134,824)	(130,719)
Net Cash Provided by (Used in) Financing Activities	163,872	(119,107)	247,920
Net Increase in Cash and Temporary Cash Investments	425,558	16,376	76,710
Cash and Temporary Cash Investments At Beginning of Year	129,972	113,596	36,886
Cash and Temporary Cash Investments At End of Year	555,530	129,972	113,596
Supplemental Disclosure of Cash Flow Information
Cash Paid for Interest	116,894	119,563	90,747
Cash Paid for Income Taxes	34,826	34,240	18,657
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities
Non-Cash Capital Expenditures	72,216	60,434	118,959
Receivable from Sale of Oil and Gas Producing Properties	$ 0	$ 19,543	$ 0

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2017
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. Reclassification Certain prior year amounts have been reclassified to conform with current year presentation. 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 M — Supplementary Information for Oil and Gas Producing Activities. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10% , which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The 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, 2017, the ceiling exceeded the book value of the oil and gas properties by $286.4 million . In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2017 , 2016 , and 2015 , estimated future net cash flows were increased by $30.5 million , $215.3 million and $194.5 million , respectively. 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 will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $262.6 million as of September 30, 2017, which includes $163.9 million of cash ( $137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) that Seneca had received in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 75 joint development wells. The cash proceeds were recorded by Seneca as a $163.9 million reduction of property, plant and equipment. The remainder funded joint development expenditures. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (which results in a 26% net revenue interest) in 56 of the joint development wells. 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 2017 2016 (Thousands) Exploration and Production $ 4,925,409 $ 4,645,226 Pipeline and Storage 2,002,736 1,956,708 Gathering 484,768 454,343 Utility 2,045,074 1,998,605 Energy Marketing 3,564 3,528 All Other and Corporate 109,128 109,455 $ 9,570,679 $ 9,167,865 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2017 2016 2015 Exploration and Production, per Mcfe(1) $ 0.65 $ 0.87 $ 1.52 Pipeline and Storage 2.2 % 2.4 % 2.4 % Gathering 3.4 % 4.0 % 4.0 % Utility 2.8 % 2.7 % 2.6 % Energy Marketing 7.9 % 7.9 % 6.1 % All Other and Corporate 1.3 % 1.8 % 1.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63 , $0.85 and $1.49 per Mcfe of production in 2017 , 2016 and 2015 , respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2017 and 2016 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, 2017 , 2016 and 2015 , 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, 2017, 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, 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 ) Year Ended September 30, 2016 Balance at October 1, 2015 $ 157,197 $ 5,969 $ (69,794 ) $ 93,372 Other Comprehensive Gains and Losses Before Reclassifications 41,845 932 (13,027 ) 29,750 Amounts Reclassified From Other Comprehensive Loss (134,260 ) (847 ) 6,345 (128,762 ) Balance at September 30, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) 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 $1.2 million and $1.3 million at September 30, 2017 and 2016, respectively. The total amount for accumulated losses was $57.3 million and $75.2 million at September 30, 2017 and 2016, 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, 2017 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 2017 2016 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $83,983 $216,823 Operating Revenues Commodity Contracts (1,921 ) 4,520 Purchased Gas Foreign Currency Contracts (457 ) (424 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale 1,575 1,374 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit (288 ) (333 ) (1) Net Actuarial Loss (13,145 ) (9,735 ) (1) 69,747 212,225 Total Before Income Tax (29,937 ) (83,463 ) Income Tax Expense $39,810 $128,762 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 $26.7 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 2017, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $17.1 million at September 30, 2017. 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, 2017, the remaining weighted average amortization period for such costs was approximately 2 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 investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction. 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 2017 2016 (Thousands) Prepayments $ 10,927 $ 10,919 Prepaid Property and Other Taxes 13,974 13,138 Federal Income Taxes Receivable — 11,758 State Income Taxes Receivable 9,689 3,961 Fair Values of Firm Commitments 1,031 3,962 Regulatory Assets 15,884 15,616 $ 51,505 $ 59,354 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2017 2016 (Thousands) Accrued Capital Expenditures $ 37,382 $ 26,796 Regulatory Liabilities 34,059 14,725 Federal Income Taxes Payable 1,775 — Other 38,673 32,909 $ 111,889 $ 74,430 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, 2017 and 2016, customers in the balanced billing programs had advanced excess funds of $15.7 million and $14.8 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, 2017 and 2016, the Company had received customer security deposits amounting to $20.4 million and $16.0 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 has outstanding are stock options, SARs, restricted stock units and performance shares. For the year ended September 30, 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 157,649 shares excluded as being antidilutive for the year ended September 30, 2017. As the Company recognized net losses for the years ended September 30, 2016 and 2015, the aforementioned potentially dilutive securities, amounting to 431,408 shares and 709,063 shares, respectively, were not recognized in the diluted earnings per share calculation for 2016 and 2015. Stock-Based Compensation The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, 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. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR 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 stock options and SARs. 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 option and 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 Option and 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 original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance. In May 2015, the FASB issued authoritative guidance related to the presentation of investments for which fair value was measured using net asset value per share (or its equivalent). In fiscal 2017, the Company adopted this authoritative guidance. As a result, the presentation of Retirement Plan Investments and Other Post-Retirement Benefit Assets has been adjusted (see tables in Note H — Retirement Plan and Other Post-Retirement Benefits). In February 2016, the FASB issued authoritative guidance 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

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Sep. 30, 2017
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 and services 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 2017 2016 2015 (Thousands) Balance at Beginning of Year $ 112,330 $ 156,805 $ 117,713 Liabilities Incurred 2,963 2,719 4,433 Revisions of Estimates (10,578 ) 16,721 33,717 Liabilities Settled (4,967 ) (72,215 ) (6,825 ) Accretion Expense 6,647 8,300 7,767 Balance at End of Year $ 106,395 $ 112,330 $ 156,805

Regulatory Matters

Regulatory Matters	12 Months Ended
	Sep. 30, 2017
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 2017 2016 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note H) $ 125,175 $ 203,755 Post-Retirement Benefit Costs(2) (Note H) 13,886 74,802 Recoverable Future Taxes (Note D) 181,363 177,261 Environmental Site Remediation Costs(2) (Note I) 19,665 23,392 Asset Retirement Obligations(2) (Note B) 12,764 12,490 Unamortized Debt Expense (Note A) 1,159 1,688 Other(3) 18,827 21,927 Total Regulatory Assets 372,839 515,315 Less: Amounts Included in Other Current Assets (15,884 ) (15,616 ) Total Long-Term Regulatory Assets $ 356,955 $ 499,699 At September 30 2017 2016 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 204,630 $ 193,424 Taxes Refundable to Customers (Note D) 95,739 93,318 Post-Retirement Benefit Costs (Note H) 102,891 67,204 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) — 19,537 Other(4) 44,884 47,310 Total Regulatory Liabilities 448,144 420,793 Less: Amounts included in Current and Accrued Liabilities (34,059 ) (34,262 ) Total Long-Term Regulatory Liabilities $ 414,085 $ 386,531 (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) $15,884 and $15,616 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $2,943 and $6,311 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively. (4) $34,059 and $14,725 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $10,825 and $32,585 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, 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. NYPSC Rate Proceeding On April 28, 2016, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million . Distribution Corporation explained in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense, among other things. On January 23, 2017, the administrative law judge assigned to the proceeding issued a recommended decision (RD) in the case. The RD, as revised on January 26, 2017, recommended a rate increase designed to provide additional annual revenues of $8.5 million , an equity ratio, subject to update of 42.3% based on the Company’s equity ratio, and a cost of equity, subject to update of 8.6% . On April 20, 2017, the NYPSC issued an Order adopting some provisions of the RD and modifying or rejecting others. The Order provides for an annual rate increase of $5.9 million . The rate increase became effective May 1, 2017. The Order further provides for a return on equity of 8.7% , and established an equity ratio of 42.9% . The Order also directs the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On July 28, 2017, Distribution Corporation filed an appeal with New York State Supreme Court, Albany County, seeking review of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On October 13, 2017, the NYPSC filed an answer which contained a request that the appeal be transferred to the Appellate Division. The Company cannot predict the outcome of the appeal at this time. FERC Rate Proceedings 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. Empire currently has no active rate case on file. Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The components of federal and state income taxes included in the Consolidated Statements of Income are as follows: Year Ended September 30 2017 2016 2015 (Thousands) Current Income Taxes — Federal $ 32,034 $ (6,658 ) $ 25,064 State 10,673 20,903 13,387 Deferred Income Taxes — Federal 103,046 (164,818 ) (244,336 ) State 14,929 (81,976 ) (113,251 ) 160,682 (232,549 ) (319,136 ) Deferred Investment Tax Credit (173 ) (348 ) (414 ) Total Income Taxes $ 160,509 $ (232,897 ) $ (319,550 ) Presented as Follows: Other Income $ (173 ) $ (348 ) $ (414 ) Income Tax Expense (Benefit) 160,682 (232,549 ) (319,136 ) Total Income Taxes $ 160,509 $ (232,897 ) $ (319,550 ) 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 2017 2016 2015 (Thousands) U.S. Income (Loss) Before Income Taxes $ 443,991 $ (523,855 ) $ (698,977 ) Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35% $ 155,397 $ (183,349 ) $ (244,642 ) State Income Taxes (Benefit) 16,641 (39,697 ) (64,912 ) Federal Tax Credits (6,679 ) (3,262 ) (732 ) Miscellaneous (4,850 ) (6,589 ) (9,264 ) Total Income Taxes $ 160,509 $ (232,897 ) $ (319,550 ) The 2017 state income taxes (benefit) shown above includes income tax benefits related to state enhanced oil recovery tax credits and a decrease in 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 2017 2016 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 1,141,432 $ 1,049,100 Pension and Other Post-Retirement Benefit Costs 79,516 151,903 Unrealized Hedging Gains 19,127 50,179 Other 57,919 55,457 Total Deferred Tax Liabilities 1,297,994 1,306,639 Deferred Tax Assets: Pension and Other Post-Retirement Benefit Costs (123,532 ) (195,829 ) Tax Loss and Credit Carryforwards (200,344 ) (194,875 ) Other (82,831 ) (92,140 ) Total Deferred Tax Assets (406,707 ) (482,844 ) Total Net Deferred Income Taxes $ 891,287 $ 823,795 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. As of September 30, 2016, the table of deferred tax liabilities and assets shown above does not include deferred tax assets of $31.9 million that arose directly from excess tax benefits related to stock-based compensation in prior periods. This amount was recognized 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 $95.7 million and $93.3 million at September 30, 2017 and 2016, 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 $181.4 million and $177.3 million at September 30, 2017 and 2016, respectively. Included in the above are regulatory liabilities and assets relating to the tax accounting method change noted below. The amounts are as follows: regulatory liabilities of $52.6 million as of September 30, 2017 and 2016 and regulatory assets of $99.4 million and $94.2 million as of September 30, 2017 and 2016, respectively. The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2017 2016 2015 (Thousands) Balance at Beginning of Year $ 396 $ 5,085 $ 3,147 Additions for Tax Positions of Prior Years 1,251 396 2,504 Reductions for Tax Positions of Prior Years (396 ) (1,314 ) (566 ) Reductions Related to Settlements with Taxing Authorities — (3,771 ) — Balance at End of Year $ 1,251 $ 396 $ 5,085 As a result of certain examinations in progress (discussed below), the Company anticipates the balance of unrecognized tax benefits could be reduced during the next 12 months. As of September 30, 2017, the entire balance of unrecognized tax benefits would favorably impact the effective tax rate, if recognized. The IRS is currently conducting examinations of the Company for fiscal 2017 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 and later years. During fiscal 2009, 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. While local IRS examiners issued no-change reports for fiscal 2009 through 2016, the IRS has reserved the right to re-examine these years, pending the anticipated 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, 2017, the Company has the following carryforwards available: Jurisdiction Tax Attribute Amount (Thousands) Expires Federal Net Operating Loss $ 184,289 2028-2033 Pennsylvania Net Operating Loss 324,572 2030-2035 California Net Operating Loss 169,723 2029-2035 Federal Alternative Minimum Tax Credit 81,683 Unlimited California Alternative Minimum Tax Credit 5,873 Unlimited Federal Enhanced Oil Recovery Credit 10,502 2029-2037 California Enhanced Oil Recovery Credit 5,061 2021-2037 Federal R&D Tax Credit 5,694 2031-2036 Approximately $1.8 million of the federal Net Operating Loss carryforward is subject to certain annual limitations. Subsequent to year-end, federal tax reform legislation was introduced which could have a material effect on the Company if enacted into law.

Capitalization And Short-Term B

Capitalization And Short-Term Borrowings	12 Months Ended
	Sep. 30, 2017
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, 2014 84,157 $ 84,157 $ 716,144 $ 1,614,361 $ (3,979 ) Net Income (Loss) Available for Common Stock (379,427 ) Dividends Declared on Common Stock ($1.56 Per Share) (131,734 ) Other Comprehensive Income, Net of Tax 97,351 Share-Based Payment Expense(2) 2,207 Common Stock Issued Under Stock and Benefit Plans(1) 437 437 25,923 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 (3) $ (30,123 ) (1) Paid in Capital includes tax benefits of $1.9 million and $9.1 million for September 30, 2016 and 2015, respectively, related to stock-based compensation. (2) Paid in Capital includes compensation costs associated with stock option, SARs, performance share 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, 2017, $707.5 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 2017, the Company issued 180,247 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 103,602 original issue shares of common stock for the Company's 401(k) plans. During 2017, the Company issued 45,912 original issue shares of common stock as a result of stock option and SARs exercises, 80,530 original issue shares of common stock for restricted stock units that vested and 43,484 original issue shares of common stock for performance shares that vested. Holders of stock options, SARs, restricted share awards or restricted stock units will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During 2017, 53,564 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 24,028 original issue shares of common stock during 2017. Shareholder Rights Plan In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). The Plan has been amended several times since it was adopted and is now embodied in an Amended and Restated Rights Agreement effective December 4, 2008, a copy of which was included as an exhibit to the Form 8-K filed by the Company on December 4, 2008. Pursuant to the Plan, the holders of the Company’s common stock have one right (Right) for each of their shares. Each Right is initially evidenced by the Company’s common stock certificates representing the outstanding shares of common stock. The Rights have anti-takeover effects because they will cause substantial dilution of the Company’s common stock if a person (an Acquiring Person) attempts to acquire the Company on terms not approved by the Board of Directors. The Rights become exercisable upon the occurrence of a Distribution Date as described below, but after a Distribution Date, Rights that are owned by an Acquiring Person will be null and void. At any time following a Distribution Date, each holder of a Right may exercise its right to receive, upon payment of an amount calculated under the Rights Agreement, common stock of the Company (or, under certain circumstances, other securities or assets of the Company) having a value equal to two times the amount paid to exercise the Right. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below. A Distribution Date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock (including Synthetic Long Positions as defined in the Plan) having 10% or more of the total voting power of the Company’s common stock and other voting stock or (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquiring, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock. In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to receive, upon exercise of the Right, common stock of the acquiring company having a value equal to two times the amount paid to exercise the Right. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power is sold or transferred. At any time prior to the end of the business day on the tenth day following the Distribution Date, the Company may redeem the Rights in whole, but not in part, at a price of $0.005 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the Distribution Date, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments. Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2018 , unless earlier than that date, they are exchanged or redeemed or the Plan is amended to extend the expiration date. Stock Option and Stock Award Plans The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, restricted stock, restricted stock units, performance units or performance shares. Stock-based compensation expense for the years ended September 30, 2017, 2016 and 2015 was approximately $10.8 million , $4.8 million and $2.1 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, 2017, 2016 and 2015 was approximately $4.4 million , $1.9 million and $0.9 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, 2017, 2016 and 2015, respectively. The tax benefit recognized from stock-based compensation exercises and vestings was $0.5 million for the year ended September 30, 2017. Stock Options Transactions involving option shares 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, 2016 19,000 $ 39.48 Granted in 2017 — $ — Exercised in 2017 (19,000 ) $ 39.48 Forfeited in 2017 — $ — Outstanding at September 30, 2017 — $ — — $ — Option shares exercisable at September 30, 2017 — $ — — $ — Shares available for future grant at September 30, 2017(1) 2,182,243 (1) Includes shares available for options, SARs, restricted stock and performance share grants. The total intrinsic value of stock options exercised during the years ended September 30, 2017, 2016 and 2015 totaled approximately $0.3 million , $4.1 million , and $5.1 million , respectively. For 2017, 2016 and 2015, the amount of cash received by the Company from the exercise of such stock options was approximately $0.8 million , $8.0 million , and $5.6 million , respectively. The Company last granted stock options in fiscal 2007 and all stock options have been fully vested since fiscal 2010. SARs Transactions 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, 2016 1,590,988 $ 48.19 Granted in 2017 — $ — Exercised in 2017 (82,077 ) $ 39.77 Forfeited in 2017 — $ — Expired in 2017 (3,000 ) $ 52.10 Outstanding at September 30, 2017 1,505,911 $ 48.64 2.52 $ 13,144 SARs exercisable at September 30, 2017 1,505,911 $ 48.64 2.52 $ 13,144 The Company did not grant any SARs during the years ended September 30, 2016 and 2015. 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, 2017, 2016 and 2015 totaled approximately $1.6 million , $0.4 million , and $2.0 million , respectively. For the years ended September 30, 2017, 2016 and 2015, 5,000 SARs, 113,082 SARs and 157,386 SARs, respectively, became fully vested. The total fair value of the SARs that became vested during each of the years ended September 30, 2017, 2016 and 2015 was approximately $0.1 million , $1.2 million and $1.7 million , respectively. Restricted Share Awards Transactions 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, 2016 20,000 $ 47.46 Granted in 2017 — $ — Vested in 2017 — $ — Forfeited in 2017 — $ — Outstanding at September 30, 2017 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, 2016 and 2015. As of September 30, 2017, unrecognized compensation expense related to restricted share awards totaled approximately $0.3 million , which will be recognized over a weighted average period of 3.1 years . Vesting restrictions for the 20,000 outstanding shares of non-vested restricted stock at September 30, 2017 will lapse in 2021. Restricted Stock Units Transactions 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, 2016 239,151 $ 49.67 Granted in 2017 87,143 $ 52.13 Vested in 2017 (80,530 ) $ 53.38 Forfeited in 2017 (12,565 ) $ 53.75 Outstanding at September 30, 2017 233,199 $ 48.99 The Company also granted 101,943 and 88,899 non-performance based restricted stock units during the years ended September 30, 2016 and 2015, respectively. The weighted average fair value of such non-performance based restricted stock units granted in 2016 and 2015 was $35.89 per share and $64.04 per share, respectively. As of September 30, 2017, unrecognized compensation expense related to non-performance based restricted stock units totaled approximately $4.7 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, 2017 will lapse as follows: 2018 — 73,819 units; 2019 — 65,265 units; 2020 — 52,641 units; 2021 - 27,976 units; and 2022 - 13,498 units. Performance Shares Transactions involving performance shares for all plans are summarized as follows: Number of Performance Shares Weighted Average Fair Value per Award Outstanding at September 30, 2016 438,234 $ 44.98 Granted in 2017 184,148 $ 56.39 Vested in 2017 (43,484 ) $ 69.13 Forfeited in 2017 (51,150 ) $ 60.74 Outstanding at September 30, 2017 527,748 $ 45.44 The Company also granted 309,996 and 107,044 performance shares during the years ended September 30, 2016 and 2015, respectively. The weighted average grant date fair value of such performance shares granted in 2016 and 2015 was $30.71 per share and $65.26 per share, respectively. As of September 30, 2017, unrecognized compensation expense related to performance shares totaled approximately $10.1 million , which will be recognized over a weighted average period of 1.7 years . Vesting restrictions for the outstanding performance shares at September 30, 2017 will lapse as follows: 2018 - 88,132 shares; 2019 - 255,468 shares; and 2020 - 184,148 shares. Half of the performance shares granted during the year ended September 30, 2017 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2016 to September 30, 2019. In addition, half of the performance shares granted during the year ended September 30, 2016 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2015 to September 30, 2018, and half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2014 to September 30, 2017. The performance goals over their respective performance cycles for these performance shares granted during 2017, 2016 and 2015 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 year ended September 30, 2017 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2016 to September 30, 2019. In addition, the other half of the performance shares granted during the year ended September 30, 2016 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2015 to September 30, 2018, and the other half of the performance shares granted during the year ended September 30, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2014 to September 30, 2017. The performance goals over their respective performance cycles for these total shareholder return performance shares ("TSR performance shares") granted during 2017, 2016 and 2015 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 2017 2016 2015 Risk-Free Interest Rate 1.54 % 1.26 % 1.01 % Remaining Term at Date of Grant (Years) 2.79 2.79 2.78 Expected Volatility 22.6 % 20.5 % 20.1 % Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2017, 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 2017 2016 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(3)(4): 3.75% to 8.75% due April 2018 to September 2027 2,300,000 2,000,000 Total Long-Term Debt 2,399,000 2,099,000 Less Unamortized Discount and Debt Issuance Costs 15,319 12,748 Less Current Portion(2) 300,000 — $ 2,083,681 $ 2,086,252 (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 scheduled to mature in April 2018. The Company redeemed these 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 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 September 18, 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 of September 30, 2017, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: $300.0 million in 2018, $250.0 million in 2019, zero in 2020 and 2021, $500.0 million in 2022, and $1,349.0 million thereafter. Short-Term Borrowings The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On September 9, 2016, the Company entered into a Third Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of what now numbers 13 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019. The Credit Agreement also provided a $500.0 million 364-day unsecured committed revolving credit facility with 11 of the 13 banks, which expired on September 8, 2017 and was not subsequently renewed. The Company also has a number of individual uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under the uncommitted lines of credit are made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. The total amount available to be issued under the Company’s commercial paper program is $500.0 million . At September 30, 2017, 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, 2017 and 2016. Debt Restrictions The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .675 at the last day of any fiscal quarter through September 30, 2017 , or .65 at the last day of any fiscal quarter from October 1, 2017 through December 5, 2019 . At September 30, 2017, the Company’s debt to capitalization ratio (as calculated under the facility) was .58 . The constraints specified in the Credit Agreement would have permitted an additional $1.15 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 .675 . 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, 2017, the Company had no debt outstanding under the Credit Agreement. Under the Company’s existing indenture covenants, at September 30, 2017, the Company would have been permitted to issue up to a maximum of $126.0 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. 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. The Company's present liquidity position is believed to be adequate to satisfy known demands. The Company’s 1974 indenture pursuant to which $98.7 million (or 4.1% ) of the Company’s long-term debt (as of September 30, 2017) 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, 2017
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, 2017 and 2016. 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, 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 At Fair Value as of September 30, 2016 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 $ 113,407 $ — $ — $ — $ 113,407 Derivative Financial Instruments: Commodity Futures Contracts — Gas 2,623 — — (2,276 ) 347 Over the Counter Swaps — Gas and Oil — 119,654 — (3,860 ) 115,794 Foreign Currency Contracts — — — (2,337 ) (2,337 ) Other Investments: Balanced Equity Mutual Fund 36,658 — — — 36,658 Fixed Income Mutual Fund 31,395 — — — 31,395 Common Stock — Financial Services Industry 2,902 — — — 2,902 Hedging Collateral Deposits 1,484 — — — 1,484 Total $ 188,469 $ 119,654 $ — $ (8,473 ) $ 299,650 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 2,276 $ — $ — $ (2,276 ) $ — Over the Counter Swaps — Gas and Oil — 5,322 — (3,860 ) 1,462 Foreign Currency Contracts — 2,337 — (2,337 ) — Total $ 2,276 $ 7,659 $ — $ (8,473 ) $ 1,462 Total Net Assets/(Liabilities) $ 186,193 $ 111,995 $ — $ — $ 298,188 (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, 2017 and 2016, 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 $1.7 million (at September 30, 2017) and $1.5 million (at September 30, 2016), 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, 2017 and 2016 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, the majority of 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, 2017, 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, 2017 and 2016, there were no assets or liabilities measured at fair value and classified as Level 3. The Company's Exploration and Production segment had a small portion of their crude oil price swap agreements reported as Level 3 at October 1, 2015 that settled during the first quarter of fiscal 2016. For the years ended September 30, 2017 and September 30, 2016, no transfers in or out of Level 1 or Level 2 occurred.

Financial Instruments

Financial Instruments	12 Months Ended
	Sep. 30, 2017
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 2017 Carrying Amount 2017 Fair Value 2016 Carrying Amount 2016 Fair Value (Thousands) Long-Term Debt $ 2,383,681 $ 2,523,639 $ 2,086,252 $ 2,255,562 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 Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices. Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $39.4 million and $39.7 million at September 30, 2017 and 2016, respectively. The fair value of the equity mutual fund was $37.0 million and $36.7 million at September 30, 2017 and 2016, respectively. The gross unrealized gain on this equity mutual fund was $9.9 million at September 30, 2017 and $7.9 million at September 30, 2016. The fair value of the fixed income mutual fund was $45.7 million and $31.4 million at September 30, 2017 and 2016, respectively. The gross unrealized loss on this fixed income mutual fund was less than $0.1 million at September 30, 2017 and the gross unrealized gain on this fixed income mutual fund was less than $0.1 million at September 30, 2016. The fair value of the stock of an insurance company was $3.2 million and $2.9 million at September 30, 2017 and 2016, respectively. The gross unrealized gain on this stock was $2.2 million and $1.6 million at September 30, 2017 and 2016, 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 6 years while the foreign currency forward contracts do not exceed 9 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, 2017 and September 30, 2016 . 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, 2017 , the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding: Commodity Units Natural Gas 114.3 Bcf (short positions) Natural Gas 1.0 Bcf (long positions) Crude Oil 3,459,000 Bbls (short positions) As of September 30, 2017, the Company was hedging a total of $89.2 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions). As of September 30, 2017, the Company had $35.5 million ( $20.8 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $18.0 million ( $10.6 million after tax) of such unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2017 and 2016 (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, 2017 2016 2017 2016 2017 2016 Commodity Contracts $ 2,811 $ 58,714 Operating Revenue $ 83,983 $ 216,823 Operating Revenue $ (100 ) $ 392 Commodity Contracts (164 ) 1,585 Purchased Gas (1,921 ) 4,520 Not Applicable — — Foreign Currency Contracts 2,700 194 Operation and Maintenance Expense (457 ) (424 ) Not Applicable — — Total $ 5,347 $ 60,493 $ 81,605 $ 220,919 $ (100 ) $ 392 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, 2017, the Company’s Energy Marketing segment had fair value hedges covering approximately 17.5 Bcf ( 16.4 Bcf of fixed price sales commitments and 1.1 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, 2017 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2017 (In thousands) Commodity Contracts Operating Revenues $ 1,655 $ (1,655 ) Commodity Contracts Purchased Gas 464 (464 ) $ 2,119 $ (2,119 ) 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 seventeen counterparties of which sixteen are in a net gain position. On average, the Company had $2.2 million of credit exposure per counterparty in a gain position at September 30, 2017. The maximum credit exposure per counterparty in a gain position at September 30, 2017 was $6.0 million . As of September 30, 2017, 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, 2017, fourteen of the seventeen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At September 30, 2017, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $26.0 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). 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, 2017. For its exchange traded futures contracts, the Company was required to post $1.7 million in hedging collateral deposits as of September 30, 2017. 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, 2017
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 $2.9 million , $2.6 million and $2.3 million for the years ended September 30, 2017, 2016 and 2015, 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 $5.9 million , $5.9 million , and $5.8 million for the years ended September 30, 2017, 2016 and 2015, 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 2017, 2016 and 2015. Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2017 2016 2015 2017 2016 2015 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 1,097,421 $ 1,026,190 $ 999,499 $ 526,138 $ 464,987 $ 465,583 Service Cost 11,969 11,710 12,047 2,449 2,331 2,693 Interest Cost 38,383 42,315 41,217 19,007 20,386 19,285 Plan Participants’ Contributions — — — 2,717 2,558 2,242 Retiree Drug Subsidy Receipts — — — 1,553 1,925 1,338 Amendments(1) — — 7,752 — — — Actuarial (Gain) Loss (32,466 ) 76,309 23,426 (62,215 ) 60,402 (1,575 ) Benefits Paid (60,481 ) (59,103 ) (57,751 ) (27,030 ) (26,451 ) (24,579 ) Benefit Obligation at End of Period $ 1,054,826 $ 1,097,421 $ 1,026,190 $ 462,619 $ 526,138 $ 464,987 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 869,775 $ 834,870 $ 869,791 $ 494,320 $ 477,959 $ 497,601 Actual Return on Plan Assets 84,279 87,008 (13,370 ) 40,157 37,415 534 Employer Contributions 17,146 7,000 36,200 3,853 2,839 2,161 Plan Participants’ Contributions — — — 2,717 2,558 2,242 Benefits Paid (60,481 ) (59,103 ) (57,751 ) (27,030 ) (26,451 ) (24,579 ) Fair Value of Assets at End of Period $ 910,719 $ 869,775 $ 834,870 $ 514,017 $ 494,320 $ 477,959 Net Amount Recognized at End of Period (Funded Status) $ (144,107 ) $ (227,646 ) $ (191,320 ) $ 51,398 $ (31,818 ) $ 12,972 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (144,107 ) $ (227,646 ) $ (191,320 ) $ (4,972 ) $ (49,467 ) $ (11,487 ) Non-Current Assets — — — 56,370 17,649 24,459 Net Amount Recognized at End of Period $ (144,107 ) $ (227,646 ) $ (191,320 ) $ 51,398 $ (31,818 ) $ 12,972 Accumulated Benefit Obligation $ 1,010,179 $ 1,039,408 $ 968,984 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 3.77 % 3.60 % 4.25 % 3.81 % 3.70 % 4.50 % Rate of Compensation Increase 4.70 % 4.70 % 4.75 % 4.70 % 4.70 % 4.75 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2017 2016 2015 2017 2016 2015 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 11,969 $ 11,710 $ 12,047 $ 2,449 $ 2,331 $ 2,693 Interest Cost 38,383 42,315 41,217 19,007 20,386 19,285 Expected Return on Plan Assets (59,718 ) (59,369 ) (59,615 ) (31,458 ) (31,535 ) (34,089 ) Amortization of Prior Service Cost (Credit) 1,058 1,234 183 (429 ) (912 ) (1,913 ) Recognition of Actuarial Loss(2) 42,687 32,248 36,129 18,415 5,530 4,148 Net Amortization and Deferral for Regulatory Purposes 469 3,957 7,739 6,108 17,123 20,322 Net Periodic Benefit Cost $ 34,848 $ 32,095 $ 37,700 $ 14,092 $ 12,923 $ 10,446 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Discount Rate 3.60 % 4.25 % 4.25 % 3.70 % 4.50 % 4.25 % Expected Return on Plan Assets 7.00 % 7.25 % 7.50 % 6.50 % 6.75 % 7.00 % Rate of Compensation Increase 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % (1) In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan. (2) Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years , as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach. The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above. In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were $7.6 million , $7.5 million and $7.0 million in 2017, 2016 and 2015, respectively. The accumulated benefit obligations for the plans were $72.5 million , $72.4 million and $66.0 million at September 30, 2017, 2016 and 2015, respectively. The projected benefit obligations for the plans were $88.9 million , $91.7 million and $85.8 million at September 30, 2017, 2016 and 2015, respectively. At September 30, 2017, $14.1 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $74.8 million is 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. At September 30, 2015, $4.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $81.3 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 3.22% , 2.80% and 3.50% as of September 30, 2017, 2016 and 2015, respectively and the weighted average rates of compensation increase for these plans were 7.75% , 7.75% and 7.75% as of September 30, 2017, 2016 and 2015, respectively. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2017, the changes in such amounts during 2017, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2018 are presented in the table below: Retirement Plan Other Post-Retirement Benefits Non-Qualified Benefit Plans (Thousands) Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) Net Actuarial Loss $ (203,887 ) $ (19,578 ) $ (24,332 ) Prior Service (Cost) Credit (6,133 ) 3,687 — Net Amount Recognized $ (210,020 ) $ (15,891 ) $ (24,332 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2017(1) Decrease (Increase) in Actuarial Loss, excluding amortization(2) $ 57,028 $ 70,915 $ (1,351 ) Change due to Amortization of Actuarial Loss 42,687 18,415 4,059 Prior Service (Cost) Credit 1,058 (429 ) — Net Change $ 100,773 $ 88,901 $ 2,708 Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (37,205 ) $ (10,558 ) $ (3,549 ) Prior Service (Cost) Credit (938 ) 429 — Net Amount Expected to be Recognized $ (38,143 ) $ (10,129 ) $ (3,549 ) (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, 2017, the Company recorded a $163.3 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $29.1 million (pre-tax) increase to Accumulated Other Comprehensive Income. 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 mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2017 by $8.3 million . In addition, other actuarial experience decreased the projected benefit obligation for the Retirement Plan in 2017 by $3.6 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 effect of the mortality assumption change for the Retirement Plan in 2015 was to increase the projected benefit obligation of the Retirement Plan by $24.2 million . The Company made cash contributions totaling $17.1 million to the Retirement Plan during the year ended September 30, 2017. The Company expects that the annual contribution to the Retirement Plan in 2018 will be in the range of $15.0 million to $40.0 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: $64.4 million in 2018; $65.0 million in 2019; $65.4 million in 2020; $65.8 million in 2021; $66.2 million in 2022; and $331.1 million in the five years thereafter. 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 effect of the discount rate change in 2015 was to decrease the other post-retirement benefit obligation by $14.3 million . Other actuarial experience increased the other post-retirement benefit obligation in 2015 by $12.8 million primarily attributable to the change in mortality assumption. 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 2018 $ 26,483 $ (1,910 ) 2019 $ 27,456 $ (2,074 ) 2020 $ 28,359 $ (2,225 ) 2021 $ 29,173 $ (2,369 ) 2022 $ 29,757 $ (2,515 ) 2023 through 2027 $ 152,957 $ (14,271 ) Assumed health care cost trend rates as of September 30 were: 2017 2016 2015 Rate of Medical Cost Increase for Pre Age 65 Participants 5.67 % (1) 5.75 % (1) 6.93 % (2) Rate of Medical Cost Increase for Post Age 65 Participants 4.75 % (1) 4.75 % (1) 6.68 % (2) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 8.45 % (1) 9.00 % (1) 7.17 % (2) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 4.75 % (1) 4.75 % (1) 6.68 % (2) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 7.33 % (1) 7.20 % (1) 6.65 % (2) (1) It was assumed that this rate would gradually decline to 4.5% by 2039. (2) It was assumed that this rate would gradually decline to 4.5% by 2028. 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, 2017 would increase by $57.9 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 2017 by $3.3 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, 2017 would decrease by $48.5 million . This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 2017 by $2.7 million . The Company made cash contributions totaling $3.8 million to its VEBA trusts during the year ended September 30, 2017. 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, 2017. The Company expects that the annual contribution to its VEBA trusts in 2018 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, 2017 and 2016, 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, 2017 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 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) Retirement Plan Investments Domestic Equities(1) $ 256,796 $ 188,253 $ — $ — $ 68,543 International Equities(2) 104,592 — — — 104,592 Global Equities(3) 120,025 — — — 120,025 Domestic Fixed Income(4) 342,442 1,647 340,795 — — International Fixed Income(5) 744 407 337 — — Global Fixed Income(6) 81,146 — — — 81,146 Real Estate 2,970 — — 2,970 — Cash Held in Collective Trust Funds 24,812 — — — 24,812 Total Retirement Plan Investments 933,527 190,307 341,132 2,970 399,118 401(h) Investments (58,707 ) (12,025 ) (21,555 ) (188 ) (24,939 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 874,820 $ 178,282 $ 319,577 $ 2,782 $ 374,179 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (5,045 ) Total Retirement Plan Assets $ 869,775 (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 adoption of the new 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 $ 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 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 $ 139,617 $ — $ — $ — $ 139,617 Collective Trust Funds — International Equities 51,488 — — — 51,488 Exchange Traded Funds — Fixed Income 230,761 230,761 — — — Cash Held in Collective Trust Funds 13,176 — — — 13,176 Total VEBA Trust Investments 435,042 230,761 — — 204,281 401(h) Investments 58,707 12,025 21,555 188 24,939 Total Investments (including 401(h) Investments) $ 493,749 $ 242,786 $ 21,555 $ 188 $ 229,220 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 571 Total Other Post-Retirement Benefit Assets $ 494,320 (1) Reflects the adoption of the new 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, 2017 and September 30, 2016, 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) Hedge Funds Real Estate Excluding 401(h) Investments Total Balance at September 30, 2015 $ 26,490 $ 4,724 $ (1,885 ) $ 29,329 Realized Gains/(Losses) 5,878 — (354 ) 5,524 Unrealized Gains/(Losses) (5,445 ) (404 ) 344 (5,505 ) Sales (26,923 ) (1,350 ) 1,707 (26,566 ) 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 Other Post-Retirement Benefit Level 3 Assets (Thousands) 401(h) Investments Balance at September 30, 2015 $ 1,885 Realized Gains/(Losses) 354 Unrealized Gains/(Losses) (344 ) Sales (1,707 ) Balance at September 30, 2016 188 Unrealized Gains/(Losses) 37 Balance at September 30, 2017 $ 225 The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.00% (Retirement Plan) and 6.25% (other post-retirement benefits), effective for fiscal 2018. 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 40 - 60% equity securities, 40 - 60% fixed income securities and 0 - 15% other. 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. Beginning in fiscal 2018, the Company refined the method used to determine the service and interest cost components of net periodic benefit cost. Using the refined method, known as the spot rate approach, the Company will use individual spot rates along the yield curve that correspond to the timing of each benefit payment to determine the discount rate. The individual spot rates along the yield curve will continue to be determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile will be excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities. The impact on the benefit obligation, as of September 30, 2017, is immaterial. This change will provide a more precise measurement of service and interest costs by improving the correlation between projected cash outflows and corresponding spot rates on the yield curve. Compared to the previous method, the spot rate approach will decrease the service and interest components of net periodic benefit costs in fiscal 2018. The Company will account for this change prospectively as a change in accounting estimate.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Sep. 30, 2017
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, 2017, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.1 million . This estimated liability has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2017. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 years . 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 2016 Project On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access 2016 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. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. In light of these pending legal actions, the Company has not yet determined a target in-service date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of September 30, 2017 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 successful resolution with the NYDEC and 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 $75.8 million at September 30, 2017. 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: $262.4 million in 2018, $84.6 million in 2019, $77.9 million in 2020, $70.9 million in 2021, $61.7 million in 2022 and $504.9 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers. The Company 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: $10.8 million in 2018, $4.6 million in 2019, $3.7 million in 2020, $2.2 million in 2021, $1.5 million in 2022 and $1.9 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, 2017, the future contractual commitments related to the system modernization and expansion projects are $61.7 million in 2018, $0.7 million in 2019, $0.2 million in 2020, $0.3 million in 2021, $0.3 million in 2022 and $1.1 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 $79.5 million in 2018, $98.0 million in 2019 and $17.1 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, 2017
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 Corporation’s operations. Midstream Corporation 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, 2017 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) $ 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 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) $ 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 Year Ended September 30, 2015 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) $ 693,441 $ 203,089 $ 497 $ 700,761 $ 159,857 $ 1,757,645 $ 2,352 $ 916 $ 1,760,913 Intersegment Revenues $ — $ 88,251 $ 76,709 $ 15,506 $ 849 $ 181,315 $ — $ (181,315 ) $ — Interest Income $ 2,554 $ 474 $ 140 $ 2,220 $ 195 $ 5,583 $ 66 $ (1,727 ) $ 3,922 Interest Expense $ 46,726 $ 27,658 $ 1,627 $ 28,176 $ 27 $ 104,214 $ — $ (4,743 ) $ 99,471 Depreciation, Depletion and Amortization $ 239,818 $ 38,178 $ 10,829 $ 45,616 $ 209 $ 334,650 $ 832 $ 676 $ 336,158 Income Tax Expense (Benefit) $ (428,217 ) $ 48,113 $ 24,721 $ 33,143 $ 4,547 $ (317,693 ) $ 13 $ (1,456 ) $ (319,136 ) Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ 1,126,257 $ — $ — $ — $ — $ 1,126,257 $ — $ — $ 1,126,257 Segment Profit: Net Income (Loss) $ (556,974 ) $ 80,354 $ 31,849 $ 63,271 $ 7,766 $ (373,734 ) $ (2 ) $ (5,691 ) $ (379,427 ) Expenditures for Additions to Long-Lived Assets $ 557,313 $ 230,192 $ 118,166 $ 94,371 $ 128 $ 1,000,170 $ — $ 339 $ 1,000,509 At September 30, 2015 (Thousands) Segment Assets $ 2,439,801 $ 1,590,524 $ 444,358 $ 1,934,731 $ 90,676 $ 6,500,090 $ 77,350 $ (12,501 ) $ 6,564,939 (1) All Revenue from External Customers originated in the United States. Geographic Information At September 30 2017 2016 2015 (Thousands) Long-Lived Assets: United States $ 5,285,040 $ 5,223,356 $ 6,189,138

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Sep. 30, 2017
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 (Loss) Net Income (Loss) Available for Common Stock Earnings (Loss) per Common Share Basic Diluted (Thousands, except per common share amounts) 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 2016 9/30/2016 $ 292,472 $ 81,244 $ 37,553 (1) $ 0.44 $ 0.44 6/30/2016 $ 335,617 $ 45,162 $ 8,286 (2) $ 0.10 $ 0.10 3/31/2016 $ 449,132 $ (237,000 ) $ (147,688 ) (3) $ (1.74 ) $ (1.74 ) 12/31/2015 $ 375,195 $ (305,924 ) $ (189,109 ) (4) $ (2.23 ) $ (2.23 ) (1) Includes a non-cash $32.7 million impairment charge ( $19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (2) Includes a non-cash $82.7 million impairment charge ( $47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (3) Includes a non-cash $397.4 million impairment charge ( $230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (4) Includes a non-cash $ 435.5 million impairment charge ( $252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

Market For Common Stock And Rel

Market For Common Stock And Related Shareholder Matters	12 Months Ended
	Sep. 30, 2017
Market For Common Stock And Related Shareholder Matters [Abstract]
Market For Common Stock And Related Shareholder Matters (unaudited)	Market for Common Stock and Related Shareholder Matters (unaudited) At September 30, 2017, there were 11,211 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note E — Capitalization and Short-Term Borrowings. The quarterly price ranges (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2017 and 2016, are shown below: Price Range Dividends Declared Quarter Ended High Low 2017 9/30/2017 $ 59.92 $ 54.89 $ 0.415 6/30/2017 $ 61.20 $ 53.03 $ 0.415 3/31/2017 $ 61.25 $ 54.67 $ 0.405 12/31/2016 $ 58.78 $ 50.61 $ 0.405 2016 9/30/2016 $ 59.62 $ 53.81 $ 0.405 6/30/2016 $ 57.06 $ 47.49 $ 0.405 3/31/2016 $ 51.53 $ 39.79 $ 0.395 12/31/2015 $ 56.64 $ 37.03 $ 0.395

Supplementary Information For O

Supplementary Information For Oil And Gas Producing Activities	12 Months Ended
	Sep. 30, 2017
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 2017 2016 (Thousands) Proved Properties(1) $ 4,832,301 $ 4,554,929 Unproved Properties 80,932 135,285 4,913,233 4,690,214 Less — Accumulated Depreciation, Depletion and Amortization 3,765,710 3,657,239 $ 1,147,523 $ 1,032,975 (1) Includes asset retirement costs of $54.4 million and $63.6 million at September 30, 2017 and 2016, 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 2018. Following is a summary of costs excluded from amortization at September 30, 2017: Total as of September 30, 2017 Year Costs Incurred 2017 2016 2015 Prior (Thousands) Acquisition Costs $ 55,193 $ — $ — $ — $ 55,193 Development Costs 11,879 4,388 6,707 416 368 Exploration Costs 13,388 2,376 7,593 3,419 — Capitalized Interest 472 235 149 88 — $ 80,932 $ 6,999 $ 14,449 $ 3,923 $ 55,561 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2017 2016 2015 (Thousands) United States Property Acquisition Costs: Proved $ 8,908 $ 1,342 $ 1,767 Unproved 262 2,165 19,998 Exploration Costs(1) 40,975 27,561 53,222 Development Costs(2) 200,639 219,386 454,605 Asset Retirement Costs (9,175 ) (49,653 ) 37,595 $ 241,609 $ 200,801 $ 567,187 (1) Amounts for 2017, 2016 and 2015 include capitalized interest of $0.3 million , $0.3 million and $0.4 million , respectively. (2) Amounts for 2017, 2016 and 2015 include capitalized interest of $0.2 million , $0.2 million and $0.5 million , respectively. For the years ended September 30, 2017, 2016 and 2015, the Company spent $101.1 million , $92.8 million and $161.8 million , respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2017 2016 2015 United States (Thousands, except per Mcfe amounts) Operating Revenues: Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)(1) $ 399,975 $ 282,619 $ 350,673 Oil, Condensate and Other Liquids 126,517 103,533 156,048 Total Operating Revenues(2) 526,492 386,152 506,721 Production/Lifting Costs 165,991 153,914 167,800 Franchise/Ad Valorem Taxes 15,372 13,794 20,167 Purchased Emission Allowance Expense 1,391 700 3,089 Accretion Expense 4,896 6,663 6,186 Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production, respectively) 108,471 136,579 234,480 Impairment of Oil and Gas Producing Properties — 948,307 1,126,257 Income Tax Expense (Benefit) 86,657 (368,940 ) (444,393 ) Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 143,714 $ (504,865 ) $ (606,865 ) (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, 2017 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, 2014 1,624,062 58,822 1,682,884 Extensions and Discoveries 633,360 (1) — 633,360 Revisions of Previous Estimates (28,124 ) (6,317 ) (34,441 ) Production (136,404 ) (2) (3,159 ) (139,563 ) Sale of Minerals in Place (112 ) — (112 ) 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 Proved Developed Reserves: September 30, 2014 1,119,901 57,907 1,177,808 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 Proved Undeveloped Reserves: September 30, 2014 504,161 915 505,076 September 30, 2015 825,284 — 825,284 September 30, 2016 541,959 — 541,959 September 30, 2017 610,018 — 610,018 (1) Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region. (2) Production includes 130,291 MMcf (during 2015), 135,598 MMcf (during 2016) and 145,452 MMcf (during 2017), from Marcellus 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, 2014 253 38,224 38,477 Extensions and Discoveries — 533 533 Revisions of Previous Estimates (3 ) (2,251 ) (2,254 ) Production (30 ) (3,004 ) (3,034 ) 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 Proved Developed Reserves: September 30, 2014 253 37,002 37,255 September 30, 2015 220 33,150 33,370 September 30, 2016 73 28,698 28,771 September 30, 2017 28 29,771 29,799 Proved Undeveloped Reserves: September 30, 2014 — 1,222 1,222 September 30, 2015 — 352 352 September 30, 2016 — 238 238 September 30, 2017 — 408 408 The Company’s proved undeveloped (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 Company’s PUD reserves decreased from 827 Bcfe at September 30, 2015 to 543 Bcfe at September 30, 2016. PUD reserves in the Marcellus Shale decreased from 825 Bcfe at September 30, 2015 to 542 Bcfe at September 30, 2016. The Company’s total PUD reserves were 29% of total proved reserves at September 30, 2016, down from 35% of total proved reserves at September 30, 2015. The increase in PUD reserves in 2017 of 69 Bcfe is 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. The PUD reserves removed were all in the Marcellus Shale and were due to a couple of factors. PUD reserves of 36 Bcfe associated with a few wells 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. This will now take longer than the five year time horizon from original booking. PUD reserves of 18 Bcfe were removed due to a change in plans this year and its impact on a few wells. As part of Seneca’s transition toward a Utica focused development program in the Western Development Area, certain Marcellus wells have been replaced with Utica wells in our development plan. The decrease in PUD reserves in 2016 of 284 Bcfe was a result of 102 Bcfe in new PUD reserve additions ( 102 Bcfe from the Marcellus Shale), offset by sales of 166 Bcfe associated with a joint development agreement (JDA) that Seneca entered into in December 2015, 14 Bcfe in downward revisions to remaining PUD reserves, offset by 110 Bcfe in PUD conversions to developed reserves and 96 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale ( 74 Bcfe) and were due to several factors including schedule changes, lower performance expectations and lower natural gas pricing. Geneseo Shale PUD reserves of 23 Bcfe were removed solely due to lower gas pricing as they were uneconomic at trailing twelve month pricing. The Company invested $101 million during the year ended September 30, 2017 to convert 147 Bcfe ( 159 Bcfe before revisions) of Marcellus 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 wells that were recorded at September 30, 2016. The vast majority of these wells were in the Appalachian region. The Company invested $93 million (includes $36 million of drilling carry costs for a JDA partner that were later reimbursed) during the year ended September 30, 2016 to convert 92 Bcfe ( 110 Bcfe before revisions) of PUD reserves to developed reserves. This represents 11% of the net PUD reserves recorded at September 30, 2015. In 2016, the majority of Seneca's planned PUD reserves development was funded by a JDA partner, which reduced Seneca's working interest, as discussed in Note A — Summary of Significant Accounting Policies under the heading “Property, Plant and Equipment.” In fiscal 2016, the Company developed 31 (or 28% ) of its gross Marcellus Shale wells that were recorded at September 30, 2015. T he majority of these wells were included in the JDA. Including the impact of JDA sales, the Company developed 207 Bcfe (or 25% ) of its net PUD reserves recorded at September 30, 2015. In addition, as stated above, the sales associated with the JDA further decreased PUD reserves. As part of Seneca’s JDA in the Marcellus Shale, Seneca anticipates it will sell approximately 60 Bcfe of its working interest PUD reserves in 2018 to its JDA partner as it develops the last group of wells included in the JDA. In 2018, the Company estimates that it will invest approximately $186 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 39% of its beginning year PUD reserves in fiscal 2013, 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 and 27% of its beginning year PUD reserves in fiscal 2017. At September 30, 2017, 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 2017 2016 2015 (Thousands) United States Future Cash Inflows $ 6,144,317 $ 3,768,463 $ 6,916,775 Less: Future Production Costs 2,378,262 1,994,916 2,854,142 Future Development Costs 411,578 375,152 761,922 Future Income Tax Expense at Applicable Statutory Rate 1,160,469 303,397 1,117,433 Future Net Cash Flows 2,194,008 1,094,998 2,183,278 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,080,962 452,470 860,244 Standardized Measure of Discounted Future Net Cash Flows $ 1,113,046 $ 642,528 $ 1,323,034 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2017 2016 2015 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 642,528 $ 1,323,034 $ 2,066,878 Sales, Net of Production Costs (345,075 ) (218,444 ) (318,753 ) Net Changes in Prices, Net of Production Costs 828,187 (1,066,593 ) (1,752,843 ) Extensions and Discoveries 170,500 47,742 266,159 Changes in Estimated Future Development Costs 8,816 143,752 164,510 Sales of Minerals in Place (9,849 ) (95,849 ) (1 ) Previously Estimated Development Costs Incurred 101,134 92,840 161,833 Net Change in Income Taxes at Applicable Statutory Rate (393,353 ) 387,739 545,442 Revisions of Previous Quantity Estimates 39,078 6,202 (16,573 ) Accretion of Discount and Other 71,080 22,105 206,382 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,113,046 $ 642,528 $ 1,323,034

Valuation And Qualifying Accoun

Valuation And Qualifying Accounts	12 Months Ended
	Sep. 30, 2017
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, 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 Year Ended September 30, 2015 Allowance for Uncollectible Accounts $ 31,811 $ 9,316 $ 2,585 $ 14,683 $ 29,029 (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.

Summary Of Significant Accoun21

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Sep. 30, 2017
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.
Reclassification	Reclassification Certain prior year amounts have been reclassified to conform with current year presentation.
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 M — Supplementary Information for Oil and Gas Producing Activities. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10% , which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The 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, 2017, the ceiling exceeded the book value of the oil and gas properties by $286.4 million . In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2017 , 2016 , and 2015 , estimated future net cash flows were increased by $30.5 million , $215.3 million and $194.5 million , respectively. 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 will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $325 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $262.6 million as of September 30, 2017, which includes $163.9 million of cash ( $137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) that Seneca had received in recognition of IOG funding that is due to Seneca for costs previously incurred to develop a portion of the first 75 joint development wells. The cash proceeds were recorded by Seneca as a $163.9 million reduction of property, plant and equipment. The remainder funded joint development expenditures. As the fee-owner of the property’s mineral rights, Seneca retains a 7.5% royalty interest and the remaining 20% working interest (which results in a 26% net revenue interest) in 56 of the joint development wells. 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 2017 2016 (Thousands) Exploration and Production $ 4,925,409 $ 4,645,226 Pipeline and Storage 2,002,736 1,956,708 Gathering 484,768 454,343 Utility 2,045,074 1,998,605 Energy Marketing 3,564 3,528 All Other and Corporate 109,128 109,455 $ 9,570,679 $ 9,167,865 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2017 2016 2015 Exploration and Production, per Mcfe(1) $ 0.65 $ 0.87 $ 1.52 Pipeline and Storage 2.2 % 2.4 % 2.4 % Gathering 3.4 % 4.0 % 4.0 % Utility 2.8 % 2.7 % 2.6 % Energy Marketing 7.9 % 7.9 % 6.1 % All Other and Corporate 1.3 % 1.8 % 1.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63 , $0.85 and $1.49 per Mcfe of production in 2017 , 2016 and 2015 , respectively.
Goodwill	Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2017 and 2016 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, 2017 , 2016 and 2015 , 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, 2017, 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, 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 ) Year Ended September 30, 2016 Balance at October 1, 2015 $ 157,197 $ 5,969 $ (69,794 ) $ 93,372 Other Comprehensive Gains and Losses Before Reclassifications 41,845 932 (13,027 ) 29,750 Amounts Reclassified From Other Comprehensive Loss (134,260 ) (847 ) 6,345 (128,762 ) Balance at September 30, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) 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 $1.2 million and $1.3 million at September 30, 2017 and 2016, respectively. The total amount for accumulated losses was $57.3 million and $75.2 million at September 30, 2017 and 2016, 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, 2017 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 2017 2016 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $83,983 $216,823 Operating Revenues Commodity Contracts (1,921 ) 4,520 Purchased Gas Foreign Currency Contracts (457 ) (424 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale 1,575 1,374 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit (288 ) (333 ) (1) Net Actuarial Loss (13,145 ) (9,735 ) (1) 69,747 212,225 Total Before Income Tax (29,937 ) (83,463 ) Income Tax Expense $39,810 $128,762 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 $26.7 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 2017, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $17.1 million at September 30, 2017. 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, 2017, the remaining weighted average amortization period for such costs was approximately 2 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 investment tax credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction. 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 2017 2016 (Thousands) Prepayments $ 10,927 $ 10,919 Prepaid Property and Other Taxes 13,974 13,138 Federal Income Taxes Receivable — 11,758 State Income Taxes Receivable 9,689 3,961 Fair Values of Firm Commitments 1,031 3,962 Regulatory Assets 15,884 15,616 $ 51,505 $ 59,354
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 2017 2016 (Thousands) Accrued Capital Expenditures $ 37,382 $ 26,796 Regulatory Liabilities 34,059 14,725 Federal Income Taxes Payable 1,775 — Other 38,673 32,909 $ 111,889 $ 74,430
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, 2017 and 2016, customers in the balanced billing programs had advanced excess funds of $15.7 million and $14.8 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, 2017 and 2016, the Company had received customer security deposits amounting to $20.4 million and $16.0 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 has outstanding are stock options, SARs, restricted stock units and performance shares. For the year ended September 30, 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 157,649 shares excluded as being antidilutive for the year ended September 30, 2017. As the Company recognized net losses for the years ended September 30, 2016 and 2015, the aforementioned potentially dilutive securities, amounting to 431,408 shares and 709,063 shares, respectively, were not recognized in the diluted earnings per share calculation for 2016 and 2015.
Stock-Based Compensation	Stock-Based Compensation The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, SARs, 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. Stock options and SARs under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no stock option or SAR 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 stock options and SARs. 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 option and 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 Option and 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 original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance. In May 2015, the FASB issued authoritative guidance related to the presentation of investments for which fair value was measured using net asset value per share (or its equivalent). In fiscal 2017, the Company adopted this authoritative guidance. As a result, the presentation of Retirement Plan Investments and Other Post-Retirement Benefit Assets has been adjusted (see tables in Note H — Retirement Plan and Other Post-Retirement Benefits). In February 2016, the FASB issued authoritative guidance 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 have been applied prospectively and prior periods have not been adjusted. 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 shall be the only component eligible to be capitalized as part of the cost of inventory or property, plant and equipment. The new guidance will be effective as of the Company’s first quarter of fiscal 2019, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the interaction of this authoritative guidance with the various regulatory provisions concerning pension and postretirement benefit costs in the Company’s Utility and Pipeline and Storage segments.

Summary Of Significant Accoun22

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2017
Accounting Policies [Abstract]
Schedule Of Depreciable Plant By Segment	The following is a summary of depreciable plant by segment: As of September 30 2017 2016 (Thousands) Exploration and Production $ 4,925,409 $ 4,645,226 Pipeline and Storage 2,002,736 1,956,708 Gathering 484,768 454,343 Utility 2,045,074 1,998,605 Energy Marketing 3,564 3,528 All Other and Corporate 109,128 109,455 $ 9,570,679 $ 9,167,865
Average Depreciation Depletion And Amortization Rates	Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2017 2016 2015 Exploration and Production, per Mcfe(1) $ 0.65 $ 0.87 $ 1.52 Pipeline and Storage 2.2 % 2.4 % 2.4 % Gathering 3.4 % 4.0 % 4.0 % Utility 2.8 % 2.7 % 2.6 % Energy Marketing 7.9 % 7.9 % 6.1 % All Other and Corporate 1.3 % 1.8 % 1.4 % (1) Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63 , $0.85 and $1.49 per Mcfe of production in 2017 , 2016 and 2015 , respectively.
Components Of Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2017, 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, 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 ) Year Ended September 30, 2016 Balance at October 1, 2015 $ 157,197 $ 5,969 $ (69,794 ) $ 93,372 Other Comprehensive Gains and Losses Before Reclassifications 41,845 932 (13,027 ) 29,750 Amounts Reclassified From Other Comprehensive Loss (134,260 ) (847 ) 6,345 (128,762 ) Balance at September 30, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 )
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, 2017 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 2017 2016 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $83,983 $216,823 Operating Revenues Commodity Contracts (1,921 ) 4,520 Purchased Gas Foreign Currency Contracts (457 ) (424 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale 1,575 1,374 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit (288 ) (333 ) (1) Net Actuarial Loss (13,145 ) (9,735 ) (1) 69,747 212,225 Total Before Income Tax (29,937 ) (83,463 ) Income Tax Expense $39,810 $128,762 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 2017 2016 (Thousands) Prepayments $ 10,927 $ 10,919 Prepaid Property and Other Taxes 13,974 13,138 Federal Income Taxes Receivable — 11,758 State Income Taxes Receivable 9,689 3,961 Fair Values of Firm Commitments 1,031 3,962 Regulatory Assets 15,884 15,616 $ 51,505 $ 59,354
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 2017 2016 (Thousands) Accrued Capital Expenditures $ 37,382 $ 26,796 Regulatory Liabilities 34,059 14,725 Federal Income Taxes Payable 1,775 — Other 38,673 32,909 $ 111,889 $ 74,430

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Sep. 30, 2017
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 2017 2016 2015 (Thousands) Balance at Beginning of Year $ 112,330 $ 156,805 $ 117,713 Liabilities Incurred 2,963 2,719 4,433 Revisions of Estimates (10,578 ) 16,721 33,717 Liabilities Settled (4,967 ) (72,215 ) (6,825 ) Accretion Expense 6,647 8,300 7,767 Balance at End of Year $ 106,395 $ 112,330 $ 156,805

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2017
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 2017 2016 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note H) $ 125,175 $ 203,755 Post-Retirement Benefit Costs(2) (Note H) 13,886 74,802 Recoverable Future Taxes (Note D) 181,363 177,261 Environmental Site Remediation Costs(2) (Note I) 19,665 23,392 Asset Retirement Obligations(2) (Note B) 12,764 12,490 Unamortized Debt Expense (Note A) 1,159 1,688 Other(3) 18,827 21,927 Total Regulatory Assets 372,839 515,315 Less: Amounts Included in Other Current Assets (15,884 ) (15,616 ) Total Long-Term Regulatory Assets $ 356,955 $ 499,699 At September 30 2017 2016 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 204,630 $ 193,424 Taxes Refundable to Customers (Note D) 95,739 93,318 Post-Retirement Benefit Costs (Note H) 102,891 67,204 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) — 19,537 Other(4) 44,884 47,310 Total Regulatory Liabilities 448,144 420,793 Less: Amounts included in Current and Accrued Liabilities (34,059 ) (34,262 ) Total Long-Term Regulatory Liabilities $ 414,085 $ 386,531 (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) $15,884 and $15,616 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $2,943 and $6,311 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively. (4) $34,059 and $14,725 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $10,825 and $32,585 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2017
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 2017 2016 2015 (Thousands) Current Income Taxes — Federal $ 32,034 $ (6,658 ) $ 25,064 State 10,673 20,903 13,387 Deferred Income Taxes — Federal 103,046 (164,818 ) (244,336 ) State 14,929 (81,976 ) (113,251 ) 160,682 (232,549 ) (319,136 ) Deferred Investment Tax Credit (173 ) (348 ) (414 ) Total Income Taxes $ 160,509 $ (232,897 ) $ (319,550 ) Presented as Follows: Other Income $ (173 ) $ (348 ) $ (414 ) Income Tax Expense (Benefit) 160,682 (232,549 ) (319,136 ) Total Income Taxes $ 160,509 $ (232,897 ) $ (319,550 )
Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate	The following is a reconciliation of this difference: Year Ended September 30 2017 2016 2015 (Thousands) U.S. Income (Loss) Before Income Taxes $ 443,991 $ (523,855 ) $ (698,977 ) Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35% $ 155,397 $ (183,349 ) $ (244,642 ) State Income Taxes (Benefit) 16,641 (39,697 ) (64,912 ) Federal Tax Credits (6,679 ) (3,262 ) (732 ) Miscellaneous (4,850 ) (6,589 ) (9,264 ) Total Income Taxes $ 160,509 $ (232,897 ) $ (319,550 )
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 2017 2016 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 1,141,432 $ 1,049,100 Pension and Other Post-Retirement Benefit Costs 79,516 151,903 Unrealized Hedging Gains 19,127 50,179 Other 57,919 55,457 Total Deferred Tax Liabilities 1,297,994 1,306,639 Deferred Tax Assets: Pension and Other Post-Retirement Benefit Costs (123,532 ) (195,829 ) Tax Loss and Credit Carryforwards (200,344 ) (194,875 ) Other (82,831 ) (92,140 ) Total Deferred Tax Assets (406,707 ) (482,844 ) Total Net Deferred Income Taxes $ 891,287 $ 823,795
Reconciliation Of The Change In Unrecognized Tax Benefits	The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2017 2016 2015 (Thousands) Balance at Beginning of Year $ 396 $ 5,085 $ 3,147 Additions for Tax Positions of Prior Years 1,251 396 2,504 Reductions for Tax Positions of Prior Years (396 ) (1,314 ) (566 ) Reductions Related to Settlements with Taxing Authorities — (3,771 ) — Balance at End of Year $ 1,251 $ 396 $ 5,085
Summary of Operating Loss and Tax Credit Carryforwards	As of September 30, 2017, the Company has the following carryforwards available: Jurisdiction Tax Attribute Amount (Thousands) Expires Federal Net Operating Loss $ 184,289 2028-2033 Pennsylvania Net Operating Loss 324,572 2030-2035 California Net Operating Loss 169,723 2029-2035 Federal Alternative Minimum Tax Credit 81,683 Unlimited California Alternative Minimum Tax Credit 5,873 Unlimited Federal Enhanced Oil Recovery Credit 10,502 2029-2037 California Enhanced Oil Recovery Credit 5,061 2021-2037 Federal R&D Tax Credit 5,694 2031-2036

Capitalization And Short-Term26

Capitalization And Short-Term Borrowings (Tables)	12 Months Ended
	Sep. 30, 2017
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, 2014 84,157 $ 84,157 $ 716,144 $ 1,614,361 $ (3,979 ) Net Income (Loss) Available for Common Stock (379,427 ) Dividends Declared on Common Stock ($1.56 Per Share) (131,734 ) Other Comprehensive Income, Net of Tax 97,351 Share-Based Payment Expense(2) 2,207 Common Stock Issued Under Stock and Benefit Plans(1) 437 437 25,923 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 (3) $ (30,123 ) (1) Paid in Capital includes tax benefits of $1.9 million and $9.1 million for September 30, 2016 and 2015, respectively, related to stock-based compensation. (2) Paid in Capital includes compensation costs associated with stock option, SARs, performance share 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, 2017, $707.5 million of accumulated earnings was free of such limitations.
Schedule Of Share-Based Compensation For Stock Options	Transactions involving option shares 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, 2016 19,000 $ 39.48 Granted in 2017 — $ — Exercised in 2017 (19,000 ) $ 39.48 Forfeited in 2017 — $ — Outstanding at September 30, 2017 — $ — — $ — Option shares exercisable at September 30, 2017 — $ — — $ — Shares available for future grant at September 30, 2017(1) 2,182,243 (1) Includes shares available for options, SARs, restricted stock and performance share grants.
Schedule Of Share-Based Compensation For SARs	Transactions 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, 2016 1,590,988 $ 48.19 Granted in 2017 — $ — Exercised in 2017 (82,077 ) $ 39.77 Forfeited in 2017 — $ — Expired in 2017 (3,000 ) $ 52.10 Outstanding at September 30, 2017 1,505,911 $ 48.64 2.52 $ 13,144 SARs exercisable at September 30, 2017 1,505,911 $ 48.64 2.52 $ 13,144
Schedule Of Share-Based Compensation For Restricted Share Awards	Transactions 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, 2016 20,000 $ 47.46 Granted in 2017 — $ — Vested in 2017 — $ — Forfeited in 2017 — $ — Outstanding at September 30, 2017 20,000 $ 47.46
Schedule Of Share-Based Compensation For Non-Performance Based Restricted Stock Units	Transactions 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, 2016 239,151 $ 49.67 Granted in 2017 87,143 $ 52.13 Vested in 2017 (80,530 ) $ 53.38 Forfeited in 2017 (12,565 ) $ 53.75 Outstanding at September 30, 2017 233,199 $ 48.99
Schedule of Share-based Compensation for Performance Shares	Transactions involving performance shares for all plans are summarized as follows: Number of Performance Shares Weighted Average Fair Value per Award Outstanding at September 30, 2016 438,234 $ 44.98 Granted in 2017 184,148 $ 56.39 Vested in 2017 (43,484 ) $ 69.13 Forfeited in 2017 (51,150 ) $ 60.74 Outstanding at September 30, 2017 527,748 $ 45.44
Schedule Of Long-Term Debt	The outstanding long-term debt is as follows: At September 30 2017 2016 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(3)(4): 3.75% to 8.75% due April 2018 to September 2027 2,300,000 2,000,000 Total Long-Term Debt 2,399,000 2,099,000 Less Unamortized Discount and Debt Issuance Costs 15,319 12,748 Less Current Portion(2) 300,000 — $ 2,083,681 $ 2,086,252 (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 scheduled to mature in April 2018. The Company redeemed these 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 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 2017 2016 2015 Risk-Free Interest Rate 1.54 % 1.26 % 1.01 % Remaining Term at Date of Grant (Years) 2.79 2.79 2.78 Expected Volatility 22.6 % 20.5 % 20.1 % Expected Dividend Yield (Quarterly) N/A N/A N/A

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2017
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, 2017 and 2016. 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, 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 At Fair Value as of September 30, 2016 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 $ 113,407 $ — $ — $ — $ 113,407 Derivative Financial Instruments: Commodity Futures Contracts — Gas 2,623 — — (2,276 ) 347 Over the Counter Swaps — Gas and Oil — 119,654 — (3,860 ) 115,794 Foreign Currency Contracts — — — (2,337 ) (2,337 ) Other Investments: Balanced Equity Mutual Fund 36,658 — — — 36,658 Fixed Income Mutual Fund 31,395 — — — 31,395 Common Stock — Financial Services Industry 2,902 — — — 2,902 Hedging Collateral Deposits 1,484 — — — 1,484 Total $ 188,469 $ 119,654 $ — $ (8,473 ) $ 299,650 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 2,276 $ — $ — $ (2,276 ) $ — Over the Counter Swaps — Gas and Oil — 5,322 — (3,860 ) 1,462 Foreign Currency Contracts — 2,337 — (2,337 ) — Total $ 2,276 $ 7,659 $ — $ (8,473 ) $ 1,462 Total Net Assets/(Liabilities) $ 186,193 $ 111,995 $ — $ — $ 298,188 (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, 2017
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 2017 Carrying Amount 2017 Fair Value 2016 Carrying Amount 2016 Fair Value (Thousands) Long-Term Debt $ 2,383,681 $ 2,523,639 $ 2,086,252 $ 2,255,562
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, 2017 and 2016 (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, 2017 2016 2017 2016 2017 2016 Commodity Contracts $ 2,811 $ 58,714 Operating Revenue $ 83,983 $ 216,823 Operating Revenue $ (100 ) $ 392 Commodity Contracts (164 ) 1,585 Purchased Gas (1,921 ) 4,520 Not Applicable — — Foreign Currency Contracts 2,700 194 Operation and Maintenance Expense (457 ) (424 ) Not Applicable — — Total $ 5,347 $ 60,493 $ 81,605 $ 220,919 $ (100 ) $ 392
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, 2017 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2017 (In thousands) Commodity Contracts Operating Revenues $ 1,655 $ (1,655 ) Commodity Contracts Purchased Gas 464 (464 ) $ 2,119 $ (2,119 )

Retirement Plan And Other Pos29

Retirement Plan And Other Post-Retirement Benefits (Tables)	12 Months Ended
	Sep. 30, 2017
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 2017, 2016 and 2015. Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2017 2016 2015 2017 2016 2015 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 1,097,421 $ 1,026,190 $ 999,499 $ 526,138 $ 464,987 $ 465,583 Service Cost 11,969 11,710 12,047 2,449 2,331 2,693 Interest Cost 38,383 42,315 41,217 19,007 20,386 19,285 Plan Participants’ Contributions — — — 2,717 2,558 2,242 Retiree Drug Subsidy Receipts — — — 1,553 1,925 1,338 Amendments(1) — — 7,752 — — — Actuarial (Gain) Loss (32,466 ) 76,309 23,426 (62,215 ) 60,402 (1,575 ) Benefits Paid (60,481 ) (59,103 ) (57,751 ) (27,030 ) (26,451 ) (24,579 ) Benefit Obligation at End of Period $ 1,054,826 $ 1,097,421 $ 1,026,190 $ 462,619 $ 526,138 $ 464,987 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 869,775 $ 834,870 $ 869,791 $ 494,320 $ 477,959 $ 497,601 Actual Return on Plan Assets 84,279 87,008 (13,370 ) 40,157 37,415 534 Employer Contributions 17,146 7,000 36,200 3,853 2,839 2,161 Plan Participants’ Contributions — — — 2,717 2,558 2,242 Benefits Paid (60,481 ) (59,103 ) (57,751 ) (27,030 ) (26,451 ) (24,579 ) Fair Value of Assets at End of Period $ 910,719 $ 869,775 $ 834,870 $ 514,017 $ 494,320 $ 477,959 Net Amount Recognized at End of Period (Funded Status) $ (144,107 ) $ (227,646 ) $ (191,320 ) $ 51,398 $ (31,818 ) $ 12,972 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (144,107 ) $ (227,646 ) $ (191,320 ) $ (4,972 ) $ (49,467 ) $ (11,487 ) Non-Current Assets — — — 56,370 17,649 24,459 Net Amount Recognized at End of Period $ (144,107 ) $ (227,646 ) $ (191,320 ) $ 51,398 $ (31,818 ) $ 12,972 Accumulated Benefit Obligation $ 1,010,179 $ 1,039,408 $ 968,984 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 3.77 % 3.60 % 4.25 % 3.81 % 3.70 % 4.50 % Rate of Compensation Increase 4.70 % 4.70 % 4.75 % 4.70 % 4.70 % 4.75 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2017 2016 2015 2017 2016 2015 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 11,969 $ 11,710 $ 12,047 $ 2,449 $ 2,331 $ 2,693 Interest Cost 38,383 42,315 41,217 19,007 20,386 19,285 Expected Return on Plan Assets (59,718 ) (59,369 ) (59,615 ) (31,458 ) (31,535 ) (34,089 ) Amortization of Prior Service Cost (Credit) 1,058 1,234 183 (429 ) (912 ) (1,913 ) Recognition of Actuarial Loss(2) 42,687 32,248 36,129 18,415 5,530 4,148 Net Amortization and Deferral for Regulatory Purposes 469 3,957 7,739 6,108 17,123 20,322 Net Periodic Benefit Cost $ 34,848 $ 32,095 $ 37,700 $ 14,092 $ 12,923 $ 10,446 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Discount Rate 3.60 % 4.25 % 4.25 % 3.70 % 4.50 % 4.25 % Expected Return on Plan Assets 7.00 % 7.25 % 7.50 % 6.50 % 6.75 % 7.00 % Rate of Compensation Increase 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % (1) In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan. (2) 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 2017, the changes in such amounts during 2017, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2018 are presented in the table below: Retirement Plan Other Post-Retirement Benefits Non-Qualified Benefit Plans (Thousands) Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1) Net Actuarial Loss $ (203,887 ) $ (19,578 ) $ (24,332 ) Prior Service (Cost) Credit (6,133 ) 3,687 — Net Amount Recognized $ (210,020 ) $ (15,891 ) $ (24,332 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2017(1) Decrease (Increase) in Actuarial Loss, excluding amortization(2) $ 57,028 $ 70,915 $ (1,351 ) Change due to Amortization of Actuarial Loss 42,687 18,415 4,059 Prior Service (Cost) Credit 1,058 (429 ) — Net Change $ 100,773 $ 88,901 $ 2,708 Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (37,205 ) $ (10,558 ) $ (3,549 ) Prior Service (Cost) Credit (938 ) 429 — Net Amount Expected to be Recognized $ (38,143 ) $ (10,129 ) $ (3,549 ) (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 2018 $ 26,483 $ (1,910 ) 2019 $ 27,456 $ (2,074 ) 2020 $ 28,359 $ (2,225 ) 2021 $ 29,173 $ (2,369 ) 2022 $ 29,757 $ (2,515 ) 2023 through 2027 $ 152,957 $ (14,271 )
Schedule Of Health Care Cost Trend Rates	Assumed health care cost trend rates as of September 30 were: 2017 2016 2015 Rate of Medical Cost Increase for Pre Age 65 Participants 5.67 % (1) 5.75 % (1) 6.93 % (2) Rate of Medical Cost Increase for Post Age 65 Participants 4.75 % (1) 4.75 % (1) 6.68 % (2) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 8.45 % (1) 9.00 % (1) 7.17 % (2) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 4.75 % (1) 4.75 % (1) 6.68 % (2) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 7.33 % (1) 7.20 % (1) 6.65 % (2) (1) It was assumed that this rate would gradually decline to 4.5% by 2039. (2) It was assumed that this rate would gradually decline to 4.5% by 2028.
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule Of Fair Value Of Plan Assets	Total Fair Value Amounts at September 30, 2017 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 Total Fair Value Level 1 Level 2 Level 3 Measured at NAV(7) Retirement Plan Investments Domestic Equities(1) $ 256,796 $ 188,253 $ — $ — $ 68,543 International Equities(2) 104,592 — — — 104,592 Global Equities(3) 120,025 — — — 120,025 Domestic Fixed Income(4) 342,442 1,647 340,795 — — International Fixed Income(5) 744 407 337 — — Global Fixed Income(6) 81,146 — — — 81,146 Real Estate 2,970 — — 2,970 — Cash Held in Collective Trust Funds 24,812 — — — 24,812 Total Retirement Plan Investments 933,527 190,307 341,132 2,970 399,118 401(h) Investments (58,707 ) (12,025 ) (21,555 ) (188 ) (24,939 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 874,820 $ 178,282 $ 319,577 $ 2,782 $ 374,179 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (5,045 ) Total Retirement Plan Assets $ 869,775 (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 adoption of the new 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) Hedge Funds Real Estate Excluding 401(h) Investments Total Balance at September 30, 2015 $ 26,490 $ 4,724 $ (1,885 ) $ 29,329 Realized Gains/(Losses) 5,878 — (354 ) 5,524 Unrealized Gains/(Losses) (5,445 ) (404 ) 344 (5,505 ) Sales (26,923 ) (1,350 ) 1,707 (26,566 ) 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
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 $ 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 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 $ 139,617 $ — $ — $ — $ 139,617 Collective Trust Funds — International Equities 51,488 — — — 51,488 Exchange Traded Funds — Fixed Income 230,761 230,761 — — — Cash Held in Collective Trust Funds 13,176 — — — 13,176 Total VEBA Trust Investments 435,042 230,761 — — 204,281 401(h) Investments 58,707 12,025 21,555 188 24,939 Total Investments (including 401(h) Investments) $ 493,749 $ 242,786 $ 21,555 $ 188 $ 229,220 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 571 Total Other Post-Retirement Benefit Assets $ 494,320 (1) Reflects the adoption of the new 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, 2015 $ 1,885 Realized Gains/(Losses) 354 Unrealized Gains/(Losses) (344 ) Sales (1,707 ) Balance at September 30, 2016 188 Unrealized Gains/(Losses) 37 Balance at September 30, 2017 $ 225

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Sep. 30, 2017
Segment Reporting [Abstract]
Segment Information By Segment	Year Ended September 30, 2017 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) $ 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 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) $ 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 Year Ended September 30, 2015 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) $ 693,441 $ 203,089 $ 497 $ 700,761 $ 159,857 $ 1,757,645 $ 2,352 $ 916 $ 1,760,913 Intersegment Revenues $ — $ 88,251 $ 76,709 $ 15,506 $ 849 $ 181,315 $ — $ (181,315 ) $ — Interest Income $ 2,554 $ 474 $ 140 $ 2,220 $ 195 $ 5,583 $ 66 $ (1,727 ) $ 3,922 Interest Expense $ 46,726 $ 27,658 $ 1,627 $ 28,176 $ 27 $ 104,214 $ — $ (4,743 ) $ 99,471 Depreciation, Depletion and Amortization $ 239,818 $ 38,178 $ 10,829 $ 45,616 $ 209 $ 334,650 $ 832 $ 676 $ 336,158 Income Tax Expense (Benefit) $ (428,217 ) $ 48,113 $ 24,721 $ 33,143 $ 4,547 $ (317,693 ) $ 13 $ (1,456 ) $ (319,136 ) Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties $ 1,126,257 $ — $ — $ — $ — $ 1,126,257 $ — $ — $ 1,126,257 Segment Profit: Net Income (Loss) $ (556,974 ) $ 80,354 $ 31,849 $ 63,271 $ 7,766 $ (373,734 ) $ (2 ) $ (5,691 ) $ (379,427 ) Expenditures for Additions to Long-Lived Assets $ 557,313 $ 230,192 $ 118,166 $ 94,371 $ 128 $ 1,000,170 $ — $ 339 $ 1,000,509 At September 30, 2015 (Thousands) Segment Assets $ 2,439,801 $ 1,590,524 $ 444,358 $ 1,934,731 $ 90,676 $ 6,500,090 $ 77,350 $ (12,501 ) $ 6,564,939 (1) All Revenue from External Customers originated in the United States.
Schedule Of Long-Lived Assets, By Geographical Areas	Geographic Information At September 30 2017 2016 2015 (Thousands) Long-Lived Assets: United States $ 5,285,040 $ 5,223,356 $ 6,189,138

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Sep. 30, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Information	Quarter Ended Operating Revenues Operating Income (Loss) Net Income (Loss) Available for Common Stock Earnings (Loss) per Common Share Basic Diluted (Thousands, except per common share amounts) 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 2016 9/30/2016 $ 292,472 $ 81,244 $ 37,553 (1) $ 0.44 $ 0.44 6/30/2016 $ 335,617 $ 45,162 $ 8,286 (2) $ 0.10 $ 0.10 3/31/2016 $ 449,132 $ (237,000 ) $ (147,688 ) (3) $ (1.74 ) $ (1.74 ) 12/31/2015 $ 375,195 $ (305,924 ) $ (189,109 ) (4) $ (2.23 ) $ (2.23 ) (1) Includes a non-cash $32.7 million impairment charge ( $19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (2) Includes a non-cash $82.7 million impairment charge ( $47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (3) Includes a non-cash $397.4 million impairment charge ( $230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (4) Includes a non-cash $ 435.5 million impairment charge ( $252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

Market For Common Stock And R32

Market For Common Stock And Related Shareholder Matters (Tables)	12 Months Ended
	Sep. 30, 2017
Market For Common Stock And Related Shareholder Matters [Abstract]
Schedule Of Price Ranges And Dividends Declared	The quarterly price ranges (based on intra-day prices) and quarterly dividends declared for the fiscal years ended September 30, 2017 and 2016, are shown below: Price Range Dividends Declared Quarter Ended High Low 2017 9/30/2017 $ 59.92 $ 54.89 $ 0.415 6/30/2017 $ 61.20 $ 53.03 $ 0.415 3/31/2017 $ 61.25 $ 54.67 $ 0.405 12/31/2016 $ 58.78 $ 50.61 $ 0.405 2016 9/30/2016 $ 59.62 $ 53.81 $ 0.405 6/30/2016 $ 57.06 $ 47.49 $ 0.405 3/31/2016 $ 51.53 $ 39.79 $ 0.395 12/31/2015 $ 56.64 $ 37.03 $ 0.395

Supplementary Information For33

Supplementary Information For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Sep. 30, 2017
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 2017 2016 (Thousands) Proved Properties(1) $ 4,832,301 $ 4,554,929 Unproved Properties 80,932 135,285 4,913,233 4,690,214 Less — Accumulated Depreciation, Depletion and Amortization 3,765,710 3,657,239 $ 1,147,523 $ 1,032,975 (1) Includes asset retirement costs of $54.4 million and $63.6 million at September 30, 2017 and 2016, respectively.
Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization	Following is a summary of costs excluded from amortization at September 30, 2017: Total as of September 30, 2017 Year Costs Incurred 2017 2016 2015 Prior (Thousands) Acquisition Costs $ 55,193 $ — $ — $ — $ 55,193 Development Costs 11,879 4,388 6,707 416 368 Exploration Costs 13,388 2,376 7,593 3,419 — Capitalized Interest 472 235 149 88 — $ 80,932 $ 6,999 $ 14,449 $ 3,923 $ 55,561
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 2017 2016 2015 (Thousands) United States Property Acquisition Costs: Proved $ 8,908 $ 1,342 $ 1,767 Unproved 262 2,165 19,998 Exploration Costs(1) 40,975 27,561 53,222 Development Costs(2) 200,639 219,386 454,605 Asset Retirement Costs (9,175 ) (49,653 ) 37,595 $ 241,609 $ 200,801 $ 567,187 (1) Amounts for 2017, 2016 and 2015 include capitalized interest of $0.3 million , $0.3 million and $0.4 million , respectively. (2) Amounts for 2017, 2016 and 2015 include capitalized interest of $0.2 million , $0.2 million and $0.5 million , respectively.
Results Of Operations For Producing Activities	Results of Operations for Producing Activities Year Ended September 30 2017 2016 2015 United States (Thousands, except per Mcfe amounts) Operating Revenues: Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)(1) $ 399,975 $ 282,619 $ 350,673 Oil, Condensate and Other Liquids 126,517 103,533 156,048 Total Operating Revenues(2) 526,492 386,152 506,721 Production/Lifting Costs 165,991 153,914 167,800 Franchise/Ad Valorem Taxes 15,372 13,794 20,167 Purchased Emission Allowance Expense 1,391 700 3,089 Accretion Expense 4,896 6,663 6,186 Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production, respectively) 108,471 136,579 234,480 Impairment of Oil and Gas Producing Properties — 948,307 1,126,257 Income Tax Expense (Benefit) 86,657 (368,940 ) (444,393 ) Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 143,714 $ (504,865 ) $ (606,865 ) (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, 2014 1,624,062 58,822 1,682,884 Extensions and Discoveries 633,360 (1) — 633,360 Revisions of Previous Estimates (28,124 ) (6,317 ) (34,441 ) Production (136,404 ) (2) (3,159 ) (139,563 ) Sale of Minerals in Place (112 ) — (112 ) 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 Proved Developed Reserves: September 30, 2014 1,119,901 57,907 1,177,808 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 Proved Undeveloped Reserves: September 30, 2014 504,161 915 505,076 September 30, 2015 825,284 — 825,284 September 30, 2016 541,959 — 541,959 September 30, 2017 610,018 — 610,018 (1) Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region. (2) Production includes 130,291 MMcf (during 2015), 135,598 MMcf (during 2016) and 145,452 MMcf (during 2017), from Marcellus 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, 2014 253 38,224 38,477 Extensions and Discoveries — 533 533 Revisions of Previous Estimates (3 ) (2,251 ) (2,254 ) Production (30 ) (3,004 ) (3,034 ) 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 Proved Developed Reserves: September 30, 2014 253 37,002 37,255 September 30, 2015 220 33,150 33,370 September 30, 2016 73 28,698 28,771 September 30, 2017 28 29,771 29,799 Proved Undeveloped Reserves: September 30, 2014 — 1,222 1,222 September 30, 2015 — 352 352 September 30, 2016 — 238 238 September 30, 2017 — 408 408
Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Year Ended September 30 2017 2016 2015 (Thousands) United States Future Cash Inflows $ 6,144,317 $ 3,768,463 $ 6,916,775 Less: Future Production Costs 2,378,262 1,994,916 2,854,142 Future Development Costs 411,578 375,152 761,922 Future Income Tax Expense at Applicable Statutory Rate 1,160,469 303,397 1,117,433 Future Net Cash Flows 2,194,008 1,094,998 2,183,278 Less: 10% Annual Discount for Estimated Timing of Cash Flows 1,080,962 452,470 860,244 Standardized Measure of Discounted Future Net Cash Flows $ 1,113,046 $ 642,528 $ 1,323,034
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 2017 2016 2015 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 642,528 $ 1,323,034 $ 2,066,878 Sales, Net of Production Costs (345,075 ) (218,444 ) (318,753 ) Net Changes in Prices, Net of Production Costs 828,187 (1,066,593 ) (1,752,843 ) Extensions and Discoveries 170,500 47,742 266,159 Changes in Estimated Future Development Costs 8,816 143,752 164,510 Sales of Minerals in Place (9,849 ) (95,849 ) (1 ) Previously Estimated Development Costs Incurred 101,134 92,840 161,833 Net Change in Income Taxes at Applicable Statutory Rate (393,353 ) 387,739 545,442 Revisions of Previous Quantity Estimates 39,078 6,202 (16,573 ) Accretion of Discount and Other 71,080 22,105 206,382 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,113,046 $ 642,528 $ 1,323,034

Summary Of Significant Accoun34

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015	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					$ 286,400
Increase estimated future net cash flows					30,500	$ 215,300	$ 194,500
Net Proceeds from Sale of Oil and Gas Producing Properties					26,554	137,316	$ 0
Goodwill	$ 5,476				5,476	5,476
Prior service (cost) credit	(1,300)				(1,200)	(1,300)
Gas stored underground	34,332				35,689	34,332
Customer Advances	14,762				15,701	14,762
Customer Security Deposits	16,019				$ 20,372	$ 16,019
Antidilutive securities					157,649	431,408	709,063
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation					$ 31,900
Impairment of Oil and Gas Producing Properties	32,700	$ 82,700	$ 397,400	$ 435,500	0	$ 948,307	$ 1,126,257
Receivable from Sale of Oil and Gas Producing Properties					0	19,543	$ 0
Amount Exceeds LIFO Basis [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground					17,100
LIFO Method [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground					26,700
Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Net Proceeds from Sale of Oil and Gas Producing Properties					163,900
Reduction in Property, Plant and Equipment					163,900
Net Proceeds from Sale of Oil and Gas Producing Properties					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	$ 75,200				$ 57,300	$ 75,200
Unamortized Debt Expense [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulated Reacquisition of Debt Cost Weighted Average Amortization Period					2 years
26 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed								56
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%
Royalty Interest								7.50%
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 Commitment to Develop Joint Wells								$ 325,000
Partner Amount Funded to Develop Joint Wells					$ 262,600
20 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed								19

Summary Of Significant Accoun35

Summary Of Significant Accounting Policies (Schedule Of Depreciable Plant By Segment) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Segment Reporting Information [Line Items]
Depreciable plant	$ 9,570,679	$ 9,167,865
Utility [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,045,074	1,998,605
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Depreciable plant	2,002,736	1,956,708
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciable plant	4,925,409	4,645,226
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Depreciable plant	3,564	3,528
Gathering [Member]
Segment Reporting Information [Line Items]
Depreciable plant	484,768	454,343
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Depreciable plant	$ 109,128	$ 109,455

Summary Of Significant Accoun36

Summary Of Significant Accounting Policies (Average Depreciation Depletion And Amortization Rates) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe	[1]	$ 0.65	$ 0.87	$ 1.52
Utility [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.80%	2.70%	2.60%
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.20%	2.40%	2.40%
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		7.90%	7.90%	6.10%
Gathering [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		3.40%	4.00%	4.00%
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		1.30%	1.80%	1.40%
Oil And Gas Producing Properties [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe		$ 0.63	$ 0.85	$ 1.49
[1]	Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note M — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.63, $0.85 and $1.49 per Mcfe of production in 2017, 2016 and 2015, respectively.

Summary Of Significant Accoun37

Summary Of Significant Accounting Policies (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ (5,640)	$ 93,372
Other Comprehensive Gains and Losses Before Reclassifications	15,327	29,750
Amounts Reclassified From Other Comprehensive Loss	(39,810)	(128,762)
Ending balance	(30,123)	(5,640)
Gains and Losses on Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	64,782	157,197
Other Comprehensive Gains and Losses Before Reclassifications	3,338	41,845
Amounts Reclassified From Other Comprehensive Loss	(47,319)	(134,260)
Ending balance	20,801	64,782
Gains and Losses on Securities Available for Sale [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	6,054	5,969
Other Comprehensive Gains and Losses Before Reclassifications	2,503	932
Amounts Reclassified From Other Comprehensive Loss	(995)	(847)
Ending balance	7,562	6,054
Funded Status of the Pension and Other Post-Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(76,476)	(69,794)
Other Comprehensive Gains and Losses Before Reclassifications	9,486	(13,027)
Amounts Reclassified From Other Comprehensive Loss	8,504	6,345
Ending balance	$ (58,486)	$ (76,476)

Summary Of Significant Accoun38

Summary Of Significant Accounting Policies 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, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ 286,937	$ 348,369	$ 522,075	$ 422,500	$ 292,472		$ 335,617		$ 449,132		$ 375,195		$ 1,579,881	$ 1,452,416	$ 1,760,913
Purchased Gas														(275,254)	(147,982)	(349,984)
Other Income														7,043	9,820	8,039
Income Before Income Taxes														444,164	(523,507)	(698,563)
Income Tax Expense														(160,682)	232,549	319,136
Net Income (Loss) Available for Common Stock		$ 45,577	$ 59,714	$ 89,283	$ 88,908	$ 37,553	[1]	$ 8,286	[2]	$ (147,688)	[3]	$ (189,109)	[4]	283,482	(290,958)	$ (379,427)
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														69,747	212,225
Income Tax Expense														(29,937)	(83,463)
Net Income (Loss) Available for Common Stock														39,810	128,762
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														1,575	1,374
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	[5]													(288)	(333)
Recognition of Net Actuarial Loss	[5]													(13,145)	(9,735)
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														83,983	216,823
Purchased Gas														(1,921)	4,520
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														$ (457)	$ (424)
[1]	Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[5]	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 Accoun39

Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Sep. 30, 2016
Summary Of Significant Accounting Policies [Line Items]
Prepayments		$ 10,927	$ 10,919
Prepaid Property and Other Taxes		13,974	13,138
Fair Values of Firm Commitments		1,031	3,962
Regulatory Assets	[1]	15,884	15,616
Other Current Assets		51,505	59,354
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		0	11,758
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		$ 9,689	$ 3,961
[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 Accoun40

Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liability	$ 34,059	$ 34,262
Other Accruals and Current Liabilities	111,889	74,430
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	37,382	26,796
Regulatory Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liability	34,059	14,725
Other Accruals [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	38,673	32,909
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	$ 1,775	$ 0

Asset Retirement Obligation (Na

Asset Retirement Obligation (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Asset Retirement Obligation [Line Items]
Liabilities Settled	$ 4,967	$ 72,215	$ 6,825
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, 2017	Sep. 30, 2016	Sep. 30, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at Beginning of Year	$ 112,330	$ 156,805	$ 117,713
Liabilities Incurred	2,963	2,719	4,433
Revisions of Estimates	(10,578)	16,721	33,717
Liabilities Settled	(4,967)	(72,215)	(6,825)
Accretion Expense	6,647	8,300	7,767
Balance at End of Year	$ 106,395	$ 112,330	$ 156,805

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2017USD ($)
Regulatory Matters [Line Items]
Amount of requested increase to annual revenues	$ 41.7
Recommended rate increase to annual revenues	$ 8.5
Recommended Equity Ratio	42.30%
Recommended Cost of Equity	8.60%
Approved Rate Increase	$ 5.9
Approved Cost of Equity	8.70%
Approved Equity Ratio	42.90%

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Sep. 30, 2016
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	$ 372,839	$ 515,315
Less: Amounts Included in Other Current Assets	[1]	(15,884)	(15,616)
Total Long-Term Regulatory Assets		174,433	320,750
Total Regulatory Liabilities		448,144	420,793
Less: Amounts Included in Current and Accrued Liabilities		(34,059)	(34,262)
Total Long-Term Regulatory Liabilities		113,716	99,789
Cost Of Removal Regulatory Liability [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		204,630	193,424
Taxes Refundable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		95,739	93,318
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		102,891	67,204
Amounts Payable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		0	19,537
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[2]	44,884	47,310
Total Long-Term Regulatory Liabilities		10,825	32,585
Non-Current Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Liabilities		414,085	386,531
Other Accruals and Current Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Current and Accrued Liabilities		(34,059)	(14,725)
Pension Costs Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	125,175	203,755
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	13,886	74,802
Recoverable Future Taxes [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	181,363	177,261
Environmental Site Remediation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	19,665	23,392
Asset Retirement Obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[3]	12,764	12,490
Unamortized Debt Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	1,159	1,688
Other [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	18,827	21,927
Total Long-Term Regulatory Assets		2,943	6,311
Long-Term Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Assets	[1]	356,955	499,699
Other Current Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Other Current Assets		$ (15,884)	$ (15,616)
[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]	$34,059 and $14,725 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $10,825 and $32,585 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.
[3]	Included in Other Regulatory Assets on the Consolidated Balance Sheets.
[4]	$15,884 and $15,616 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $2,943 and $6,311 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2017 and 2016, respectively.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Income Taxes [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	$ 31,900
Taxes Refundable to Customers	95,739	$ 93,318
Recoverable Future Taxes	181,363	177,261
Federal net operating loss, certain annual limitations	1,800
Deferred Income Taxes [Member]
Income Taxes [Line Items]
Taxes Refundable to Customers	95,700	93,300
Recoverable Future Taxes	181,400	177,300
Regulatory liabilities	52,600	52,600
Regulatory assets	$ 99,400	$ 94,200

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, 2017	Sep. 30, 2016	Sep. 30, 2015
Current Income Taxes [Abstract]
Federal	$ 32,034	$ (6,658)	$ 25,064
State	10,673	20,903	13,387
Deferred Income Taxes [Abstract]
Federal	103,046	(164,818)	(244,336)
State	14,929	(81,976)	(113,251)
Income Tax Expense (Benefit)	160,682	(232,549)	(319,136)
Deferred Investment Tax Credit	(173)	(348)	(414)
Total Income Taxes	160,509	(232,897)	(319,550)
Presented as Follows [Abstract]
Other Income	(173)	(348)	(414)
Income Tax Expense (Benefit)	$ 160,682	$ (232,549)	$ (319,136)

Income Taxes (Schedule Of Incom

Income Taxes (Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
U.S. Income (Loss) Before Income Taxes	$ 443,991	$ (523,855)	$ (698,977)
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%	155,397	(183,349)	(244,642)
State Income Taxes (Benefit)	16,641	(39,697)	(64,912)
Federal Tax Credits	(6,679)	(3,262)	(732)
Miscellaneous	(4,850)	(6,589)	(9,264)
Total Income Taxes	$ 160,509	$ (232,897)	$ (319,550)
Federal Statutory Rate	35.00%	35.00%	35.00%

Income Taxes (Significant Compo

Income Taxes (Significant Components Of Deferred Tax Liabilities And Assets) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Deferred Tax Liabilities [Abstract]
Property, Plant and Equipment	$ 1,141,432	$ 1,049,100
Pension and Other Post-Retirement Benefit Costs	79,516	151,903
Unrealized Hedging Gains	19,127	50,179
Other	57,919	55,457
Total Deferred Tax Liabilities	1,297,994	1,306,639
Deferred Tax Assets [Abstract]
Pension and Other Post-Retirement Benefit Costs	(123,532)	(195,829)
Tax Loss and Credit Carryforwards	(200,344)	(194,875)
Other	(82,831)	(92,140)
Total Deferred Tax Assets	(406,707)	(482,844)
Total Net Deferred Income Taxes	$ 891,287	$ 823,795

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Balance at Beginning of Year	$ 396	$ 5,085	$ 3,147
Additions for Tax Positions of Prior Years	1,251	396	2,504
Reductions for Tax Positions of Prior Years	(396)	(1,314)	(566)
Reductions Related to Settlements with Taxing Authorities	0	(3,771)	0
Balance at End of Year	$ 1,251	$ 396	$ 5,085

Income Taxes Income Taxes (Summ

Income Taxes Income Taxes (Summary of Operating Loss and Tax Credit Carryforwards) (Details) $ in Thousands	Sep. 30, 2017USD ($)
Federal [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	$ 184,289
Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	81,683
Research and Development Tax Credit Carryforward [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	5,694
Enhanced Oil Recovery Credit [Member] | Federal [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	10,502
Pennsylvania [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	324,572
California [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss	169,723
California [Member] | Alternative Minimum Tax Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	5,873
California [Member] | Enhanced Oil Recovery Credit [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforwards	$ 5,061

Capitalization And Short-Term51

Capitalization And Short-Term Borrowings (Narrative) (Details)	Sep. 18, 2017USD ($)	Sep. 30, 2017USD ($)$ / sharesshares	Sep. 30, 2017USD ($)$ / sharesshares	Sep. 30, 2016USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / sharesshares
Debt Instrument [Line Items]
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan | shares			180,247
Common stock issued for 401(k) plans | shares			103,602
Common stock shares issued due to stock option and SARs exercises | shares			(19,000)
Shares tendered | shares			53,564
Percentage of voting power			10.00%
Percentage of assets or earning power that are sold or transferred		50.00%	50.00%
Equity redemption price per share | $ / shares			$ 0.005
Voting power percentage to redeem rights			75.00%
Rights expiration date			Jul. 31, 2018
Share-Based Payment Expense			$ 10,800,000	$ 4,800,000	$ 2,100,000
Tax benefit related to stock-based compensation expense			4,400,000	1,900,000	900,000
Capitalized stock-based compensation costs			100,000	100,000	100,000
Tax benefit from stock-based compensation exercises and vestings			500,000
Carrying Amount		$ 2,383,681,000	$ 2,383,681,000	2,086,252,000
Percentage of Long-Term Debt issued under 1974 Indenture			4.10%
Net proceeds from issuance of long-term debt			$ 295,151,000	0	444,635,000
Principal amounts of long-term debt maturing in 2018		300,000,000	300,000,000
Principal amounts of long-term debt maturing in 2019		250,000,000	250,000,000
Principal amounts of long-term debt maturing in 2020		0	0
Principal amounts of long-term debt maturing in 2021		0	0
Principal amounts of long-term debt maturing in 2022		500,000,000	500,000,000
Principal amounts of long-term debt maturing after 2022		1,349,000,000	1,349,000,000
Commercial paper, outstanding		0	$ 0	0
Line of Credit Facility, Term Start Date			Oct. 1, 2017
Short-term notes payable outstanding		0	$ 0	0
Debt to capitalization ratio			0.58
Additional borrowing		1,150,000,000	$ 1,150,000,000
Maximum debt increase under existing indenture covenants		$ 126,000,000
Aggregated indebtedness			$ 40,000,000
Preferred stock, shares authorized | shares		10,000,000	10,000,000
Preferred stock par value | $ / shares		$ 1	$ 1
Committed credit facility, outstanding amount		$ 0	$ 0
Stock Options And SARs [Member]
Debt Instrument [Line Items]
Common stock shares issued due to stock option and SARs exercises | shares			45,912
Stock Options [Member]
Debt Instrument [Line Items]
Options, exercises in period, total intrinsic value			$ 300,000	4,100,000	5,100,000
Proceeds from Stock Options Exercised			$ 800,000	$ 8,000,000	$ 5,600,000
Stock Appreciation Rights (SARs) [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares			0	0	0
Total intrinsic value of SAR's exercised			$ 1,600,000	$ 400,000	$ 2,000,000
Number of Awards Vested | shares			5,000	113,082	157,386
Equity instruments other than options, vested in period, total fair value			$ 100,000	$ 1,200,000	$ 1,700,000
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		300,000	$ 300,000
Unrecognized compensation expense recognized weighted average period			3 years 1 month 13 days
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Number of Shares Granted | shares			87,143	101,943	88,899
Weighted Average Fair Value per Award Granted | $ / shares			$ 52.13	$ 35.89	$ 64.04
Number of Awards Vested | shares			80,530
Unrecognized compensation expense		4,700,000	$ 4,700,000
Unrecognized compensation expense recognized weighted average period			2 years 2 months 13 days
Performance Shares [Member]
Debt Instrument [Line Items]
Common stock issued | shares			43,484
Number of Shares Granted | shares			184,148	309,996	107,044
Weighted Average Fair Value per Award Granted | $ / shares			$ 56.39	$ 30.71	$ 65.26
Number of Awards Vested | shares			43,484
Unrecognized compensation expense		10,100,000	$ 10,100,000
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			80,530
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
6.50% Notes Due April 2018 [Member]
Debt Instrument [Line Items]
Long-term debt, face value		$ 300,000,000	$ 300,000,000
Long-term debt, interest rate		6.50%	6.50%
Indenture From 1974 [Member]
Debt Instrument [Line Items]
Carrying Amount		$ 98,700,000	$ 98,700,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Commercial paper available		500,000,000	$ 500,000,000
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued | shares			24,028
Third Amended & Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		750,000,000	$ 750,000,000
364-Day Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 500,000,000	$ 500,000,000
Last Day of Fiscal Quarter Through September 30, 2017 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date			Sep. 30, 2017
Committed credit facility debt to capitalization ratio			0.675
Last Day of Fiscal Quarter October 1, 2017 through December 5, 2019 [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date			Dec. 5, 2019
Committed credit facility debt to capitalization ratio			0.65
2018 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			73,819
2018 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			88,132
2019 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			65,265
2019 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			255,468
2020 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			52,641
2020 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			184,148
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			27,976
2022 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			13,498

Capitalization And Short-Term52

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, 2017		Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016		Jun. 30, 2016	[2]	Mar. 31, 2016	[3]	Dec. 31, 2015		Sep. 30, 2017		Sep. 30, 2016	Sep. 30, 2015
Schedule of Capitalization [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term															0 years
Beginning balance (shares)						85,118,886									85,118,886
Beginning balance						$ 771,164									$ 771,164
Balance at Beginning of Year						676,361							$ 1,103,200		676,361		$ 1,103,200	$ 1,614,361
Beginning balance						(5,640)							93,372		(5,640)		93,372
Net Income (Loss) Available for Common Stock		$ 45,577		$ 59,714	$ 89,283	$ 88,908	$ 37,553	[1]	$ 8,286		$ (147,688)		$ (189,109)	[4]	283,482		(290,958)	(379,427)
Dividends Declared on Common Stock															(140,090)		(135,881)	(131,734)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation		$ 31,900													31,900
Other Comprehensive Income (Loss), Net of Tax															(24,483)		(99,012)	97,351
Share-Based Payment Expense															$ 10,800		$ 4,800	2,100
Ending balance (Shares)		85,543,125					85,118,886								85,543,125		85,118,886
Ending balance		$ 796,646					$ 771,164								$ 796,646		$ 771,164
Balance at End of Year		851,669					676,361								851,669		676,361	1,103,200
Ending balance		(30,123)					$ (5,640)								$ (30,123)		$ (5,640)	$ 93,372
Dividend per share															$ 1.64		$ 1.60	$ 1.56
Tax benefit related to stock-based compensation recorded to Paid in Capital																	$ 1,868	$ 9,064
Accumulated earnings free from limitations		$ 707,500													$ 707,500
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term															0 years
Common Stock [Member]
Schedule of Capitalization [Line Items]
Beginning balance (shares)						85,119,000							84,594,000		85,119,000		84,594,000	84,157,000
Beginning balance (value)						$ 85,119							$ 84,594		$ 85,119		$ 84,594	$ 84,157
Common Stock Issued Under Stock and Benefit Plans (Shares)	[5]														424,000		525,000	437,000
Common Stock Issued Under Stock and Benefit Plans (Value)	[5]														$ 424		$ 525	$ 437
Ending balance (Shares)		85,543,000					85,119,000								85,543,000		85,119,000	84,594,000
Ending balance (Value)		$ 85,543					$ 85,119								$ 85,543		$ 85,119	$ 84,594
Paid In Capital [Member]
Schedule of Capitalization [Line Items]
Beginning balance						771,164							744,274		771,164		744,274	716,144
Share-Based Payment Expense	[6]														10,902		4,843	2,207
Common Stock Issued Under Stock and Benefit Plans (Value)	[5]														14,580		22,047	25,923
Ending balance		796,646					771,164								796,646		771,164	744,274
Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year						676,361							1,103,200		676,361		1,103,200	1,614,361
Net Income (Loss) Available for Common Stock															283,482		(290,958)	(379,427)
Dividends Declared on Common Stock															(140,090)		(135,881)	(131,734)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation		31,916													31,916
Balance at End of Year		851,669	[7]				676,361								851,669	[7]	676,361	1,103,200
Accumulated Other Comprehensive Income (Loss) [Member]
Schedule of Capitalization [Line Items]
Beginning balance						$ (5,640)							$ 93,372		(5,640)		93,372	(3,979)
Other Comprehensive Income (Loss), Net of Tax															(24,483)		(99,012)	97,351
Ending balance		$ (30,123)					$ (5,640)								$ (30,123)		$ (5,640)	$ 93,372
[1]	Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[5]	Paid in Capital includes tax benefits of $1.9 million and $9.1 million for September 30, 2016 and 2015, respectively, related to stock-based compensation.
[6]	Paid in Capital includes compensation costs associated with stock option, SARs, performance share and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.
[7]	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, 2017, $707.5 million of accumulated earnings was free of such limitations.

Capitalization And Short-Term53

Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Stock Options And Share Awards) (Details) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		19,000
Number of Shares Granted		0
Number of Shares Exercised		(19,000)
Number of Shares Forfeited		0
Number of Shares Outstanding, End of Year		0	19,000
Number of Option shares exercisable		0
Number of Shares Subject to Option, Option shares available for future grant	[1]	2,182,243
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 39.48
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		39.48
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Outstanding End of Year		0	$ 39.48
Weighted Average Exercise Price, Option shares exercisable		$ 0
Weighted Average Remaining Contractual Life, Outstanding		0 years
Weighted Average Remaining Contractual Life, Option shares exercisable		0 years
Aggregate Intrinsic Value Outstanding		$ 0
Aggregate Intrinsic Value, Option Shares exercisable		$ 0
Performance Shares [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		438,234
Number of Shares Granted		184,148	309,996	107,044
Number of Awards Vested		(43,484)
Number of Shares Forfeited		(51,150)
Number of Shares Outstanding, End of Year		527,748	438,234
Weighted Average Fair Value per Award, Beginning of Year		$ 44.98
Weighted Average Fair Value per Award Granted		56.39	$ 30.71	$ 65.26
Weighted Average Fair Value per Award Vested		69.13
Weighted Average Fair Value per Award Forfeited		60.74
Weighted Average Fair Value per Award, End of Year		$ 45.44	$ 44.98
Stock Appreciation Rights (SARs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		1,590,988
Number of Shares Granted		0	0	0
Number of Shares Exercised		(82,077)
Number of Awards Vested		(5,000)	(113,082)	(157,386)
Number of Shares Forfeited		0
Number of Shares Expired		(3,000)
Number of Shares Outstanding, End of Year		1,505,911	1,590,988
Number of SARs exercisable		1,505,911
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 48.19
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		39.77
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Expired		52.10
Weighted Average Exercise Price, Outstanding End of Year		48.64	$ 48.19
Weighted Average Exercise Price, SARs exercisable		$ 48.64
Weighted Average Remaining Contractual Life, Outstanding		2 years 6 months 6 days
Weighted Average Remaining Contractual Life, SARs exercisable		2 years 6 months 6 days
Aggregate Intrinsic Value Outstanding		$ 13,144
Aggregate Intrinsic Value, SARs exercisable		$ 13,144
[1]	Includes shares available for options, SARs, restricted stock and performance share grants.

Capitalization And Short-Term54

Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
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	239,151
Number of Shares Granted	87,143	101,943	88,899
Number of Awards Vested	(80,530)
Number of Shares Forfeited	(12,565)
Number of Shares Outstanding, End of Year	233,199	239,151
Weighted Average Fair Value per Award, Beginning of Year	$ 49.67
Weighted Average Fair Value per Award Granted	52.13	$ 35.89	$ 64.04
Weighted Average Fair Value per Award Vested	53.38
Weighted Average Fair Value per Award Forfeited	53.75
Weighted Average Fair Value per Award, End of Year	$ 48.99	$ 49.67

Capitalization And Short-Term55

Capitalization And Short-Term Borrowings (Weighted Average Assumptions Used In Estimating Fair Value) (Details) - Performance Shares [Member]	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk Free Interest Rate	1.54%	1.26%	1.01%
Remaining Term at Date of Grant (Years)	2 years 9 months 14 days	2 years 9 months 14 days	2 years 9 months 12 days
Expected Volatility Rate	22.60%	20.50%	20.10%

Capitalization And Short-Term56

Capitalization And Short-Term Borrowings (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 18, 2017
Debt Instrument [Line Items]
Total Long-Term Debt		$ 2,399,000	$ 2,099,000
Less Unamortized Discount and Debt Issuance Costs		15,319	12,748
Less Current Portion	[1]	300,000	0
Long-term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		2,083,681	2,086,252
Debt Instrument redeemed		307,000
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%
3.95% Notes Due September 15, 2027 [Member]
Debt Instrument [Line Items]
Long-term debt, face value				$ 300,000
Long-term debt, interest rate				3.95%
Maximum interest rate adjustment		2.00%
7.4% Due March 2023 To June 2025 [Member]
Debt Instrument [Line Items]
Medium-Term Notes	[2]	$ 99,000	$ 99,000
Long-term debt, interest rate		7.40%	7.40%
3.75% To 8.75% Due April 2018 To September 2027 [Member]
Debt Instrument [Line Items]
Notes	[2],[3],[4]	$ 2,300,000	$ 2,000,000
Percentage of principal amount		101.00%	101.00%
Minimum [Member] | 3.75% To 8.75% Due April 2018 To September 2027 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate		3.75%	3.75%
Maximum [Member] | 3.75% To 8.75% Due April 2018 To September 2027 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate		8.75%	8.75%
[1]	Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes scheduled to mature in April 2018. The Company redeemed these 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 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 ($)		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	[1]	$ 1,741,000	$ 1,484,000
Level 1 or Level 2 Transfers		0	0
Derivative Financial Instruments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Level 3 Fair Value		0	0
Level 1 or Level 2 Transfers		0	0
Sales of Derivative Financial Instruments			0
Purchases of Derivative Financial Instruments		0	0
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		1,741,000	1,484,000
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		1,700,000	1,500,000
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, 2017	Sep. 30, 2016
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 527,978	$ 113,407
Hedging Collateral Deposits	[1]	1,741	1,484
Total Assets	[1]	651,740	299,650
Total Liabilities	[1]	1,103	1,462
Total Net Assets/(Liabilities)	[1]	650,637	298,188
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	520	347
Derivative Liability	[1]	0	0
Over Counter Swaps Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	34,771	115,794
Derivative Liability	[1]	1,103	1,462
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	820	(2,337)
Derivative Liability	[1]	0	0
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	37,033	36,658
Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	45,727	31,395
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	3,150	2,902
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		527,978	113,407
Hedging Collateral Deposits		1,741	1,484
Total Assets		617,112	188,469
Total Liabilities		963	2,276
Total Net Assets/(Liabilities)		616,149	186,193
Fair Value, Inputs, Level 1 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		1,483	2,623
Derivative Liability		963	2,276
Fair Value, Inputs, Level 1 [Member] | Over 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		37,033	36,658
Fair Value, Inputs, Level 1 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		45,727	31,395
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		3,150	2,902
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		40,204	119,654
Total Liabilities		5,716	7,659
Total Net Assets/(Liabilities)		34,488	111,995
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 Counter Swaps Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		38,977	119,654
Derivative Liability		5,309	5,322
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		1,227	0
Derivative Liability		407	2,337
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 Counter Swaps Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Netting Adjustments [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	0	0
Hedging Collateral Deposits	[1]	0	0
Total Assets	[1]	(5,576)	(8,473)
Total Liabilities	[1]	(5,576)	(8,473)
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]	(963)	(2,276)
Derivative Liability	[1]	(963)	(2,276)
Netting Adjustments [Member] | Over Counter Swaps Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(4,206)	(3,860)
Derivative Liability	[1]	(4,206)	(3,860)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(407)	(2,337)
Derivative Liability	[1]	(407)	(2,337)
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, 2017USD ($)counterpartyMMcfbbl	Sep. 30, 2016USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Cash Surrender Value of Life Insurance		$ 39,400,000	$ 39,700,000
Net hedging gains (losses) in accumulated other comprehensive income (loss)		35,500,000
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)		20,800,000
Pre-tax Net hedging gains (losses) reclassified within twelve months		18,000,000
After tax Net hedging gains (losses) reclassified within twelve months		10,600,000
Fair market value of derivative asset with a credit-risk related contingency		26,000,000
Hedging collateral deposits	[1]	1,741,000	1,484,000
Equity Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		37,000,000	36,700,000
Gross unrealized gain		9,900,000	7,900,000
Fixed Income Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		45,700,000	31,400,000
Gross unrealized loss		100,000
Gross unrealized gain			100,000
Insurance Company Stock [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		3,200,000	2,900,000
Gross unrealized gain		2,200,000	$ 1,600,000
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount		$ 89,200,000
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		17,500
Exchange-Traded Futures Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedging collateral deposits		$ 1,700,000
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		16,400
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		1,100
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		17
Number of counterparties in net gain position | counterparty		16
Credit risk exposure per counterparty		$ 2,200,000
Maximum credit risk exposure per counterparty		6,000,000
Collateral Received from Counterparties by the Company		0
Hedging collateral deposits		$ 0
Over the Counter Swaps and Foreign Currency Forward Contracts [Member] | Credit Risk Related Contingency Feature [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties with a common credit-risk related contingency | counterparty		14
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		114,300
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		3,459,000
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		1,000
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Financial Instruments (Long-Ter

Financial Instruments (Long-Term Debt) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,383,681	$ 2,086,252
Fair Value	$ 2,523,639	$ 2,255,562

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, 2017	Sep. 30, 2016	Sep. 30, 2015
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)	$ 5,347	$ 60,493	$ 381,018
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)	81,605	220,919
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	(100)	392
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)	2,700	194
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)	(457)	(424)
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)	2,811	58,714
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)	83,983	216,823
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	(100)	392
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)	(164)	1,585
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)	(1,921)	4,520
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$ 0	$ 0

Financial Instruments (Schedu62

Financial Instruments (Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2017USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	$ 2,119
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	(2,119)
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	1,655
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	(1,655)
Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	464
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	$ (464)

Retirement Plan And Other Pos63

Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
Increase to accumulated other comprehensive income	$ 44,731,000	$ 171,586,000	$ (169,919,000)
Expected future benefit payments in year one	64,400,000
Expected future benefit payments in year two	65,000,000
Expected future benefit payments in year three	65,400,000
Expected future benefit payments in year four	65,800,000
Expected future benefit payments in year five	66,200,000
Expected future benefit payments in five years thereafter	331,100,000
Effect of one percentage point increase on accumulated postretirement benefit obligation	57,900,000
Effect of one percentage point increase on service and interest cost components	3,300,000
Effect of one percentage point decrease on accumulated postretirement benefit obligation	48,500,000
Effect of one percentage point decrease on service and interest cost components	2,700,000
Benefit assets transferred	0	0
Benefit assets transferred in/out of Level 3	0	0
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	7,600,000	7,500,000	7,000,000
Accumulated benefit obligation	72,500,000	72,400,000	66,000,000
Benefit obligation	$ 88,900,000	$ 91,700,000	$ 85,800,000
Discount rate	3.22%	2.80%	3.50%
Rate of compensation increase	7.75%	7.75%	7.75%
Tax-Deferred Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	$ 5,900,000	$ 5,900,000	$ 5,800,000
Retirement Savings Account [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	2,900,000	2,600,000	2,300,000
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	163,300,000
Increase to accumulated other comprehensive income	29,100,000
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	34,848,000	32,095,000	37,700,000
Accumulated benefit obligation	1,010,179,000	1,039,408,000	968,984,000
Benefit obligation	$ 1,054,826,000	$ 1,097,421,000	$ 1,026,190,000	$ 999,499,000
Discount rate	3.77%	3.60%	4.25%
Rate of compensation increase	4.70%	4.70%	4.75%
Employer Contributions	$ 17,146,000	$ 7,000,000	$ 36,200,000
Expected long term rate of return on plan assets	7.00%	7.25%	7.50%
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	$ 14,092,000	$ 12,923,000	$ 10,446,000
Benefit obligation	$ 462,619,000	$ 526,138,000	$ 464,987,000	$ 465,583,000
Discount rate	3.81%	3.70%	4.50%
Rate of compensation increase	4.70%	4.70%	4.75%
Employer Contributions	$ 3,853,000	$ 2,839,000	$ 2,161,000
Expected future benefit payments in year one	26,483,000
Expected future benefit payments in year two	27,456,000
Expected future benefit payments in year three	28,359,000
Expected future benefit payments in year four	29,173,000
Expected future benefit payments in year five	29,757,000
Expected future benefit payments in five years thereafter	$ 152,957,000
Expected long term rate of return on plan assets	6.50%	6.75%	7.00%
VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	$ 3,800,000
Other Actuarial Experience [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(3,600,000)
Other Actuarial Experience [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(50,300,000)	$ 11,000,000	$ 12,800,000
Mortality Assumption Change [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation			24,200,000
Mortality Improvement Projection Scale [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(8,300,000)
Mortality Improvement Projection Scale [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(5,700,000)
Discount Rate Change [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(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	$ (6,200,000)	49,400,000	(14,300,000)
Effective Fiscal 2018 [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	7.00%
Effective Fiscal 2018 [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	6.25%
Minimum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 15,000,000
Minimum [Member] | VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 2,500,000
Minimum [Member] | Equity Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	40.00%
Minimum [Member] | Fixed Income Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	40.00%
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	$ 40,000,000
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	60.00%
Maximum [Member] | Fixed Income Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	60.00%
Maximum [Member] | Other Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target Allocation	15.00%
Other Accruals And Current Liabilities [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 14,100,000	9,800,000	4,500,000
Non-Current [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	$ 74,800,000	$ 81,900,000	$ 81,300,000

Retirement Plan And Other Pos64

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, 2017	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Non-Current Assets		$ 56,370	$ 17,649
Amortization period		10 years
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 1,097,421	1,026,190	$ 999,499
Service Cost		11,969	11,710	12,047
Interest Cost		38,383	42,315	41,217
Plan Participants' Contributions		0	0	0
Retiree Drug Subsidy Receipts		0	0	0
Amendments	[1]	0	0	7,752
Actuarial (Gain) Loss		(32,466)	76,309	23,426
Benefits Paid		(60,481)	(59,103)	(57,751)
Benefit Obligation at End of Period		1,054,826	1,097,421	1,026,190
Fair Value of Assets at Beginning of Period		869,775	834,870	869,791
Actual Return on Plan Assets		84,279	87,008	(13,370)
Employer Contributions		17,146	7,000	36,200
Plan Participants' Contributions		0	0	0
Benefits Paid		(60,481)	(59,103)	(57,751)
Fair Value of Assets at End of Period		910,719	869,775	834,870
Net Amount Recognized at End of Period (Funded Status)		(144,107)	(227,646)	(191,320)
Non-Current Liabilities		(144,107)	(227,646)	(191,320)
Non-Current Assets		0	0	0
Accumulated Benefit Obligation		$ 1,010,179	$ 1,039,408	$ 968,984
Discount Rate		3.77%	3.60%	4.25%
Rate of Compensation Increase		4.70%	4.70%	4.75%
Expected Return on Plan Assets		$ (59,718)	$ (59,369)	$ (59,615)
Amortization of Prior Service Cost (Credit)		1,058	1,234	183
Recognition of Actuarial Loss	[2]	42,687	32,248	36,129
Net Amortization and Deferral for Regulatory Purposes		469	3,957	7,739
Net Periodic Benefit Cost		$ 34,848	$ 32,095	$ 37,700
Discount Rate		3.60%	4.25%	4.25%
Expected Return on Plan Assets		7.00%	7.25%	7.50%
Rate of Compensation Increase		4.75%	4.75%	4.75%
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 526,138	$ 464,987	$ 465,583
Service Cost		2,449	2,331	2,693
Interest Cost		19,007	20,386	19,285
Plan Participants' Contributions		2,717	2,558	2,242
Retiree Drug Subsidy Receipts		1,553	1,925	1,338
Amendments	[1]	0	0	0
Actuarial (Gain) Loss		(62,215)	60,402	(1,575)
Benefits Paid		(27,030)	(26,451)	(24,579)
Benefit Obligation at End of Period		462,619	526,138	464,987
Fair Value of Assets at Beginning of Period		494,320	477,959	497,601
Actual Return on Plan Assets		40,157	37,415	534
Employer Contributions		3,853	2,839	2,161
Plan Participants' Contributions		2,717	2,558	2,242
Benefits Paid		(27,030)	(26,451)	(24,579)
Fair Value of Assets at End of Period		514,017	494,320	477,959
Net Amount Recognized at End of Period (Funded Status)		51,398	(31,818)	12,972
Non-Current Liabilities		(4,972)	(49,467)	(11,487)
Non-Current Assets		$ 56,370	$ 17,649	$ 24,459
Discount Rate		3.81%	3.70%	4.50%
Rate of Compensation Increase		4.70%	4.70%	4.75%
Expected Return on Plan Assets		$ (31,458)	$ (31,535)	$ (34,089)
Amortization of Prior Service Cost (Credit)		(429)	(912)	(1,913)
Recognition of Actuarial Loss	[2]	18,415	5,530	4,148
Net Amortization and Deferral for Regulatory Purposes		6,108	17,123	20,322
Net Periodic Benefit Cost		$ 14,092	$ 12,923	$ 10,446
Discount Rate		3.70%	4.50%	4.25%
Expected Return on Plan Assets		6.50%	6.75%	7.00%
Rate of Compensation Increase		4.75%	4.75%	4.75%
[1]	In fiscal 2015, the Company passed an amendment which updated the mortality table used in the Retirement Plan's definition of "actuarially equivalent" effective July 1, 2015. This increased the benefit obligation of the Retirement Plan.
[2]	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 Pos65

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, 2017USD ($)	[1]
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	$ (24,332)
Prior Service (Cost) Credit	0
Net Amount Recognized	(24,332)
Decrease (Increase) in Actuarial Loss, excluding amortization	(1,351)	[2]
Change due to Amortization of Actuarial Loss	4,059
Prior Service (Cost) Credit	0
Net Change	2,708
Net Actuarial Loss	(3,549)
Prior Service (Cost) Credit	0
Net Amount Expected to be Recognized	(3,549)
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(203,887)
Prior Service (Cost) Credit	(6,133)
Net Amount Recognized	(210,020)
Decrease (Increase) in Actuarial Loss, excluding amortization	57,028	[2]
Change due to Amortization of Actuarial Loss	42,687
Prior Service (Cost) Credit	1,058
Net Change	100,773
Net Actuarial Loss	(37,205)
Prior Service (Cost) Credit	(938)
Net Amount Expected to be Recognized	(38,143)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(19,578)
Prior Service (Cost) Credit	3,687
Net Amount Recognized	(15,891)
Decrease (Increase) in Actuarial Loss, excluding amortization	70,915	[2]
Change due to Amortization of Actuarial Loss	18,415
Prior Service (Cost) Credit	(429)
Net Change	88,901
Net Actuarial Loss	(10,558)
Prior Service (Cost) Credit	429
Net Amount Expected to be Recognized	$ (10,129)
[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 Pos66

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Sep. 30, 2017USD ($)
Defined Benefit Plan Disclosure [Line Items]
2018 - Benefit Payments	$ 64,400
2019 - Benefit Payments	65,000
2020 - Benefit Payments	65,400
2021 - Benefit Payments	65,800
2022 - Benefit Payments	66,200
2023 through 2027 - Benefit Payments	331,100
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
2018 - Benefit Payments	26,483
2018 - Subsidy Receipts	(1,910)
2019 - Benefit Payments	27,456
2019 - Subsidy Receipts	(2,074)
2020 - Benefit Payments	28,359
2020 - Subsidy Receipts	(2,225)
2021 - Benefit Payments	29,173
2021 - Subsidy Receipts	(2,369)
2022 - Benefit Payments	29,757
2022 - Subsidy Receipts	(2,515)
2023 through 2027 - Benefit Payments	152,957
2023 through 2027 - Subsidy Receipts	$ (14,271)

Retirement Plan And Other Pos67

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Health Care Cost Trend Rates) (Details)	12 Months Ended
	Sep. 30, 2017		Sep. 30, 2016		Sep. 30, 2015
Retirement Benefits [Abstract]
Rate of Medical Cost Increase for Pre Age 65 Participants	5.67%	[1]	5.75%	[1]	6.93%	[2]
Rate of Medical Cost Increase for Post Age 65 Participants	4.75%	[1]	4.75%	[1]	6.68%	[2]
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	8.45%	[1]	9.00%	[1]	7.17%	[2]
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	4.75%	[1]	4.75%	[1]	6.68%	[2]
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	7.33%	[1]	7.20%	[1]	6.65%	[2]
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.
[2]	It was assumed that this rate would gradually decline to 4.5% by 2028.

Retirement Plan And Other Pos68

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Fair Value Of Plan Assets) (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ 910,719	$ 869,775	$ 834,870	$ 869,791
Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	290,716	256,796
Investments Measured at NAV	[1],[2]	81,295	68,543
Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	123,069	104,592
Investments Measured at NAV	[2],[3]	123,069	104,592
Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	121,008	120,025
Investments Measured at NAV	[2],[4]	121,008	120,025
Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	348,501	342,442
Investments Measured at NAV	[2],[5]	0	0
Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	422	744
Investments Measured at NAV	[2],[6]	0	0
Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	75,428	81,146
Investments Measured at NAV	[2],[7]	75,428	81,146
Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		3,391	2,970
Investments Measured at NAV	[2]	0	0
Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		988,593	933,527
Investments Measured at NAV	[2]	426,858	399,118
Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(64,728)	(58,707)
Investments Measured at NAV	[2]	(27,476)	(24,939)
Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		923,865	874,820
Investments Measured at NAV	[2]	399,382	374,179
Retirement Plan [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		26,058	24,812
Investments Measured at NAV	[2]	26,058	24,812
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		514,017	494,320	$ 477,959	$ 497,601
Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		64,728	58,707
Investments Measured at NAV	[2]	27,476	24,939
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		130,864	139,617
Investments Measured at NAV	[2]	130,864	139,617
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		52,063	51,488
Investments Measured at NAV	[2]	52,063	51,488
Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		256,099	230,761
Investments Measured at NAV	[2]	0	0
Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		9,569	13,176
Investments Measured at NAV	[2]	9,569	13,176
Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		448,595	435,042
Investments Measured at NAV	[2]	192,496	204,281
Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		513,323	493,749
Investments Measured at NAV	[2]	219,972	229,220
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	209,421	188,253
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	0	0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	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	[5]	1,664	1,647
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	422	407
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	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] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		211,507	190,307
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(14,026)	(12,025)
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		197,481	178,282
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] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		14,026	12,025
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		256,099	230,761
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] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		256,099	230,761
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		270,125	242,786
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	[3]	0	0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	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	[5]	346,837	340,795
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	0	337
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[7]	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] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		346,837	341,132
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(23,001)	(21,555)
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		323,836	319,577
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] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		23,001	21,555
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] | 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] | 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		23,001	21,555
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	[3]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	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	[5]	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	[6]	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	[7]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		3,391	2,970
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		3,391	2,970
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(225)	(188)
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		3,166	2,782
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] | Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		225	188
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] | 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] | 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		225	188
Miscellaneous Accruals, Interest Receivables, And Non-Interest Cash [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(13,146)	(5,045)
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		$ 694	$ 571
[1]	Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
[2]	Reflects the adoption of the new authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.
[3]	International Equities are comprised of collective trust funds.
[4]	Global Equities are comprised of collective trust funds.
[5]	Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.
[6]	International Fixed Income securities are comprised mostly of an exchange traded fund.
[7]	Global Fixed Income securities are comprised of a collective trust fund.

Retirement Plan And Other Pos69

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, 2017	Sep. 30, 2016
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	$ 2,782	$ 29,329
Realized Gains/(Losses)		5,524
Unrealized Gains/(Losses)	384	(5,505)
Sales		(26,566)
Balance, End of Year	3,166	2,782
Hedge Funds Investments [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	0	26,490
Realized Gains/(Losses)		5,878
Unrealized Gains/(Losses)	0	(5,445)
Sales		(26,923)
Balance, End of Year	0	0
Real Estate [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	2,970	4,724
Realized Gains/(Losses)		0
Unrealized Gains/(Losses)	421	(404)
Sales		(1,350)
Balance, End of Year	3,391	2,970
Excluding 401(h) Investments [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	(188)	(1,885)
Realized Gains/(Losses)		(354)
Unrealized Gains/(Losses)	(37)	344
Sales		1,707
Balance, End of Year	(225)	(188)
401(h) Investments [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	188	1,885
Realized Gains/(Losses)		354
Unrealized Gains/(Losses)	37	(344)
Sales		(1,707)
Balance, End of Year	$ 225	$ 188

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2017USD ($)
Site Contingency [Line Items]
Estimate minimum liability for environmental remediation	$ 3.1
Project Costs	75.8
Future purchase obligation first year	262.4
Future purchase obligation second year	84.6
Future purchase obligation third year	77.9
Future purchase obligation fourth year	70.9
Future purchase obligation fifth year	61.7
Future purchase obligation thereafter	504.9
Operating lease commitment first year	10.8
Operating lease commitment second year	4.6
Operating lease commitment third year	3.7
Operating lease commitment fourth year	2.2
Operating lease commitment fifth year	1.5
Operating lease commitment thereafter	$ 1.9
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	$ 61.7
Contract commitments second year	0.7
Contract commitments third year	0.2
Contractual commitments fourth year	0.3
Contractual commitments fifth year	0.3
Contractual commitments thereafter	1.1
Exploration And Production [Member]
Site Contingency [Line Items]
Contract commitments first year	79.5
Contract commitments second year	98
Contract commitments third year	$ 17.1

Business Segment Information (N

Business Segment Information (Narrative) (Details)	12 Months Ended
	Sep. 30, 2017segment
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, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Segment Reporting Information [Line Items]
Interest Income														$ 4,113	$ 4,235	$ 3,922
Interest Expense														119,837	121,044	99,471
Depreciation, Depletion and Amortization														224,195	249,417	336,158
Income Tax Expense (Benefit)														160,682	(232,549)	(319,136)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties						$ 32,700		$ 82,700		$ 397,400		$ 435,500		0	948,307	1,126,257
Segment Profit: Net Income (Loss)		$ 45,577	$ 59,714	$ 89,283	$ 88,908	37,553	[1]	$ 8,286	[2]	$ (147,688)	[3]	$ (189,109)	[4]	283,482	(290,958)	(379,427)
Expenditures for Additions to Long-Lived Assets														462,117	523,051	1,000,509
Segment Assets		6,103,320				5,636,387								6,103,320	5,636,387	6,564,939
Utility [Member]
Segment Reporting Information [Line Items]
Interest Income														1,051	1,737	2,220
Interest Expense														28,492	27,582	28,176
Depreciation, Depletion and Amortization														52,582	48,618	45,616
Income Tax Expense (Benefit)														24,894	25,602	33,143
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0	0
Segment Profit: Net Income (Loss)														46,935	50,960	63,271
Expenditures for Additions to Long-Lived Assets														80,867	98,007	94,371
Segment Assets		2,013,123				2,021,514								2,013,123	2,021,514	1,934,731
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Interest Income														1,467	770	474
Interest Expense														33,717	33,327	27,658
Depreciation, Depletion and Amortization														41,196	43,273	38,178
Income Tax Expense (Benefit)														40,947	50,241	48,113
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0	0
Segment Profit: Net Income (Loss)														68,446	76,610	80,354
Expenditures for Additions to Long-Lived Assets														95,336	114,250	230,192
Segment Assets		1,929,788				1,680,734								1,929,788	1,680,734	1,590,524
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Interest Income														707	858	2,554
Interest Expense														53,702	55,434	46,726
Depreciation, Depletion and Amortization														112,565	139,963	239,818
Income Tax Expense (Benefit)														66,093	(334,029)	(428,217)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															948,307	1,126,257
Segment Profit: Net Income (Loss)														129,326	(452,842)	(556,974)
Expenditures for Additions to Long-Lived Assets														253,057	256,104	557,313
Segment Assets		1,407,152				1,323,081								1,407,152	1,323,081	2,439,801
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Interest Income														571	422	195
Interest Expense														47	49	27
Depreciation, Depletion and Amortization														279	278	209
Income Tax Expense (Benefit)														891	2,460	4,547
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0	0
Segment Profit: Net Income (Loss)														1,509	4,348	7,766
Expenditures for Additions to Long-Lived Assets														36	34	128
Segment Assets		60,937				63,392								60,937	63,392	90,676
Gathering [Member]
Segment Reporting Information [Line Items]
Interest Income														994	297	140
Interest Expense														9,142	8,872	1,627
Depreciation, Depletion and Amortization														16,162	15,282	10,829
Income Tax Expense (Benefit)														29,694	24,334	24,721
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0	0
Segment Profit: Net Income (Loss)														40,377	30,499	31,849
Expenditures for Additions to Long-Lived Assets														32,645	54,293	118,166
Segment Assets		580,051				534,259								580,051	534,259	444,358
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Interest Income														4,790	4,084	5,583
Interest Expense														125,100	125,264	104,214
Depreciation, Depletion and Amortization														222,784	247,414	334,650
Income Tax Expense (Benefit)														162,519	(231,392)	(317,693)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															948,307	1,126,257
Segment Profit: Net Income (Loss)														286,593	(290,425)	(373,734)
Expenditures for Additions to Long-Lived Assets														461,941	522,688	1,000,170
Segment Assets		5,991,051				5,622,980								5,991,051	5,622,980	6,500,090
All Other [Member]
Segment Reporting Information [Line Items]
Interest Income														213	117	66
Interest Expense														0	0	0
Depreciation, Depletion and Amortization														661	1,260	832
Income Tax Expense (Benefit)														(247)	561	13
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0	0
Segment Profit: Net Income (Loss)														(342)	778	(2)
Expenditures for Additions to Long-Lived Assets														39	37	0
Segment Assets		76,861				77,138								76,861	77,138	77,350
Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Interest Income														(890)	34	(1,727)
Interest Expense														(5,263)	(4,220)	(4,743)
Depreciation, Depletion and Amortization														750	743	676
Income Tax Expense (Benefit)														(1,590)	(1,718)	(1,456)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0	0
Segment Profit: Net Income (Loss)														(2,769)	(1,311)	(5,691)
Expenditures for Additions to Long-Lived Assets														137	326	339
Segment Assets		$ 35,408				$ (63,731)								35,408	(63,731)	(12,501)
Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													1,579,881	1,452,416	1,760,913
Revenue from External Customers [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													626,899	531,024	700,761
Revenue from External Customers [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													206,615	215,674	203,089
Revenue from External Customers [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													614,599	607,113	693,441
Revenue from External Customers [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													128,586	93,578	159,857
Revenue from External Customers [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													115	374	497
Revenue from External Customers [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													1,576,814	1,447,763	1,757,645
Revenue from External Customers [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													2,173	3,753	2,352
Revenue from External Customers [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue	[5]													894	900	916
Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue														0	0	0
Intersegment Revenues [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue														13,072	13,123	15,506
Intersegment Revenues [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue														87,810	90,755	88,251
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														794	884	849
Intersegment Revenues [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue														107,566	89,073	76,709
Intersegment Revenues [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue														209,242	193,835	181,315
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														$ (209,242)	$ (193,835)	$ (181,315)
[1]	Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[5]	All Revenue from External Customers originated in the United States.

Business Segment Information 73

Business Segment Information (Schedule Of Long-Lived Assets, By Geographical Areas) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-Lived Assets	$ 5,285,040	$ 5,223,356	$ 6,189,138

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, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Operating Revenues	$ 286,937	$ 348,369	$ 522,075	$ 422,500	$ 292,472		$ 335,617		$ 449,132		$ 375,195		$ 1,579,881	$ 1,452,416	$ 1,760,913
Operating Income (Loss)	87,395	123,354	169,957	172,139	81,244		45,162		(237,000)		(305,924)		552,845	(416,518)	(611,053)
Net Income (Loss) Available for Common Stock	$ 45,577	$ 59,714	$ 89,283	$ 88,908	$ 37,553	[1]	$ 8,286	[2]	$ (147,688)	[3]	$ (189,109)	[4]	$ 283,482	$ (290,958)	$ (379,427)
Earnings (Loss) per Common Share, Basic	$ 0.53	$ 0.70	$ 1.05	$ 1.04	$ 0.44		$ 0.10		$ (1.74)		$ (2.23)		$ 3.32	$ (3.43)	$ (4.50)
Earnings (Loss) per Common Share, Diluted	$ 0.53	$ 0.69	$ 1.04	$ 1.04	$ 0.44		$ 0.10		$ (1.74)		$ (2.23)		$ 3.30	$ (3.43)	$ (4.50)
Impairment of Oil and Gas Producing Properties					$ 32,700		$ 82,700		$ 397,400		$ 435,500		$ 0	$ 948,307	$ 1,126,257
Impairment of Oil and Gas Producing Properties After Tax					$ 19,000		$ 47,900		$ 230,500		$ 252,600
[1]	Includes a non-cash $32.7 million impairment charge ($19.0 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[2]	Includes a non-cash $82.7 million impairment charge ($47.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $397.4 million impairment charge ($230.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes a non-cash $435.5 million impairment charge ($252.6 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

Market For Common Stock And R75

Market For Common Stock And Related Shareholder Matters (Price Ranges And Dividends Declared) (Details)	3 Months Ended								12 Months Ended
	Sep. 30, 2017$ / shares	Jun. 30, 2017$ / shares	Mar. 31, 2017$ / shares	Dec. 31, 2016$ / shares	Sep. 30, 2016$ / shares	Jun. 30, 2016$ / shares	Mar. 31, 2016$ / shares	Dec. 31, 2015$ / shares	Sep. 30, 2017entity$ / shares
Class of Stock [Line Items]
Number of Common Stock Shareholders | entity									11,211
Dividends Declared	$ 0.415	$ 0.415	$ 0.405	$ 0.405	$ 0.405	$ 0.405	$ 0.395	$ 0.395
High [Member]
Class of Stock [Line Items]
Price Range	59.92	61.20	61.25	58.78	59.62	57.06	51.53	56.64	$ 59.92
Low [Member]
Class of Stock [Line Items]
Price Range	$ 54.89	$ 53.03	$ 54.67	$ 50.61	$ 53.81	$ 47.49	$ 39.79	$ 37.03	$ 54.89

Supplementary Information For76

Supplementary Information For Oil And Gas Producing Activities (Narrative) (Details) $ in Millions, ft³ in Billions	12 Months Ended
	Sep. 30, 2017USD ($)ft³	Sep. 30, 2016USD ($)ft³	Sep. 30, 2015USD ($)ft³	Sep. 30, 2014	Sep. 30, 2013
Reserve Quantities [Line Items]
Amount spent for developing proved undeveloped reserves | $	$ 101.1	$ 92.8	$ 161.8
Proved Undeveloped Reserve (Volume)	612	543	827
Percentage of PUD reserves to the total proved reserves	28.00%	29.00%	35.00%
New PUD reserve additions	269	102
PUD Sales		166
PUD Downward Revisions		14
PUD Upward Revisions	13
PUD conversions to developed reserves	159	110
Proved Undeveloped Reserves, Removed	54	96
Decrease in Proved undeveloped (PUD) reserves		284
Increase in Proved undeveloped (PUD) reserves	69
Investment made to convert proved undeveloped reserves to developed reserves | $	$ 101	$ 93
Reimbursed Drilling Carry Costs for JDA Partner | $		$ 36
Conversion of undeveloped proved reserves to developed proved reserves	147	92
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year	27.00%	11.00%	33.00%	51.00%	39.00%
Wells Developed	37
Percent Wells Developed	41.00%
Arbitrary discount rate	10.00%
West Coast Region [Member]
Reserve Quantities [Line Items]
New PUD reserve additions	2
PUD conversions to developed reserves	1
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume)	456	542	825
New PUD reserve additions	113	102
PUD conversions to developed reserves	158
Proved Undeveloped Reserves, Removed		74
Wells Developed		31
Percent Wells Developed		28.00%
Utica Shale [Member]
Reserve Quantities [Line Items]
New PUD reserve additions	154
Geneseo Shale [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Removed		23
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 | $	$ 186
Conversion Of Undeveloped Proved Reserves To Developed Proved Reserves Before Revisions [Member]
Reserve Quantities [Line Items]
Conversion of undeveloped proved reserves to developed proved reserves	159	110
Impact of JDA Sales [Member]
Reserve Quantities [Line Items]
Conversion of undeveloped proved reserves to developed proved reserves		207
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year		25.00%
Anticipated JDA Sales [Member]
Reserve Quantities [Line Items]
PUD Sales	60

Supplementary Information For77

Supplementary Information For Oil And Gas Producing Activities (Capitalized Costs Relating To Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands		Sep. 30, 2017	Sep. 30, 2016
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved Properties	[1]	$ 4,832,301	$ 4,554,929
Unproved Properties		80,932	135,285
Capitalized Costs, Oil and Gas Producing Activities, Gross, Total		4,913,233	4,690,214
Less - Accumulated Depreciation, Depletion and Amortization		3,765,710	3,657,239
Capitalized Costs Oil And Gas Producing Activities Net		1,147,523	1,032,975
Asset retirement costs		$ 54,400	$ 63,600
[1]	Includes asset retirement costs of $54.4 million and $63.6 million at September 30, 2017 and 2016, respectively.

Supplementary Information For78

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, 2017	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	$ 0	$ 0	$ 0
Development Costs	4,388	6,707	416
Exploration Costs	2,376	7,593	3,419
Capitalized Interest	235	149	88
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	6,999	$ 14,449	$ 3,923
Capitalized Costs Of Unproved Properties Cumulative Balance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	55,193
Development Costs	11,879
Exploration Costs	13,388
Capitalized Interest	472
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	$ 80,932
Costs Incurred Prior To Fiscal 2015 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs				$ 55,193
Development Costs				368
Exploration Costs				0
Capitalized Interest				0
Capitalized Costs of Unproved Properties Excluded from Amortization, Total				$ 55,561

Supplementary Information For79

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, 2017	Sep. 30, 2016	Sep. 30, 2015
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved		$ 8,908	$ 1,342	$ 1,767
Unproved		262	2,165	19,998
Exploration Costs	[1]	40,975	27,561	53,222
Development Costs	[2]	200,639	219,386	454,605
Asset Retirement Costs		(9,175)	(49,653)	37,595
Total Property Acquisition Costs		241,609	200,801	567,187
Capitalized interest included in exploration costs		300	300	400
Capitalized interest included in development costs		$ 200	$ 200	$ 500
[1]	Amounts for 2017, 2016 and 2015 include capitalized interest of $0.3 million, $0.3 million and $0.4 million, respectively.
[2]	Amounts for 2017, 2016 and 2015 include capitalized interest of $0.2 million, $0.2 million and $0.5 million, respectively.

Supplementary Information For80

Supplementary Information For Oil And Gas Producing Activities (Results Of Operations For Producing Activities) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Reserve Quantities [Line Items]
Revenues from sales to affiliates		$ 0	$ 0	$ 0
Operating Revenues	[1]	526,492,000	386,152,000	506,721,000
Production/Lifting Costs		165,991,000	153,914,000	167,800,000
Franchise/Ad Valorem Taxes		15,372,000	13,794,000	20,167,000
Purchased Emission Allowance Expense		1,391,000	700,000	3,089,000
Accretion Expense		4,896,000	6,663,000	6,186,000
Depreciation, Depletion and Amortization ($0.63, $0.85 and $1.49 per Mcfe of production)		108,471,000	136,579,000	234,480,000
Impairment of Oil and Gas Producing Properties		0	948,307,000	1,126,257,000
Income Tax Expense (Benefit)		86,657,000	(368,940,000)	(444,393,000)
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)		143,714,000	(504,865,000)	(606,865,000)
Depreciation, Depletion and Amortization, per Mcfe of Production		0.63	0.85	1.49
Transfers to Entity's Other Operations		2,357,000	1,765,000	1,946,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Natural Gas (includes transfers to operations of $2,357, $1,765 and $1,946, respectively)	[2]	399,975,000	282,619,000	350,673,000
Oil, Condensate And Other Liquids [Member]
Reserve Quantities [Line Items]
Operating Revenues		$ 126,517,000	$ 103,533,000	$ 156,048,000
[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 For81

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, 2017MMcfMBblsft³	Sep. 30, 2016MMcfMBblsft³	Sep. 30, 2015MMcfMBblsft³	Sep. 30, 2014MMcfMBbls
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		612	543	827
Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		1,674,575	2,142,128	1,682,884
Extensions and Discoveries		386,657	185,347	633,360
Revisions of Previous Estimates		90,849	(248,161)	(34,441)
Production Volume		(157,088)	(143,547)	(139,563)
Sales of Minerals in Place		(21,873)	(261,192)	(112)
Proved Developed and Undeveloped Reserves		1,973,120	1,674,575	2,142,128
Proved Developed Reserves (Volume)		1,363,102	1,132,616	1,316,844	1,177,808
Proved Undeveloped Reserve (Volume)		610,018	541,959	825,284	505,076
Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		29,009	33,722	38,477
Extensions and Discoveries | MBbls		674	530	533
Revisions of Previous Estimates | MBbls		3,293	(2,247)	(2,254)
Production Volume | MBbls		(2,740)	(2,923)	(3,034)
Sales of Minerals in Place | MBbls		(29)	73
Proved Developed and Undeveloped Reserves | MBbls		30,207	29,009	33,722
Proved Developed Reserves (Volume) | MBbls		29,799	28,771	33,370	37,255
Proved Undeveloped Reserve (Volume) | MBbls		408	238	352	1,222
West Coast Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		43,124	49,346	58,822
Extensions and Discoveries		8	0	0
Revisions of Previous Estimates		6,369	(3,132)	(6,317)
Production Volume		(2,995)	(3,090)	(3,159)
Sales of Minerals in Place		0	0	0
Proved Developed and Undeveloped Reserves		46,506	43,124	49,346
Proved Developed Reserves (Volume)		46,506	43,124	49,346	57,907
Proved Undeveloped Reserve (Volume)		0	0	0	915
West Coast Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		28,936	33,502	38,224
Extensions and Discoveries | MBbls		674	530	533
Revisions of Previous Estimates | MBbls		3,305	(2,201)	(2,251)
Production Volume | MBbls		(2,736)	(2,895)	(3,004)
Sales of Minerals in Place | MBbls		0	0
Proved Developed and Undeveloped Reserves | MBbls		30,179	28,936	33,502
Proved Developed Reserves (Volume) | MBbls		29,771	28,698	33,150	37,002
Proved Undeveloped Reserve (Volume) | MBbls		408	238	352	1,222
Appalachian Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		1,631,451	2,092,782	1,624,062
Extensions and Discoveries	[1]	386,649	185,347	633,360
Revisions of Previous Estimates		84,480	(245,029)	(28,124)
Production Volume	[2]	(154,093)	(140,457)	(136,404)
Sales of Minerals in Place		(21,873)	(261,192)	(112)
Proved Developed and Undeveloped Reserves		1,926,614	1,631,451	2,092,782
Proved Developed Reserves (Volume)		1,316,596	1,089,492	1,267,498	1,119,901
Proved Undeveloped Reserve (Volume)		610,018	541,959	825,284	504,161
Appalachian Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		73	220	253
Extensions and Discoveries | MBbls		0	0	0
Revisions of Previous Estimates | MBbls		(12)	(46)	(3)
Production Volume | MBbls		(4)	(28)	(30)
Sales of Minerals in Place | MBbls		(29)	73
Proved Developed and Undeveloped Reserves | MBbls		28	73	220
Proved Developed Reserves (Volume) | MBbls		28	73	220	253
Proved Undeveloped Reserve (Volume) | MBbls		0	0	0	0
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		456	542	825
Marcellus Shale Fields [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		181,000	179,000	598,000
Production Volume		(145,452)	(135,598)	(130,291)
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15.00%
[1]	Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region.
[2]	Extensions and discoveries include 598 Bcf (during 2015), 179 Bcf (during 2016) and 181 Bcf (during 2017), of Marcellus Shale gas in the Appalachian region.(

Supplementary Information For82

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, 2017	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Future Cash Inflows	$ 6,144,317	$ 3,768,463	$ 6,916,775
Future Production Costs	2,378,262	1,994,916	2,854,142
Future Development Costs	411,578	375,152	761,922
Future Income Tax Expense at Applicable Statutory Rate	1,160,469	303,397	1,117,433
Future Net Cash Flows	2,194,008	1,094,998	2,183,278
10% Annual Discount for Estimated Timing of Cash Flows	1,080,962	452,470	860,244
Standardized Measure of Discounted Future Net Cash Flows	$ 1,113,046	$ 642,528	$ 1,323,034	$ 2,066,878

Supplementary Information For83

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, 2017	Sep. 30, 2016	Sep. 30, 2015
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$ 642,528	$ 1,323,034	$ 2,066,878
Sales, Net of Production Costs	(345,075)	(218,444)	(318,753)
Net Changes in Prices, Net of Production Costs	828,187	(1,066,593)	(1,752,843)
Extensions and Discoveries	170,500	47,742	266,159
Changes in Estimated Future Development Costs	8,816	143,752	164,510
Sales of Minerals in Place	(9,849)	(95,849)	(1)
Previously Estimated Development Costs Incurred	101,134	92,840	161,833
Net Change in Income Taxes at Applicable Statutory Rate	(393,353)	387,739	545,442
Revisions of Previous Quantity Estimates	39,078	6,202	(16,573)
Accretion of Discount and Other	71,080	22,105	206,382
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$ 1,113,046	$ 642,528	$ 1,323,034

Valuation And Qualifying Acco84

Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2015
Valuation and Qualifying Accounts [Abstract]
Balance at Beginning of Period		$ 21,109	$ 29,029	$ 31,811
Additions Charged to Costs and Expenses		6,301	6,819	9,316
Additions Charged to Other Accounts	[1]	1,774	1,521	2,585
Deductions	[2]	6,658	16,260	14,683
Balance at End of Period		$ 22,526	$ 21,109	$ 29,029
[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.