National Fuel Gas (NFG) 10-K 20 Nov 15 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2015	Oct. 31, 2015	Mar. 31, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
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		84,633,992
Entity Public Float			$ 4,935,145,000
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, 2015	Sep. 30, 2014	Sep. 30, 2013
INCOME
Operating Revenues	$ 1,760,913	$ 2,113,081	$ 1,829,551
Operating Expenses
Purchased Gas	349,984	605,838	460,432
Operation and Maintenance	470,003	463,078	442,090
Property, Franchise and Other Taxes	89,564	90,711	82,431
Depreciation, Depletion and Amortization	336,158	383,781	326,760
Impairment of Oil and Gas Producing Properties	1,126,257	0	0
Total Operating Expenses	2,371,966	1,543,408	1,311,713
Operating Income (Loss)	(611,053)	569,673	517,838
Other Income (Expense):
Other Income	8,039	9,461	4,697
Interest Income	3,922	4,170	4,335
Interest Expense on Long-Term Debt	(95,916)	(90,194)	(90,273)
Other Interest Expense	(3,555)	(4,083)	(3,838)
Income (Loss) Before Income Taxes	(698,563)	489,027	432,759
Income Tax Expense (Benefit)	(319,136)	189,614	172,758
Net Income (Loss) Available for Common Stock	(379,427)	299,413	260,001
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	1,614,361	1,442,617	1,306,284
Beginning Retained Earnings Unappropriated And Current Period Net Income Loss	1,234,934	1,742,030	1,566,285
Dividends on Common Stock	(131,734)	(127,669)	(123,668)
Balance at End of Year	$ 1,103,200	$ 1,614,361	$ 1,442,617
Earnings Per Common Share, Basic:
Net Income (Loss) Available for Common Stock (in usd per share)	$ (4.50)	$ 3.57	$ 3.11
Earnings Per Common Share, Diluted:
Net Income (Loss) Available for Common Stock (in usd per share)	$ (4.50)	$ 3.52	$ 3.08
Weighted Average Number of Shares Outstanding:
Used in Basic Calculation	84,387,755	83,929,989	83,518,857
Used in Diluted Calculation	84,387,755	84,952,347	84,341,220

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
Net Income (Loss) Available for Common Stock	$ (379,427)	$ 299,413	$ 260,001
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(31,538)	(8,280)	55,940
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	9,217	9,203	15,282
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(3,234)	3,863	5,041
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	381,018	5,334	91,790
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	(591)	(662)	0
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(184,953)	17,647	(36,029)
Other Comprehensive Income (Loss), Before Tax	169,919	27,105	132,024
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(11,922)	(2,720)	21,304
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	3,375	3,370	5,650
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(1,195)	1,398	1,847
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	160,872	529	38,236
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	(217)	(242)	0
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) on Derivative Financial Instruments in Net Income	(78,345)	9,515	(14,799)
Income Taxes - Net	72,568	11,850	52,238
Other Comprehensive Income	97,351	15,255	79,786
Comprehensive Income (Loss)	$ (282,076)	$ 314,668	$ 339,787

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014
ASSETS
Property, Plant and Equipment		$ 9,261,323	$ 8,245,791
Less - Accumulated Depreciation, Depletion and Amortization		3,929,428	2,502,700
Property, Plant and Equipment, Net, Total		5,331,895	5,743,091
Current Assets
Cash and Temporary Cash Investments		113,596	36,886
Hedging Collateral Deposits	[1]	11,124	2,734
Receivables - Net of Allowance for Uncollectible Accounts of $29,029 and $31,811, Respectively		105,004	149,735
Unbilled Revenue		20,746	25,663
Gas Stored Underground		34,252	39,422
Materials and Supplies - at average cost		30,414	27,817
Other Current Assets		60,665	54,752
Deferred Income Taxes		137,200	40,323
Total Current Assets		513,001	377,332
Other Assets
Recoverable Future Taxes		168,214	163,485
Unamortized Debt Expense		2,218	2,747
Other Regulatory Assets		278,227	224,436
Deferred Charges		15,129	14,212
Other Investments		92,990	86,788
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		24,459	36,512
Fair Value of Derivative Financial Instruments		270,363	72,606
Other		167	1,355
Total Other Assets		857,243	607,617
Total Assets		6,702,139	6,728,040
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 84,594,383 Shares and 84,157,220 Shares, Respectively		84,594	84,157
Paid In Capital		744,274	716,144
Earnings Reinvested in the Business		1,103,200	1,614,361
Accumulated Other Comprehensive Income (Loss)		93,372	(3,979)
Total Comprehensive Shareholders' Equity		2,025,440	2,410,683
Long-term Debt, Net of Unamortized Discount and Debt Issuance Costs		2,084,009	1,637,443
Total Capitalization		4,109,449	4,048,126
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		0	85,600
Current Portion of Long-Term Debt	[2]	0	0
Accounts Payable		180,388	136,674
Amounts Payable to Customers		56,778	33,745
Dividends Payable		33,415	32,400
Interest Payable on Long-Term Debt		36,200	29,960
Customer Advances		16,236	19,005
Customer Security Deposits		16,490	15,761
Other Accruals and Current Liabilities		96,557	136,672
Fair Value of Derivative Financial Instruments		10,076	759
Total Current and Accrued Liabilities		446,140	490,576
Deferred Credits
Deferred Income Taxes		1,275,162	1,456,283
Taxes Refundable to Customers		89,448	91,736
Unamortized Investment Tax Credit		731	1,145
Cost of Removal Regulatory Liability		184,907	173,199
Other Regulatory Liabilities		108,617	81,152
Pension and Other Post-Retirement Liabilities		202,807	134,202
Asset Retirement Obligations		156,805	117,713
Other Deferred Credits		128,073	133,908
Total Deferred Credits		2,146,550	2,189,338
Commitments and Contingencies		0	0
Total Capitalization and Liabilities		$ 6,702,139	$ 6,728,040
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.
[2]	None of the Company’s long-term debt at September 30, 2015 and 2014 will mature within the following twelve-month period.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 29,029	$ 31,811
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	84,594,383	84,157,220
Common Stock, Shares Outstanding	84,594,383	84,157,220

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Operating Activities
Net Income (Loss) Available for Common Stock	$ (379,427)	$ 299,413	$ 260,001
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	1,126,257	0	0
Depreciation, Depletion and Amortization	336,158	383,781	326,760
Deferred Income Taxes	(357,587)	142,415	167,887
Excess Tax Benefits Associated with Stock-Based Compensation Awards	(9,064)	(4,641)	(675)
Stock-Based Compensation	3,208	11,763	12,446
Other	9,823	14,063	14,965
Change in:
Hedging Collateral Deposits	(8,390)	(1,640)	(730)
Receivables and Unbilled Revenue	51,638	(22,781)	(17,135)
Gas Stored Underground and Materials and Supplies	3,438	13,285	(3,016)
Unrecovered Purchased Gas Costs	0	12,408	(12,408)
Other Current Assets	3,150	(3,630)	(109)
Accounts Payable	34,687	15,149	8,303
Amounts Payable to Customers	23,033	20,917	(7,136)
Customer Advances	(2,769)	(2,954)	(2,096)
Customer Security Deposits	729	(422)	(1,759)
Other Accruals and Current Liabilities	(7,173)	6,872	666
Other Assets	2,696	18,513	(5,757)
Other Liabilities	23,173	6,879	(1,635)
Net Cash Provided by Operating Activities	853,580	909,390	738,572
Investing Activities
Capital Expenditures	(1,018,179)	(914,417)	(703,461)
Other	(6,611)	5,982	(2,522)
Net Cash Used in Investing Activities	(1,024,790)	(908,435)	(705,983)
Financing Activities
Change in Notes Payable to Banks and Commercial Paper	(85,600)	85,600	(171,000)
Excess Tax Benefits Associated with Stock-Based Compensation Awards	9,064	4,641	675
Net Proceeds from Issuance of Long-Term Debt	444,635	0	495,415
Reduction of Long-Term Debt	0	0	(250,000)
Dividends Paid on Common Stock	(130,719)	(126,642)	(122,710)
Net Proceeds from Issuance of Common Stock	10,540	7,474	5,395
Net Cash Provided By (Used in) Financing Activities	247,920	(28,927)	(42,225)
Net Increase (Decrease) in Cash and Temporary Cash Investments	76,710	(27,972)	(9,636)
Cash and Temporary Cash Investments At Beginning of Year	36,886	64,858	74,494
Cash and Temporary Cash Investments At End of Year	113,596	36,886	64,858
Supplemental Disclosure of Cash Flow Information
Cash Paid for Interest	90,747	91,927	91,215
Cash Paid for Income Taxes	18,657	40,944	13,187
Non-cash Capital Expenditures	$ 118,959	$ 136,628	$ 81,138

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2015
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 Due to the adoption of the authoritative guidance regarding the presentation of debt issuance costs, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified debt issuance costs related to long-term debt previously shown as Unamortized Debt Expense as a direct deduction from the carrying value of Long-Term Debt on the Consolidated Balance Sheet. 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. The book value of the oil and gas properties exceeded the ceiling at September 30, 2015 as well as at June 30, 2015 and March 31, 2015. As such, the Company recognized pre-tax impairment charges of $1.1 billion for the year ended September 30, 2015. Deferred income tax benefits of $476.1 million related to the impairment charges were also recognized for the year ended September 30, 2015. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2015 , 2014 , and 2013 , estimated future net cash flows were increased by $194.5 million , decreased by $33.6 million and increased by $71.6 million , respectively. 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 2015 2014 (Thousands) Exploration and Production $ 4,556,096 $ 3,995,200 Pipeline and Storage 1,710,947 1,609,593 Gathering 307,274 239,507 Utility 1,888,489 1,833,104 Energy Marketing 3,494 3,366 All Other and Corporate 109,193 108,986 $ 8,575,493 $ 7,789,756 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2015 2014 2013 Exploration and Production, per Mcfe(1) $ 1.52 $ 1.85 $ 2.02 Pipeline and Storage 2.4 % 2.4 % 2.5 % Gathering 4.0 % 3.3 % 3.7 % Utility 2.6 % 2.6 % 2.6 % Energy Marketing 6.1 % 5.8 % 3.9 % All Other and Corporate 1.4 % 0.9 % 1.3 % (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 $1.49 , $1.82 and $1.98 per Mcfe of production in 2015 , 2014 and 2013 , respectively. Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2015 and 2014 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, 2015 , 2014 and 2013 , 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 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, 2015, 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, 2015 Balance at October 1, 2014 $ 43,659 $ 8,382 $ (56,020 ) $ (3,979 ) Other Comprehensive Gains and Losses Before Reclassifications 220,146 (2,039 ) (19,616 ) 198,491 Amounts Reclassified From Other Comprehensive Income (106,608 ) (374 ) 5,842 (101,140 ) Balance at September 30, 2015 $ 157,197 $ 5,969 $ (69,794 ) $ 93,372 Year Ended September 30, 2014 Balance at October 1, 2013 $ 30,722 $ 6,337 $ (56,293 ) $ (19,234 ) Other Comprehensive Gains and Losses Before Reclassifications 4,805 2,465 (5,560 ) 1,710 Amounts Reclassified From Other Comprehensive Loss 8,132 (420 ) 5,833 13,545 Balance at September 30, 2014 $ 43,659 $ 8,382 $ (56,020 ) $ (3,979 ) 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) credit was ( $1.5 million ) and $0.2 million at September 30, 2015 and 2014, respectively. The total amount for accumulated losses was $68.3 million and $56.2 million at September 30, 2015 and 2014, respectively. Reclassifications Out of Accumulated Other Comprehensive Income (Loss) The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the year ended September 30, 2015 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 2015 2014 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $180,069 ($14,880 ) Operating Revenues Commodity Contracts 4,884 (2,767 ) Purchased Gas Gains (Losses) on Securities Available for Sale 591 662 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit 109 131 (1) Net Actuarial Loss (9,326 ) (9,334 ) (1) 176,327 (26,188 ) Total Before Income Tax (75,187 ) 12,643 Income Tax Expense $101,140 ($13,545 ) 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 — Current In the Utility segment, gas stored underground — current in the amount of $26.8 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2015, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $13.8 million at September 30, 2015. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or market 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, 2015, the remaining weighted average amortization period for such costs was approximately 4 years . Income Taxes The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. 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 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 2015 2014 (Thousands) Prepayments $ 10,743 $ 10,079 Prepaid Property and Other Taxes 13,709 13,743 Federal Income Taxes Receivable — 8,211 Fair Values of Firm Commitments 15,775 — Regulatory Assets 20,438 22,719 $ 60,665 $ 54,752 Other Accruals and Current Liabilities The components of the Company’s Other Accruals and Current Liabilities are as follows: Year Ended September 30 2015 2014 (Thousands) Accrued Capital Expenditures $ 53,652 $ 80,348 Regulatory Liabilities 5,346 18,072 Federal Income Taxes Payable 5,686 — State Income Taxes Payable 1,170 5,798 Other 30,703 32,454 $ 96,557 $ 136,672 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, 2015 and 2014, customers in the balanced billing programs had advanced excess funds of $16.2 million and $19.0 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, 2015 and 2014, the Company had received customer security deposits amounting to $16.5 million and $15.8 million , respectively. Earnings Per Common Share Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares. As the Company recognized a net loss in 2015, the aforementioned securities, amounting to 709,063 securities, were not recognized in the diluted earnings per share calculation for 2015. For 2014 and 2013, 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. For 2014 and 2013, 1,007 securities and 181,418 securities were excluded as being antidilutive, respectively. 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. 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. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures. In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements. In April 2015, the FASB issued authoritative guidance regarding the presentation of debt issuance costs. The authoritative guidance requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The Company early adopted this guidance at September 30, 2015 on a retrospective basis. In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Sep. 30, 2015
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, with the transmission mains and other components in the pipeline system in the Pipeline and Storage segment and with gathering lines and other components in the Gathering segment. These 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. A reconciliation of the Company’s asset retirement obligations are shown below: Year Ended September 30 2015 2014 2013 (Thousands) Balance at Beginning of Year $ 117,713 $ 119,511 $ 119,246 Liabilities Incurred and Revisions of Estimates 38,150 (2,496 ) (4,796 ) Liabilities Settled (6,825 ) (6,955 ) (1,744 ) Accretion Expense 7,767 7,653 6,805 Balance at End of Year $ 156,805 $ 117,713 $ 119,511

Regulatory Matters

Regulatory Matters	12 Months Ended
	Sep. 30, 2015
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 2015 2014 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note H) $ 202,781 $ 164,804 Post-Retirement Benefit Costs(2) (Note H) 34,217 17,128 Recoverable Future Taxes (Note D) 168,214 163,485 Environmental Site Remediation Costs(2) (Note I) 24,606 25,645 NYPSC Assessment(3) 13,916 12,730 Asset Retirement Obligations(2) (Note B) 12,250 12,006 Unamortized Debt Expense (Note A) 2,218 2,747 Other(4) 10,895 14,842 Total Regulatory Assets 469,097 413,387 Less: Amounts Included in Other Current Assets (20,438 ) (22,719 ) Total Long-Term Regulatory Assets $ 448,659 $ 390,668 At September 30 2015 2014 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 184,907 $ 173,199 Taxes Refundable to Customers (Note D) 89,448 91,736 Post-Retirement Benefit Costs (Note H) 60,013 53,650 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 56,778 33,745 Off-System Sales and Capacity Release Credits(5) 21,027 12,805 Other(6) 32,923 32,769 Total Regulatory Liabilities 445,096 397,904 Less: Amounts included in Current and Accrued Liabilities (62,124 ) (51,817 ) Total Long-Term Regulatory Liabilities $ 382,972 $ 346,087 (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) Amounts are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and September 30, 2014 since such amounts are expected to be recovered from ratepayers in the next 12 months. (4) $6,522 and $9,989 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $4,373 and $4,853 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively. (5) The September 30, 2015 amount is included in Other Regulatory Liabilities on the Consolidated Balance Sheet at September 30, 2015. The September 30, 2014 amount is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2014 since such amount is expected to be passed back to ratepayers in the next 12 months. (6) $5,346 and $5,267 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $27,577 and $27,502 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, 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 Assessment On April 7, 2009, the Governor of the State of New York signed into law an amendment to the Public Service Law increasing the allowed utility assessment from the then current rate of one-third of one percent to one percent of a utility’s in-state gross operating revenue, together with a temporary surcharge (expiring March 31, 2014) equal, as applied, to an additional one percent of the utility’s in-state gross operating revenue. Pursuant to a New York State budget agreement in 2014, the temporary increase in the assessment will be phased out over a three year period ending July 1, 2017. The NYPSC, in a generic proceeding initiated for the purpose of implementing the amended law, has authorized the recovery, through rates, of the full cost of the increased assessment. The assessment is currently being applied to customer bills in the Utility segment’s New York jurisdiction. NYPSC Rate Proceeding Following negotiations and other proceedings, on December 6, 2013, Distribution Corporation filed an agreement, also executed by the Department of Public Service and intervenors, extending existing rates through, at a minimum, September 30, 2015. Although customer rates were not changed, the parties agreed that the allowed rate of return on equity would be set, for ratemaking purposes, at 9.1% . Following conventional practice in New York, the agreement authorizes an “earnings sharing mechanism” (“ESM”). The ESM distributes earnings above the allowed rate of return as follows: from 9.5% to 10.5% , 50% would be allocated to shareholders, and 50% will be deferred for the benefit of customers; above 10.5% , 20% would be allocated to shareholders and 80% will be deferred for the benefit of customers. The agreement further authorizes, and rates reflect, an increase in Distribution Corporation’s pipeline replacement spending by $8.2 million per year of the agreement. The agreement contains other terms and conditions of service that are customary for settlement agreements recently approved by the NYPSC. A $7.5 million refund provision was passed back to ratepayers during 2014 after the NYPSC approved the settlement agreement without modification in an order issued on May 8, 2014. All significant terms of the agreement, including existing rates, continue in effect beyond September 30, 2015 until modified by the NYPSC. The agreement also states that nothing in the agreement precludes the parties from meeting to discuss extending the agreement on mutually acceptable terms, and presenting such extension to the NYPSC for approval. On May 22, 2015, Distribution Corporation filed with the NYPSC a Notice of Impending Settlement Discussions stating that settlement discussions would be scheduled in the near future, and that such discussions might include, among other things, the possible extension of the agreement on mutually acceptable terms. Distribution Corporation is currently involved in such settlement discussions. FERC Rate Proceeding On September 29, 2015, Supply Corporation filed a rate case settlement at the FERC that would, upon approval, extend the Company’s current FERC-approved rate case settlement with a required rate case filing at the latest by December 31, 2019 and prohibit any party from seeking to initiate a rate case proceeding before September 30, 2017. Prior to this settlement, Supply Corporation had been otherwise required by its current rate settlement to make a general rate filing no later than January 1, 2016. The settlement extension provides for, among other things, the following: Supply Corporation will reduce its maximum reservation, capacity, demand and deliverability rates by 2% on November 1, 2015 and by an additional 2% on November 1, 2016. Supply Corporation will also adopt a mechanism that allows it to recover, as a surcharge, certain pipeline safety and greenhouse gas costs it may incur as a result of new rules and regulations. FERC approved the settlement extension on November 13, 2015. Off-System Sales and Capacity Release Credits The Company, in its Utility segment, has entered into off-system sales and capacity release transactions. Most of the margins on such transactions are returned to the customer with only a small percentage being retained by the Company. The amount owed to the customer has been deferred as a regulatory liability.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2015
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 2015 2014 2013 (Thousands) Current Income Taxes — Federal $ 25,064 $ 34,579 $ (632 ) State 13,387 12,620 5,503 Deferred Income Taxes — Federal (244,336 ) 116,143 130,318 State (113,251 ) 26,272 37,569 (319,136 ) 189,614 172,758 Deferred Investment Tax Credit (414 ) (434 ) (426 ) Total Income Taxes $ (319,550 ) $ 189,180 $ 172,332 Presented as Follows: Other Income $ (414 ) $ (434 ) $ (426 ) Income Tax Expense (Benefit) (319,136 ) 189,614 172,758 Total Income Taxes $ (319,550 ) $ 189,180 $ 172,332 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 2015 2014 2013 (Thousands) U.S. Income (Loss) Before Income Taxes $ (698,977 ) $ 488,593 $ 432,333 Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35% $ (244,642 ) $ 171,008 $ 151,317 State Income Taxes (Benefit) (64,912 ) 25,280 27,997 Miscellaneous (9,996 ) (7,108 ) (6,982 ) Total Income Taxes $ (319,550 ) $ 189,180 $ 172,332 Significant components of the Company’s deferred tax liabilities and assets were as follows: At September 30 2015 2014 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 1,291,718 $ 1,614,515 Pension and Other Post-Retirement Benefit Costs 141,032 113,248 Unrealized Hedging Gains 118,522 37,051 Other 51,230 50,884 Total Deferred Tax Liabilities 1,602,502 1,815,698 Deferred Tax Assets: Pension and Other Post-Retirement Benefit Costs (168,451 ) (124,452 ) Tax Loss and Credit Carryforwards (185,681 ) (171,423 ) Other (110,408 ) (103,863 ) Total Deferred Tax Assets (464,540 ) (399,738 ) Total Net Deferred Income Taxes $ 1,137,962 $ 1,415,960 Presented as Follows: Deferred Tax Liability/(Asset) — Current $ (137,200 ) $ (40,323 ) Deferred Tax Liability — Non-Current 1,275,162 1,456,283 Total Net Deferred Income Taxes $ 1,137,962 $ 1,415,960 As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets that arose directly from excess tax deductions related to stock-based compensation. Tax benefits of $9.1 million , $4.6 million and $0.7 million relating to the excess stock-based compensation deductions were recorded in Paid in Capital during the years ended September 30, 2015, September 30, 2014 and September 30, 2013, respectively. Cumulative tax benefits of $32.8 million and $34.2 million remain as of September 30, 2015 and September 30, 2014, respectively, and will be recorded in Paid in Capital in future years when such tax benefits are realized. 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 $89.4 million and $91.7 million at September 30, 2015 and 2014, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $168.2 million and $163.5 million at September 30, 2015 and 2014, 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, 2015 and 2014 and regulatory assets of $88.7 million and $85.3 million as of September 30, 2015 and 2014, respectively. The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2015 2014 2013 (Thousands) Balance at Beginning of Year $ 3,147 $ 2,001 $ 11,170 Additions for Tax Positions Related to Current Year — — 700 Additions for Tax Positions of Prior Years 2,504 2,447 164 Reductions for Tax Positions of Prior Years (566 ) (1,301 ) (10,033 ) Balance at End of Year $ 5,085 $ 3,147 $ 2,001 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, 2015, 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 2015 and fiscal 2014 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 2013, 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, 2015, the Company has a federal net operating loss (NOL) carryover of $343 million , which expires in varying amounts between 2023 and 2033, and a minimum tax credit carryforward of $54 million , that has no expiration date. Approximately $7.3 million of the NOL carryforward is subject to certain annual limitations, and $87 million is attributable to excess tax deductions related to stock-based compensation as discussed above. In addition, the Company has state NOL carryovers in Pennsylvania, California and New York of $333 million , $207 million and $96 million , respectively, which begin to expire in varying amounts between 2025 and 2035. During fiscal 2014, legislation was enacted reducing the corporate tax rate in New York from 7.1% to 6.5% , effective for tax years beginning after January 1, 2016. As a result, a deferred tax benefit of approximately $2.8 million was recorded in the accompanying financial statements.

Capitalization And Short-Term B

Capitalization And Short-Term Borrowings	12 Months Ended
	Sep. 30, 2015
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, 2012 83,330 $ 83,330 $ 669,501 $ 1,306,284 $ (99,020 ) Net Income Available for Common Stock 260,001 Dividends Declared on Common Stock ($1.48 Per Share) (123,668 ) Other Comprehensive Income, Net of Tax 79,786 Share-Based Payment Expense(2) 11,537 Common Stock Issued Under Stock and Benefit Plans(1) 332 332 6,646 Balance at September 30, 2013 83,662 83,662 687,684 1,442,617 (19,234 ) Net Income Available for Common Stock 299,413 Dividends Declared on Common Stock ($1.52 Per Share) (127,669 ) Other Comprehensive Income, Net of Tax 15,255 Share-Based Payment Expense(2) 10,654 Common Stock Issued Under Stock and Benefit Plans(1) 495 495 17,806 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 (3) $ 93,372 (1) Paid in Capital includes tax benefits of $9.1 million , $4.6 million and $0.7 million for September 30, 2015, 2014 and 2013, 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, 2015, $959.0 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 2015, the Company issued 124,214 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 92,887 original issue shares of common stock for the Company's 401(k) plans. During 2015, the Company issued 206,523 original issue shares of common stock as a result of stock option and SARs exercises and 48,490 original issue shares of common stock for restricted stock units 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 2015, 50,467 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 15,516 original issue shares of common stock during 2015. 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, 2015, 2014 and 2013 was approximately $2.1 million , $10.5 million , and $11.5 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, 2015, 2014 and 2013 was approximately $0.9 million , $4.3 million and $4.6 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 less than $0.1 million was capitalized under these rules during the years ended September 30, 2015, 2014 and 2013, respectively. The Company realized excess tax benefits related to stock-based compensation of $7.7 million , $3.1 million , and $3.6 million for the fiscal years ended September 30, 2015, 2014 and 2013, respectively. These amounts are recorded in Paid in Capital when they meet the realization requirements of the authoritative guidance on stock-based compensation. 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, 2014 482,000 $ 36.71 Granted in 2015 — $ — Exercised in 2015 (175,500 ) $ 34.94 Forfeited in 2015 — $ — Outstanding at September 30, 2015 306,500 $ 37.73 0.94 $ 3,754 Option shares exercisable at September 30, 2015 306,500 $ 37.73 0.94 $ 3,754 Option shares available for future grant at September 30, 2015(1) 3,184,675 (1) Includes shares available for SARs, restricted stock and performance share grants. The total intrinsic value of stock options exercised during the years ended September 30, 2015, 2014 and 2013 totaled approximately $5.1 million , $13.7 million , and $11.6 million , respectively. For 2015, 2014 and 2013, the amount of cash received by the Company from the exercise of such stock options was approximately $5.6 million , $7.4 million , and $2.6 million , respectively. The Company last granted stock options in fiscal 2007 and all outstanding 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, 2014 1,793,482 $ 48.11 Granted in 2015 — $ — Exercised in 2015 (60,698 ) $ 31.29 Forfeited in 2015 — $ — Outstanding at September 30, 2015 1,732,784 $ 48.70 4.98 $ 2,224 SARs exercisable at September 30, 2015 1,614,702 $ 48.36 4.82 $ 2,621 The Company did not grant any SARs during the year ended September 30, 2014. The Company granted 412,970 SARs during the year ended September 30, 2013 with a weighted average grant date fair value of $10.66 per share. The SARs granted in 2013 may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. 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 SARs granted during the year ended September 30, 2013 vest and become exercisable annually in one-third increments. The weighted average grant date fair value of the SARs granted during the year ended September 30, 2013 was estimated on the date of grant using the same accounting treatment that is applied for stock options. The total intrinsic value of SARs exercised during the years ended September 30, 2015, 2014 and 2013 totaled approximately $2.0 million , $8.4 million , and $0.8 million , respectively. For the years ended September 30, 2015, 2014 and 2013, 157,386 SARs, 323,188 SARs and 287,168 SARs, respectively, became fully vested. The total fair value of the SARs that became vested during each of the years ended September 30, 2015, 2014 and 2013 was approximately $1.7 million , $3.8 million and $3.6 million , respectively. As of September 30, 2015, unrecognized compensation expense related to SARs totaled approximately $0.1 million , which will be recognized over a weighted average period of 6 months . The fair value of SARs at the date of grant was estimated using the Black-Scholes-Merton closed form model. The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the SARs. The expected life is based on historical experience and the expected volatility is based on historical daily stock price returns. For SARs grants during the year ended September 30, 2013, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following weighted average assumptions were used in estimating the fair value of SARs at the date of grant: Year Ended September 30 2015 2014 2013 Risk-Free Interest Rate N/A N/A 1.55 % Expected Life (Years) N/A N/A 8.25 Expected Volatility N/A N/A 25.61 % Expected Dividend Yield (Quarterly) N/A N/A 0.69 % 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, 2014 89,518 $ 49.05 Granted in 2015 — $ — Vested in 2015 (29,518 ) $ 52.14 Forfeited in 2015 — $ — Outstanding at September 30, 2015 60,000 $ 47.53 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, 2014 and 2013. As of September 30, 2015, unrecognized compensation expense related to restricted share awards totaled approximately $0.9 million , which will be recognized over a weighted average period of 2.4 years . Vesting restrictions for the outstanding shares of non-vested restricted stock at September 30, 2015 will lapse as follows: 2016 — 5,000 shares; 2018 — 35,000 shares; and 2021 — 20,000 shares. 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, 2014 204,519 $ 56.36 Granted in 2015 88,899 $ 64.04 Vested in 2015 (48,490 ) $ 57.17 Forfeited in 2015 (7,980 ) $ 57.38 Outstanding at September 30, 2015 236,948 $ 59.04 The Company also granted 82,151 and 44,200 non-performance based restricted stock units during the years ended September 30, 2014 and 2013, respectively. The weighted average fair value of such non-performance based restricted stock units granted in 2014 and 2013 was $65.24 per share and $51.11 per share, respectively. As of September 30, 2015, unrecognized compensation expense related to non-performance based restricted stock units totaled approximately $5.7 million , which will be recognized over a weighted average period of 1.6 years . Vesting restrictions for the non-performance based restricted stock units outstanding at September 30, 2015 will lapse as follows: 2016 — 77,837 units; 2017 — 76,156 units; 2018 — 50,600 units; 2019 — 21,245 units; and 2020 - 11,110 units. Transactions involving performance based restricted stock units for all plans are summarized as follows: Number of Performance Based Restricted Stock Units Weighted Average Fair Value per Award Outstanding at September 30, 2014 233,876 $ 49.61 Granted in 2015 — $ — Vested in 2015 — $ — Forfeited in 2015 (389 ) $ 48.49 Outstanding at September 30, 2015 233,487 $ 49.61 The Company granted 255,604 performance based restricted stock units during the year ended September 30, 2013 with a weighted average grant date fair value of $49.51 per share. The Company did not grant any performance based restricted stock units during the year ended September 30, 2014. The performance based restricted stock units granted during the year ended September 30, 2013 must meet a performance condition over the performance cycle of October 1, 2012 to September 30, 2015. The performance condition over the performance cycle, generally stated, is the Company’s total return on capital as compared to the same metric for companies in the Natural Gas Distribution and Integrated Natural Gas Companies group as calculated and reported in the Monthly Utility Reports of AUS, Inc., a leading industry consultant. The number of performance based restricted stock units that will vest will depend upon the Company’s performance relative to the report group and not upon the absolute level of return achieved by the Company. Based on the significant loss that the Company experienced during 2015, management believes that the performance conditions associated with the outstanding performance based restricted stock units will not be met. Accordingly, the cumulative stock-based compensation expense of approximately $8.0 million associated with these restricted stock units was reversed during 2015, and there is no unrecognized compensation expense related to such performance based restricted stock units at September 30, 2015. These restricted stock units are not expected to vest in 2016, which is when the vesting restrictions are scheduled to lapse. 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, 2014 98,466 $ 67.16 Granted in 2015 107,044 $ 65.26 Vested in 2015 — $ — Forfeited in 2015 (768 ) $ 67.16 Outstanding at September 30, 2015 204,742 $ 66.17 The Company granted 116,090 performance shares during the year ended September 30, 2014 with a weighted average grant date fair value of $67.16 per share. The Company did not grant any performance shares during the year ended September 30, 2013. As of September 30, 2015, unrecognized compensation expense related to performance shares totaled approximately $7.0 million , which will be recognized over a weighted average period of 1.3 years . Vesting restrictions for the outstanding performance shares at September 30, 2015 will lapse as follows: 2017 - 97,698 shares; and 2018 - 107,044 shares. 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. In addition, half of the performance shares granted during the year ended September 30, 2014 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2013 to September 30, 2016. The performance goals over their respective performance cycles for these performance shares granted during 2015 and 2014 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, 2015 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2014 to September 30, 2017. In addition, the other half of the performance shares granted during the year ended September 30, 2014 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2013 to September 30, 2016. The performance goals over their respective performance cycles for these total shareholder return performance shares ("TSR performance shares") granted during 2015 and 2014 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 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 2015 2014 2013 Risk-Free Interest Rate 1.01 % 0.62 % N/A Remaining Term at Date of Grant (Years) 2.78 2.78 N/A Expected Volatility 20.1 % 28.3 % N/A Expected Dividend Yield (Quarterly) N/A N/A N/A Redeemable Preferred Stock As of September 30, 2015, 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 2015 2014 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(3): 3.75% to 8.75% due April 2018 to July 2025 2,000,000 1,550,000 Total Long-Term Debt 2,099,000 1,649,000 Less Unamortized Discount and Debt Issuance Costs 14,991 11,557 Less Current Portion(2) — — $ 2,084,009 $ 1,637,443 (1) The Medium-Term Notes and Notes are unsecured. (2) None of the Company’s long-term debt at September 30, 2015 and 2014 will mature within the following twelve-month period. (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. On June 25, 2015, the Company issued $450.0 million of 5.20% notes due July 15, 2025. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $444.6 million . The proceeds of this debt issuance were used for general corporate purposes, including the reduction of short-term debt. As of September 30, 2015, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2016 and 2017, $300.0 million in 2018, $250.0 million in 2019, zero in 2020 and $1,549.0 million thereafter. Short-Term Borrowings The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On December 5, 2014, the Company entered into an Amended and Restated Credit Agreement with a syndicate of 14 banks. The agreement replaced the Company's previous $750.0 million syndicated committed credit facility with a substantially similar facility totaling $750.0 million . On September 30, 2015, the Company entered into a Second Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of the same 14 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through December 5, 2019, plus a $500.0 million 364-day unsecured committed revolving credit facility through September 29, 2016. 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, 2015, the commercial paper program was backed by the Credit Agreement. The Company did not have any outstanding commercial paper at September 30, 2015. At September 30, 2014, the Company had outstanding commercial paper of $85.6 million with a weighted average interest rate on the commercial paper of 0.31% . The Company did not have any short-term notes payable to banks at September 30, 2015 and 2014. Debt Restrictions The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter through December 5, 2019 . At September 30, 2015, the Company’s debt to capitalization ratio (as calculated under the facility) was .51 . The constraints specified in the Credit Agreement would have permitted an additional $1.67 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65 . If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible. 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, 2015, the Company had no debt outstanding under the Credit Agreement. Under the Company’s existing indenture covenants, at September 30, 2015, the Company is precluded from issuing additional long-term unsecured indebtedness during fiscal 2016 as a result of impairments of its oil and gas properties recognized during the year ended September 30, 2015. The 1974 indenture would not preclude the Company from issuing new indebtedness to replace maturing debt. If the Company experiences additional significant impairments of its oil and gas properties in the first or subsequent quarters of fiscal 2016, the Company, under its 1974 indenture, expects to continue to be precluded from issuing incremental long-term debt into the first or subsequent quarters of fiscal 2017. However, the Company expects that it could borrow under its credit facilities. The Company's present liquidity position is believed to be adequate to satisfy known demands. The Company’s 1974 indenture pursuant to which $99.0 million (or 4.7% ) of the Company’s long-term debt (as of September 30, 2015) 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, 2015
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, 2015 and 2014. 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, 2015 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 $ 92,196 $ — $ — $ — $ 92,196 Derivative Financial Instruments: Commodity Futures Contracts — Gas 6,373 — — (6,373 ) — Over the Counter Swaps — Gas and Oil — 272,335 1,791 (808 ) 273,318 Foreign Currency Contracts — — — (2,955 ) (2,955 ) Other Investments: Balanced Equity Mutual Fund 34,884 — — — 34,884 Fixed Income Mutual Funds 8,004 — — — 8,004 Common Stock — Financial Services Industry 4,318 — — — 4,318 Other Common Stock 450 — — — 450 Hedging Collateral Deposits 11,124 — — — 11,124 Total $ 157,349 $ 272,335 $ 1,791 $ (10,136 ) $ 421,339 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 15,276 $ — $ — $ (6,373 ) $ 8,903 Over the Counter Swaps — Gas and Oil — 1,981 — (808 ) 1,173 Foreign Currency Contracts — 2,955 — (2,955 ) — Total $ 15,276 $ 4,936 $ — $ (10,136 ) $ 10,076 Total Net Assets/(Liabilities) $ 142,073 $ 267,399 $ 1,791 $ — $ 411,263 At Fair Value as of September 30, 2014 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 $ 23,794 $ — $ — $ — $ 23,794 Derivative Financial Instruments: Commodity Futures Contracts — Gas 2,725 — — (1,987 ) 738 Over the Counter Swaps — Gas and Oil — 75,951 1,368 (5,451 ) 71,868 Other Investments: Balanced Equity Mutual Fund 35,331 — — — 35,331 Common Stock — Financial Services Industry 6,629 — — — 6,629 Other Common Stock 455 — — — 455 Hedging Collateral Deposits 2,734 — — — 2,734 Total $ 71,668 $ 75,951 $ 1,368 $ (7,438 ) $ 141,549 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 2,674 $ — $ — $ (1,987 ) $ 687 Over the Counter Swaps — Gas and Oil — 5,523 — (5,451 ) 72 Total $ 2,674 $ 5,523 $ — $ (7,438 ) $ 759 Total Net Assets/(Liabilities) $ 68,994 $ 70,428 $ 1,368 $ — $ 140,790 (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, 2015 and 2014, 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 $11.1 million (at September 30, 2015) and $2.7 million (at September 30, 2014), 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, 2015 and 2014 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 derivative financial instruments reported in Level 3 consist of a portion of the crude oil price swap agreements used in the Company’s Exploration and Production segment at September 30, 2015 and 2014. The fair value of the Level 3 crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). The significant unobservable input used in the fair value measurement of a portion of the Company’s over-the-counter crude oil swaps is the basis differential between Midway Sunset oil and NYMEX contracts. Significant changes in the assumed basis differential could result in a significant change in the value of the derivative financial instruments. At September 30, 2015, it was assumed that Midway Sunset oil was 91.8% of NYMEX. This is based on a historical twelve month average of Midway Sunset oil sales verses NYMEX settlements. During this twelve-month period, the price of Midway Sunset oil ranged from 87.8% to 94.6% of NYMEX. If the price of Midway Sunset oil relative to NYMEX used in the fair value measurement calculation had been 10 percentage points higher, the fair value of the Level 3 crude oil price swap agreements asset would have been approximately $0.2 million lower at September 30, 2015. If the price of Midway Sunset oil relative to NYMEX used in the fair value measurement had been 10 percentage points lower, the fair value measurement of the Level 3 crude oil price swap agreements asset would have been approximately $0.2 million higher at September 30, 2015. These calculated amounts are based solely on basis differential changes and do not take into account any other changes to the fair value measurement calculation. 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, 2015, 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. The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the years ended September 30, 2015 and September 30, 2014, respectively. For the years ended September 30, 2015 and September 30, 2014, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts). Fair Value Measurements Using Unobservable Inputs (Level 3) Total Gains/Losses October 1, 2014 (Gains)/Losses Realized and Included in Earnings Gains/(Losses) Unrealized and Included in Other Comprehensive Income (Loss) Transfer In/(Out) of Level 3 September 30, 2015 (Dollars in thousands) Derivative Financial Instruments(2) $ 1,368 $ (12,738 ) (1) $ 13,161 $ — $ 1,791 (1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2015. (2) Derivative Financial Instruments are shown on a net basis. Total Gains/Losses October 1, 2013 (Gains)/Losses Realized and Included in Earnings Gains/(Losses) Transfer In/(Out) of Level 3 September 30, 2014 (Dollars in thousands) Derivative Financial Instruments(2) $ (5,190 ) $ 2,217 (1) $ 4,341 $ — $ 1,368 (1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2014. (2) Derivative Financial Instruments are shown on a net basis.

Financial Instruments

Financial Instruments	12 Months Ended
	Sep. 30, 2015
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 2015 Carrying Amount 2015 Fair Value 2014 Carrying Amount 2014 Fair Value (Thousands) Long-Term Debt $ 2,084,009 $ 2,129,558 $ 1,637,443 $ 1,775,715 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 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 $45.3 million and $44.4 million at September 30, 2015 and 2014, respectively. The fair value of the equity mutual fund was $34.9 million and $35.3 million at September 30, 2015 and 2014, respectively. The gross unrealized gain on this equity mutual fund was $6.5 million at September 30, 2015 and $8.4 million at September 30, 2014. The fair value of the fixed income mutual fund was $8.0 million at September 30, 2015. The fair value of the stock of an insurance company was $4.3 million and $6.6 million at September 30, 2015 and 2014, respectively. The gross unrealized gain on this stock was $2.6 million and $4.5 million at September 30, 2015 and 2014, 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 duration of the Company’s combined cash flow and fair value hedges does not typically exceed 5 years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. The derivative financial instruments held by the Energy Marketing segment are not considered to be material to the Company. 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, 2015 and September 30, 2014 . Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency 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, 2015 , the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding: Commodity Units Natural Gas 180.5 Bcf (short positions) Natural Gas 2.8 Bcf (long positions) Crude Oil 2,196,000 Bbls (short positions) As of September 30, 2015, the Company was hedging a total of $58.0 million of forecasted transportation costs denominated in Canadian dollars with swaps on forward currency rates (long positions). Settlements will begin in fiscal 2016. As of September 30, 2015, the Company had $272.2 million ( $157.2 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $168.1 million ( $97.1 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. Refer to Note A, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2015 and 2014 (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, 2015 2014 2015 2014 2015 2014 Commodity Contracts $ 377,957 $ 9,763 Operating Revenue $ 180,069 $ (14,880 ) Operating Revenue $ 3,563 $ 624 Commodity Contracts $ 6,016 $ (4,429 ) Purchased Gas $ 4,884 $ (2,767 ) Not Applicable $ — $ — Foreign Currency Contracts $ (2,955 ) $ — Not Applicable $ — $ — Not Applicable $ — $ — Total $ 381,018 $ 5,334 $ 184,953 $ (17,647 ) $ 3,563 $ 624 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 market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of September 30, 2015, the Company’s Energy Marketing segment had fair value hedges covering approximately 17.9 Bcf of mostly fixed price sales commitments. 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, 2015 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2015 (In thousands) Commodity Contracts Operating Revenues $ (13,944 ) $ 13,944 Commodity Contracts Purchased Gas (18 ) 18 $ (13,962 ) $ 13,962 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 with sixteen counterparties of which fifteen are in a net gain position. On average, the Company had $18.0 million of credit exposure per counterparty in a gain position at September 30, 2015. The maximum credit exposure per counterparty in a gain position at September 30, 2015 was $50.5 million . The Company’s gain position on such derivative financial instruments for certain counterparties exceeded the established thresholds at which the counterparties would be required to post collateral. At September 30, 2015, collateral deposits of $29.7 million were posted. These collateral deposits are recorded as a component of Accounts Payable on the Consolidated Balance Sheet. As of September 30, 2015, thirteen of the sixteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps) 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, 2015, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $174.6 million according to the Company’s internal model (discussed in Note F — Fair Value Measurements). For its over-the-counter swap agreements, no hedging collateral deposits were required to be posted by the Company at September 30, 2015. For its exchange traded futures contracts, the Company was required to post $11.1 million in hedging collateral deposits as of September 30, 2015. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts 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, 2015
Compensation and Retirement Disclosure [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 $2.3 million , $1.9 million and $1.2 million for the years ended September 30, 2015, 2014 and 2013, 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 $5.8 million , $5.2 million , and $4.4 million for the years ended September 30, 2015, 2014 and 2013, 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 2015, 2014 and 2013. Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2015 2014 2013 2015 2014 2013 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 999,499 $ 946,305 $ 1,070,744 $ 465,583 $ 460,634 $ 561,263 Service Cost 12,047 11,987 15,846 2,693 2,939 4,705 Interest Cost 41,217 43,574 36,498 19,285 21,308 19,212 Plan Participants’ Contributions — — — 2,242 2,265 2,141 Retiree Drug Subsidy Receipts — — — 1,338 1,419 1,526 Amendments(1) 7,752 — — — — — Actuarial (Gain) Loss 23,426 53,887 (121,631 ) (1,575 ) 1,087 (104,455 ) Benefits Paid (57,751 ) (56,254 ) (55,152 ) (24,579 ) (24,069 ) (23,758 ) Benefit Obligation at End of Period $ 1,026,190 $ 999,499 $ 946,305 $ 464,987 $ 465,583 $ 460,634 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 869,791 $ 799,307 $ 701,676 $ 497,601 $ 472,392 $ 414,134 Actual Return on Plan Assets (13,370 ) 93,238 98,783 534 44,898 61,715 Employer Contributions 36,200 33,500 54,000 2,161 2,115 18,160 Plan Participants’ Contributions — — — 2,242 2,265 2,141 Benefits Paid (57,751 ) (56,254 ) (55,152 ) (24,579 ) (24,069 ) (23,758 ) Fair Value of Assets at End of Period $ 834,870 $ 869,791 $ 799,307 $ 477,959 $ 497,601 $ 472,392 Net Amount Recognized at End of Period (Funded Status) $ (191,320 ) $ (129,708 ) $ (146,998 ) $ 12,972 $ 32,018 $ 11,758 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (191,320 ) $ (129,708 ) $ (146,998 ) $ (11,487 ) $ (4,494 ) $ (11,016 ) Non-Current Assets — — — 24,459 36,512 22,774 Net Amount Recognized at End of Period $ (191,320 ) $ (129,708 ) $ (146,998 ) $ 12,972 $ 32,018 $ 11,758 Accumulated Benefit Obligation $ 968,984 $ 940,068 $ 886,942 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 4.25 % 4.25 % 4.75 % 4.50 % 4.25 % 4.75 % Rate of Compensation Increase 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2015 2014 2013 2015 2014 2013 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 12,047 $ 11,987 $ 15,846 $ 2,693 $ 2,939 $ 4,705 Interest Cost 41,217 43,574 36,498 19,285 21,308 19,212 Expected Return on Plan Assets (59,615 ) (59,974 ) (57,346 ) (34,089 ) (37,424 ) (32,872 ) Amortization of Prior Service Cost (Credit) 183 210 238 (1,913 ) (2,138 ) (2,138 ) Amortization of Transition Amount — — — — — 8 Recognition of Actuarial Loss(2) 36,129 36,007 52,776 4,148 2,645 20,892 Net Amortization and Deferral for Regulatory Purposes 7,739 8,151 (10,406 ) 20,322 23,263 11,844 Net Periodic Benefit Cost $ 37,700 $ 39,955 $ 37,606 $ 10,446 $ 10,593 $ 21,651 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Discount Rate 4.25 % 4.75 % 3.50 % 4.25 % 4.75 % 3.50 % Expected Return on Plan Assets 7.50 % 8.00 % 8.00 % 7.00 % 8.00 % 8.00 % 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 cost associated with these plans were $7.0 million , $7.5 million and $9.6 million in 2015, 2014 and 2013, respectively. The accumulated benefit obligations for the plans were $66.0 million , $65.7 million and $57.2 million at September 30, 2015, 2014 and 2013, respectively. The projected benefit obligations for the plans were $85.8 million , $85.5 million and $77.1 million at September 30, 2015, 2014 and 2013, respectively. At September 30, 2015, $4.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $81.3 million is recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2014, $6.6 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $78.9 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, 2013, the projected benefit obligations are recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 3.50% , 3.50% and 3.75% as of September 30, 2015, 2014 and 2013, respectively and the weighted average rate of compensation increase for these plans were 7.75% , 7.50% and 7.75% as of September 30, 2015, 2014 and 2013, respectively. The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2015, the changes in such amounts during 2015, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2016 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 $ (287,180 ) $ (59,914 ) $ (24,929 ) Prior Service (Cost) Credit (8,425 ) 5,027 — Net Amount Recognized $ (295,605 ) $ (54,887 ) $ (24,929 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2015(1) Increase in Actuarial Loss, excluding amortization(2) $ (96,412 ) $ (31,980 ) $ (4,321 ) Change due to Amortization of Actuarial Loss 36,129 4,148 2,925 Prior Service (Cost) Credit (7,569 ) (1,913 ) — Net Change $ (67,852 ) $ (29,745 ) $ (1,396 ) Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (32,248 ) $ (5,530 ) $ (3,295 ) Prior Service (Cost) Credit (1,234 ) 912 — Net Amount Expected to be Recognized $ (33,482 ) $ (4,618 ) $ (3,295 ) (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, 2015, the Company recorded a $76.7 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $22.3 million (pre-tax) decrease to Accumulated Other Comprehensive Income. 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 . In 2015, other actuarial experience decreased the projected benefit obligation for the Retirement Plan by $0.8 million . The effect of the discount rate change for the Retirement Plan in 2014 was to increase the projected benefit obligation of the Retirement Plan by $53.7 million . The effect of the discount rate change for the Retirement Plan in 2013 was to decrease the projected benefit obligation of the Retirement Plan by $147.9 million . The Company made cash contributions totaling $36.2 million to the Retirement Plan during the year ended September 30, 2015. The Company expects that the annual contribution to the Retirement Plan in 2016 will be in the range of $5.0 million to $10.0 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: $61.1 million in 2016; $62.1 million in 2017; $63.0 million in 2018; $63.7 million in 2019; $64.4 million in 2020; and $332.1 million in the five years thereafter. 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 effect of the discount rate change in 2014 was to increase the other post-retirement benefit obligation by $26.4 million . Other actuarial experience decreased the other post-retirement benefit obligation in 2014 by $25.3 million primarily attributable to a revision in assumed per-capita claims cost, premiums and participant contributions based on actual experience. The effect of the discount rate change in 2013 was to decrease the other post-retirement benefit obligation by $75.9 million . Other actuarial experience decreased the other post-retirement benefit obligation in 2013 by $28.6 million as the increase in obligation attributable to the change in mortality assumption was more than offset by the decrease in obligation attributable to a revision in assumed per-capita claims cost, premiums and participant contributions based on actual experience. The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands): Benefit Payments Subsidy Receipts 2016 $ 25,728 $ (1,786 ) 2017 $ 26,942 $ (1,935 ) 2018 $ 28,059 $ (2,094 ) 2019 $ 29,038 $ (2,259 ) 2020 $ 30,079 $ (2,405 ) 2021 through 2025 $ 161,958 $ (14,197 ) Assumed health care cost trend rates as of September 30 were: 2015 2014 2013 Rate of Medical Cost Increase for Pre Age 65 Participants 6.93 % (1) 7.10 % (1) 7.28 % (1) Rate of Medical Cost Increase for Post Age 65 Participants 6.68 % (1) 6.73 % (1) 6.78 % (1) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 7.17 % (1) 7.47 % (1) 7.78 % (1) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 6.68 % (1) 6.73 % (1) 6.78 % (1) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 6.65 % (1) 6.79 % (1) 7.03 % (1) (1) 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, 2015 would increase by $53.9 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 2015 by $2.9 million . If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of October 1, 2015 would decrease by $45.2 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 2015 by $2.4 million . The Company made cash contributions totaling $2.0 million to its VEBA trusts and 401(h) accounts during the year ended September 30, 2015. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2015. The Company expects that the annual contribution to its VEBA trusts and 401(h) accounts in 2016 will be in the range of $2.0 million to $5.0 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, 2015 and 2014, 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, 2015 Level 1 Level 2 Level 3 Retirement Plan Investments Domestic Equities(1) $ 229,811 $ 170,166 $ 59,645 $ — International Equities(2) 96,478 — 96,478 — Global Equities(3) 112,802 — 112,802 — Domestic Fixed Income(4) 303,508 1,539 301,969 — International Fixed Income(5) 883 883 — — Global Fixed Income(6) 86,773 — 86,773 — Hedge Fund Investments 26,490 — — 26,490 Real Estate 4,724 — — 4,724 Cash and Cash Equivalents 27,723 — 27,723 — Total Retirement Plan Investments 889,192 172,588 685,390 31,214 401(h) Investments (53,686 ) (10,420 ) (41,381 ) (1,885 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 835,506 $ 162,168 $ 644,009 $ 29,329 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (636 ) Total Retirement Plan Assets $ 834,870 Total Fair Value Level 1 Level 2 Level 3 Retirement Plan Investments Domestic Equities(1) $ 268,649 $ 171,979 $ 96,670 $ — International Equities(2) 80,957 1,969 78,988 — Global Equities(3) 104,238 — 104,238 — Domestic Fixed Income(4) 299,494 63,187 236,307 — International Fixed Income(5) 1,240 508 732 — Global Fixed Income(6) 93,704 — 93,704 — Hedge Fund Investments 45,213 — — 45,213 Real Estate 3,792 — — 3,792 Cash and Cash Equivalents 33,544 — 33,544 — Total Retirement Plan Investments 930,831 237,643 644,183 49,005 401(h) Investments (54,921 ) (14,105 ) (37,907 ) (2,909 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 875,910 $ 223,538 $ 606,276 $ 46,096 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (6,119 ) Total Retirement Plan Assets $ 869,791 (1) Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. (2) International Equities include mostly collective trust funds and common stock. (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 include mostly collective trust funds and exchange traded funds. (6) Global Fixed Income securities are comprised of a collective trust fund. Total Fair Value Level 1 Level 2 Level 3 Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Domestic Equities $ 128,336 $ — $ 128,336 $ — Collective Trust Funds — International Equities 48,857 — 48,857 — Exchange Traded Funds — Fixed Income 233,471 233,471 — — Cash Held in Collective Trust Funds 13,119 — 13,119 — Total VEBA Trust Investments 423,783 233,471 190,312 — 401(h) Investments 53,686 10,420 41,381 1,885 Total Investments (including 401(h) Investments) $ 477,469 $ 243,891 $ 231,693 $ 1,885 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 490 Total Other Post-Retirement Benefit Assets $ 477,959 Total Fair Value Level 1 Level 2 Level 3 Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Domestic Equities $ 148,219 $ — $ 148,219 $ — Collective Trust Funds — International Equities 54,881 — 54,881 — Exchange Traded Funds — Fixed Income 236,513 236,513 — — Cash Held in Collective Trust Funds 6,412 — 6,412 — Total VEBA Trust Investments 446,025 236,513 209,512 — 401(h) Investments 54,921 14,105 37,907 2,909 Total Investments (including 401(h) Investments) $ 500,946 $ 250,618 $ 247,419 $ 2,909 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (3,345 ) Total Other Post-Retirement Benefit Assets $ 497,601 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). Note: For the years ended September 30, 2015 and September 30, 2014, 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, 2013 $ 42,027 $ 2,723 $ (2,606 ) $ 42,144 Realized Gains/(Losses) — 62 (4 ) 58 Unrealized Gains/(Losses) 3,186 (10 ) (239 ) 2,937 Purchases — 1,111 (65 ) 1,046 Sales — (94 ) 5 (89 ) Balance at September 30, 2014 45,213 3,792 (2,909 ) 46,096 Realized Gains/(Losses) 2,284 — (135 ) 2,149 Unrealized Gains/(Losses) 317 871 (103 ) 1,085 Purchases — 82 (5 ) 77 Sales (21,324 ) (21 ) 1,267 (20,078 ) Balance at September 30, 2015 $ 26,490 $ 4,724 $ (1,885 ) $ 29,329 Other Post-Retirement Benefit Level 3 Assets (Thousands) VEBA Trust Investments Including 401(h) Investments Other Post-Retirement Benefit Investments Real Estate Balance at September 30, 2013 $ 55 $ 2,606 $ 2,661 Realized Gains/(Losses) (40 ) 4 (36 ) Unrealized Gains/(Losses) — 239 239 Purchases — 65 65 Sales (15 ) (5 ) (20 ) Balance at September 30, 2014 — 2,909 2,909 Realized Gains/(Losses) — 135 135 Unrealized Gains/(Losses) — 103 103 Purchases — 5 5 Sales — (1,267 ) (1,267 ) Balance at September 30, 2015 $ — $ 1,885 $ 1,885 The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.25% (Retirement Plan) and 6.75% (other post-retirement benefits), effective for fiscal 2016. 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. The discount rate used to present value the future benefit payment obligations of the Retirement Plan is 4.25% at September 30, 2015. The discount rate used to present value the future benefit payment obligations of the Company’s other post-retirement benefits is 4.50% as of September 30, 2015. The discount rate used to present value the future benefit payment obligations of the Non-Qualified benefit plans is 3.50% as of September 30, 2015. The Company utilizes the Mercer Yield Curve Above Mean Model to determine the discount rate. The yield curve is a spot rate yield curve that provides a zero-coupon interest rate for each year into the future. Each year’s anticipated benefit payments are discounted at the associated spot interest rate back to the measurement date. The discount rate is then determined based on the spot interest rate that results in the same present value when applied to the same anticipated benefit payments. In determining the spot rates, the model will exclude coupon interest rates that are in the lower 50 th percentile based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Sep. 30, 2015
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, 2015, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be approximately $11.2 million . The main component of this liability is discussed below under "Former Manufactured Gas Plant Sites." This estimated liability has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, 2015. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 12 years . Other than as discussed below, 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. Former Manufactured Gas Plant Sites The Company has incurred investigation and/or clean-up costs at several former manufactured gas plant sites in New York and Pennsylvania. The Company continues to be responsible for future ongoing monitoring and long-term maintenance at two sites. The most significant ongoing clean-up matter currently facing the Company is a former manufactured gas plant site located in New York. In February 2009, the Company received approval from the NYDEC of a Remedial Design Work Plan (RDWP) for this site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. As a result of this work, the Company submitted to the NYDEC a proposal to amend the NYDEC’s Record of Decision remedy for the site. In April 2013, the NYDEC approved the Company’s proposed amendment. Final remedial design work for the site has been completed, and remedial work has begun. An estimated minimum liability for remaining remediation of this site of $9.9 million has been recorded. 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 majority of these contracts expire within the next five years. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $185.1 million in 2016, $89.4 million in 2017, $84.9 million in 2018, $92.6 million in 2019, $73.5 million in 2020 and $762.5 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, meters 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: $25.7 million in 2016, $6.0 million in 2017, $4.7 million in 2018, $4.5 million in 2019, $3.3 million in 2020 and $0.6 million thereafter. The Company, in its Pipeline and Storage segment and Gathering segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system expansion projects. As of September 30, 2015, the future contractual commitments related to the expansion projects are $96.6 million in 2016 and $0.2 million in 2017. There are no contractual commitments extending beyond 2017. The Company, in its Exploration and Production segment, has entered into contractual obligations associated with hydraulic fracturing and fuel. The future contractual commitments are $104.7 million in 2016 and $25.0 million in 2017. There are no contractual commitments extending beyond 2017. The Company, in its Utility segment, has entered into contractual obligations associated with the replacement of its legacy mainframe systems and has future contractual commitments of $21.4 million in 2016. There are no contractual commitments extending beyond 2016. 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, 2015
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 and purchase 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 natural gas to major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. 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. Energy Marketing segment revenues and related purchased gas costs for the year ended September 30, 2013 were recorded when billed, resulting in a one month lag. Starting in 2014, the Energy Marketing segment began recording unbilled revenue and related gas costs, recording $8.5 million of unbilled revenue and $0.6 million of related incremental margin (net of tax). The impact of not recording unbilled revenue and related costs was immaterial in all prior periods. Year Ended September 30, 2015 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) $ 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 $ 2,549,374 $ 1,597,173 $ 447,968 $ 1,960,158 $ 88,193 $ 6,642,866 $ 77,350 $ (18,077 ) $ 6,702,139 Year Ended September 30, 2014 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) $ 804,096 $ 200,664 $ 673 $ 831,156 $ 271,993 $ 2,108,582 $ 3,532 $ 967 $ 2,113,081 Intersegment Revenues $ — $ 83,744 $ 69,937 $ 18,462 $ 1,159 $ 173,302 $ — $ (173,302 ) $ — Interest Income $ 1,909 $ 284 $ 120 $ 3,010 $ 173 $ 5,496 $ 106 $ (1,432 ) $ 4,170 Interest Expense $ 42,232 $ 26,428 $ 1,726 $ 27,693 $ 31 $ 98,110 $ 6 $ (3,839 ) $ 94,277 Depreciation, Depletion and Amortization $ 296,210 $ 36,642 $ 6,116 $ 43,594 $ 197 $ 382,759 $ 344 $ 678 $ 383,781 Income Tax Expense (Benefit) $ 81,370 $ 47,100 $ 23,636 $ 33,918 $ 3,761 $ 189,785 $ 822 $ (993 ) $ 189,614 Segment Profit: Net Income (Loss) $ 121,569 $ 77,559 $ 32,709 $ 64,059 $ 6,631 $ 302,527 $ 1,160 $ (4,274 ) $ 299,413 Expenditures for Additions to Long-Lived Assets $ 602,705 $ 139,821 $ 137,799 $ 88,810 $ 264 $ 969,399 $ 274 $ 234 $ 969,907 At September 30, 2014 (Thousands) Segment Assets $ 3,100,514 $ 1,367,181 $ 326,662 $ 1,862,850 $ 76,238 $ 6,733,445 $ 86,460 $ (91,865 ) $ 6,728,040 Year Ended September 30, 2013 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) $ 702,937 $ 178,184 $ 1,324 $ 730,319 $ 211,990 $ 1,824,754 $ 3,910 $ 887 $ 1,829,551 Intersegment Revenues $ — $ 89,424 $ 33,457 $ 16,020 $ 1,384 $ 140,285 $ — $ (140,285 ) $ — Interest Income $ 1,501 $ 193 $ 55 $ 3,417 $ 169 $ 5,335 $ 115 $ (1,115 ) $ 4,335 Interest Expense $ 39,745 $ 26,248 $ 2,283 $ 29,076 $ 36 $ 97,388 $ 2 $ (3,279 ) $ 94,111 Depreciation, Depletion and Amortization $ 243,431 $ 35,156 $ 3,945 $ 42,729 $ 123 $ 325,384 $ 577 $ 799 $ 326,760 Income Tax Expense (Benefit) $ 95,317 $ 38,626 $ 10,287 $ 31,065 $ 2,450 $ 177,745 $ 529 $ (5,516 ) $ 172,758 Segment Profit: Net Income (Loss) $ 115,391 $ 63,245 $ 13,321 $ 65,686 $ 4,589 $ 262,232 $ 894 $ (3,125 ) $ 260,001 Expenditures for Additions to Long-Lived Assets $ 533,129 $ 56,144 $ 54,792 $ 71,970 $ 595 $ 716,630 $ 307 $ 160 $ 717,097 At September 30, 2013 (Thousands) Segment Assets $ 2,746,233 $ 1,246,027 $ 203,323 $ 1,870,587 $ 67,267 $ 6,133,437 $ 95,793 $ (24,253 ) $ 6,204,977 (1) All Revenue from External Customers originated in the United States. Geographic Information At September 30 2015 2014 2013 (Thousands) Long-Lived Assets: United States $ 6,189,138 $ 6,350,708 $ 5,756,300

Quarterly Financial Data

Quarterly Financial Data	12 Months Ended
	Sep. 30, 2015
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) 2015 9/30/2015 $ 301,062 $ (326,731 ) $ (187,703 ) (1) $ (2.22 ) $ (2.22 ) 6/30/2015 $ 339,815 $ (489,214 ) $ (293,134 ) (2) $ (3.47 ) $ (3.44 ) 3/31/2015 $ 596,127 $ 44,331 $ 16,669 (3) $ 0.20 $ 0.20 12/31/2014 $ 523,909 $ 160,561 $ 84,741 $ 1.01 $ 1.00 2014 9/30/2014 $ 366,623 $ 102,004 $ 57,431 $ 0.68 $ 0.68 6/30/2014 $ 440,144 $ 127,013 $ 64,520 $ 0.77 $ 0.76 3/31/2014 $ 756,242 $ 180,075 $ 95,210 (4) $ 1.14 $ 1.12 12/31/2013 $ 550,072 $ 160,581 $ 82,252 $ 0.98 $ 0.97 (1) Includes a non-cash $417.2 million impairment charge ( $240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ( $5.2 million after tax) related to performance based restricted stock units. (2) Includes a non-cash $588.7 million impairment charge ( $339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (3) Includes a non-cash $120.3 million impairment charge ( $69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (4) Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.

Market For Common Stock And Rel

Market For Common Stock And Related Shareholder Matters	12 Months Ended
	Sep. 30, 2015
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, 2015, there were 12,147 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, 2015 and 2014, are shown below: Price Range Dividends Declared Quarter Ended High Low 2015 9/30/2015 $ 59.39 $ 48.61 $ 0.395 6/30/2015 $ 66.07 $ 58.83 $ 0.395 3/31/2015 $ 70.19 $ 57.73 $ 0.385 12/31/2014 $ 72.21 $ 64.31 $ 0.385 2014 9/30/2014 $ 78.79 $ 65.29 $ 0.385 6/30/2014 $ 78.46 $ 68.50 $ 0.385 3/31/2014 $ 77.05 $ 68.12 $ 0.375 12/31/2013 $ 72.53 $ 65.23 $ 0.375

Supplementary Information For O

Supplementary Information For Oil And Gas Producing Activities	12 Months Ended
	Sep. 30, 2015
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 2015 2014 (Thousands) Proved Properties(1) $ 4,473,721 $ 3,941,143 Unproved Properties 176,327 141,719 4,650,048 4,082,862 Less — Accumulated Depreciation, Depletion and Amortization 2,572,348 1,211,610 $ 2,077,700 $ 2,871,252 (1) Includes asset retirement costs of $113.3 million and $75.7 million at September 30, 2015 and 2014, 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 2020. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2016. Following is a summary of costs excluded from amortization at September 30, 2015: Total as of September 30, 2015 Year Costs Incurred 2015 2014 2013 Prior (Thousands) Acquisition Costs $ 61,253 $ 2,777 $ 7,057 $ 905 $ 50,514 Development Costs 86,641 74,444 9,343 665 2,189 Exploration Costs 27,815 10,210 17,605 — — Capitalized Interest 618 303 315 — — $ 176,327 $ 87,734 $ 34,320 $ 1,570 $ 52,703 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities Year Ended September 30 2015 2014 2013 (Thousands) United States Property Acquisition Costs: Proved $ 1,767 $ 18,213 $ 7,575 Unproved 19,998 7,884 9,274 Exploration Costs(1) 53,222 71,850 49,483 Development Costs(2) 454,605 490,164 460,554 Asset Retirement Costs 37,595 (4,946 ) 37,546 $ 567,187 $ 583,165 $ 564,432 (1) Amounts for 2015, 2014 and 2013 include capitalized interest of $0.4 million , $0.7 million and $0.4 million , respectively. (2) Amounts for 2015, 2014 and 2013 include capitalized interest of $0.5 million , $0.7 million and $0.7 million , respectively. For the years ended September 30, 2015, 2014 and 2013, the Company spent $161.8 million , $179.9 million and $148.5 million , respectively, developing proved undeveloped reserves. Results of Operations for Producing Activities Year Ended September 30 2015 2014 2013 (Thousands, except per Mcfe amounts) United States Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $1 for all years presented and transfers to operations of $1,946, $2,145 and $612, respectively) $ 350,673 $ 515,080 $ 371,311 Oil, Condensate and Other Liquids 156,048 298,179 291,762 Total Operating Revenues(1) 506,721 813,259 663,073 Production/Lifting Costs 167,800 165,534 119,243 Franchise/Ad Valorem Taxes 20,167 20,765 17,200 Purchased Emission Allowance Expense 3,089 — — Accretion Expense 6,186 6,192 3,929 Depreciation, Depletion and Amortization ($1.49, $1.82 and $1.98 per Mcfe of production) 234,480 291,651 238,467 Impairment of Oil and Gas Producing Properties 1,126,257 — — Income Tax Expense (444,393 ) 140,484 120,431 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ (606,865 ) $ 188,633 $ 163,803 (1) 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 25 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 for the past twelve years. 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 that determines 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 1998 with over 13 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, 2015 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, state data-sites and 2D and 3D seismic data. This data was 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, 2012 925,411 63,023 988,434 Extensions and Discoveries 360,922 (1) 702 361,624 Revisions of Previous Estimates 53,038 112 53,150 Production (100,633 ) (2) (3,060 ) (103,693 ) September 30, 2013 1,238,738 60,777 1,299,515 Extensions and Discoveries 446,821 (1) — 446,821 Revisions of Previous Estimates 43,690 1,358 45,048 Production (139,097 ) (2) (3,210 ) (142,307 ) Purchases of Minerals in Place 33,986 — 33,986 Sale of Minerals in Place (76 ) (103 ) (179 ) 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 Proved Developed Reserves: September 30, 2012 544,560 59,923 604,483 September 30, 2013 807,055 59,862 866,917 September 30, 2014 1,119,901 57,907 1,177,808 September 30, 2015 1,267,498 49,346 1,316,844 Proved Undeveloped Reserves: September 30, 2012 380,851 3,100 383,951 September 30, 2013 431,683 915 432,598 September 30, 2014 504,161 915 505,076 September 30, 2015 825,284 — 825,284 (1) Extensions and discoveries include 355 Bcf (during 2013), 442 Bcf (during 2014) and 598 Bcf (during 2015), of Marcellus Shale gas in the Appalachian Region. (2) Production includes 93,999 MMcf (during 2013), 131,590 MMcf (during 2014) and 130,291 MMcf (during 2015), 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, 2012 306 42,556 42,862 Extensions and Discoveries — 2,443 2,443 Revisions of Previous Estimates 5 (881 ) (876 ) Production (28 ) (2,803 ) (2,831 ) September 30, 2013 283 41,315 41,598 Extensions and Discoveries 18 1,521 1,539 Revisions of Previous Estimates (17 ) (1,677 ) (1,694 ) Production (31 ) (3,005 ) (3,036 ) Purchases of Minerals in Place — 83 83 Sales of Minerals in Place — (13 ) (13 ) 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 Proved Developed Reserves: September 30, 2012 306 38,138 38,444 September 30, 2013 283 38,082 38,365 September 30, 2014 253 37,002 37,255 September 30, 2015 220 33,150 33,370 Proved Undeveloped Reserves: September 30, 2012 — 4,418 4,418 September 30, 2013 — 3,233 3,233 September 30, 2014 — 1,222 1,222 September 30, 2015 — 352 352 The Company’s proved undeveloped (PUD) reserves increased from 512 Bcfe at September 30, 2014 to 827 Bcfe at September 30, 2015. PUD reserves in the Marcellus Shale increased from 504 Bcfe at September 30, 2014 to 825 Bcfe at September 30, 2015. The Company’s total PUD reserves were 35% of total proved reserves at September 30, 2015, up from 27% of total proved reserves at September 30, 2014. The Company’s PUD reserves increased from 452 Bcfe at September 30, 2013 to 512 Bcfe at September 30, 2014. PUD reserves in the Marcellus Shale increased from 432 Bcfe at September 30, 2013 to 504 Bcfe at September 30, 2014. The Company’s total PUD reserves were 27% of total proved reserves at September 30, 2014, down from 29% of total proved reserves at September 30, 2013. The increase in PUD reserves in 2015 of 315 Bcfe is a result of 496 Bcfe in new PUD reserve additions ( 494 Bcfe from the Marcellus Shale), 26 Bcfe in upward revisions to remaining PUD reserves, offset by 168 Bcfe in PUD conversions to developed reserves and 39 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale ( 37 Bcfe) in Tioga County, where the Company has no near term plans to develop these reserves as it is employing capital elsewhere. An additional 2 Bcfe ( 279 Mbbl) of PUD reserves were removed at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere. The increase in PUD reserves in 2014 of 60 Bcfe is a result of 290 Bcfe in new PUD reserve additions ( 288 Bcfe from the Marcellus Shale), 20 Bcfe in PUD reserves acquired, 12 Bcfe in upward revisions to remaining PUD reserves, offset by 229 Bcfe in PUD conversions to developed reserves and 33 Bcfe in PUD reserves removed. The PUD reserves removed were primarily in the Marcellus Shale ( 24 Bcfe) in Seneca’s non-operated joint venture in Clearfield County where the operator had previously drilled and cased the horizontal wells to total depth and does not appear now to have firm plans for their completion. An additional 9 Bcfe ( 1,501 Mbbl) of PUD reserves were removed at the Midway Sunset field in the Tulare reservoir as the Company has no near term plans to develop these reserves as it is employing capital elsewhere. The Company invested $162 million during the year ended September 30, 2015 to convert 168 Bcfe ( 184 Bcfe including revisions) of PUD reserves to developed reserves. This represents 33% of the PUD reserves booked at September 30, 2014. The Company invested $180 million during the year ended September 30, 2014 to convert 229 Bcfe ( 248 Bcfe including revisions) of September 30, 2013 PUD reserves to proved developed reserves. This represented 51% of the PUD reserves booked at September 30, 2013. In 2016, the Company estimates that it will invest approximately $166 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 47% of its beginning year PUD reserves in fiscal 2011, 33% of its beginning year PUD reserves in fiscal 2012, 39% of its beginning year PUD reserves in fiscal 2013, 51% of its beginning year PUD reserves in fiscal 2014 and 33% of its beginning year PUD reserves in fiscal 2015. At September 30, 2015, 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 2015 2014 2013 (Thousands) United States Future Cash Inflows $ 6,916,775 $ 10,001,545 $ 8,943,942 Less: Future Production Costs 2,854,142 2,795,657 2,334,393 Future Development Costs 761,922 790,033 749,876 Future Income Tax Expense at Applicable Statutory Rate 1,117,433 2,434,370 2,113,101 Future Net Cash Flows 2,183,278 3,981,485 3,746,572 Less: 10% Annual Discount for Estimated Timing of Cash Flows 860,244 1,914,607 1,780,206 Standardized Measure of Discounted Future Net Cash Flows $ 1,323,034 $ 2,066,878 $ 1,966,366 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 2015 2014 2013 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 2,066,878 $ 1,966,366 $ 1,469,791 Sales, Net of Production Costs (318,753 ) (626,960 ) (526,630 ) Net Changes in Prices, Net of Production Costs (1,752,843 ) (38,723 ) 339,655 Extensions and Discoveries 266,159 381,008 390,255 Changes in Estimated Future Development Costs 164,510 68,731 6,117 Purchases of Minerals in Place — 34,705 — Sales of Minerals in Place (1 ) (691 ) — Previously Estimated Development Costs Incurred 161,833 179,502 148,535 Net Change in Income Taxes at Applicable Statutory Rate 545,442 (231,807 ) (130,574 ) Revisions of Previous Quantity Estimates (16,573 ) 55,184 34,864 Accretion of Discount and Other 206,382 279,563 234,353 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,323,034 $ 2,066,878 $ 1,966,366

Valuation And Qualifying Accoun

Valuation And Qualifying Accounts	12 Months Ended
	Sep. 30, 2015
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, 2015 Allowance for Uncollectible Accounts $ 31,811 $ 9,316 $ 2,585 $ 14,683 $ 29,029 Year Ended September 30, 2014 Allowance for Uncollectible Accounts $ 27,144 $ 10,856 $ 3,241 $ 9,430 $ 31,811 Year Ended September 30, 2013 Allowance for Uncollectible Accounts $ 30,317 $ 5,568 $ 2,390 $ 11,131 $ 27,144 (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, 2015
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 Due to the adoption of the authoritative guidance regarding the presentation of debt issuance costs, certain prior year amounts have been reclassified to conform with current year presentation. The Company reclassified debt issuance costs related to long-term debt previously shown as Unamortized Debt Expense as a direct deduction from the carrying value of Long-Term Debt on the Consolidated Balance Sheet.
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. The book value of the oil and gas properties exceeded the ceiling at September 30, 2015 as well as at June 30, 2015 and March 31, 2015. As such, the Company recognized pre-tax impairment charges of $1.1 billion for the year ended September 30, 2015. Deferred income tax benefits of $476.1 million related to the impairment charges were also recognized for the year ended September 30, 2015. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2015 , 2014 , and 2013 , estimated future net cash flows were increased by $194.5 million , decreased by $33.6 million and increased by $71.6 million , respectively. 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 2015 2014 (Thousands) Exploration and Production $ 4,556,096 $ 3,995,200 Pipeline and Storage 1,710,947 1,609,593 Gathering 307,274 239,507 Utility 1,888,489 1,833,104 Energy Marketing 3,494 3,366 All Other and Corporate 109,193 108,986 $ 8,575,493 $ 7,789,756 Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2015 2014 2013 Exploration and Production, per Mcfe(1) $ 1.52 $ 1.85 $ 2.02 Pipeline and Storage 2.4 % 2.4 % 2.5 % Gathering 4.0 % 3.3 % 3.7 % Utility 2.6 % 2.6 % 2.6 % Energy Marketing 6.1 % 5.8 % 3.9 % All Other and Corporate 1.4 % 0.9 % 1.3 % (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 $1.49 , $1.82 and $1.98 per Mcfe of production in 2015 , 2014 and 2013 , respectively.
Goodwill	Goodwill The Company has recognized goodwill of $5.5 million as of September 30, 2015 and 2014 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, 2015 , 2014 and 2013 , 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 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, 2015, 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, 2015 Balance at October 1, 2014 $ 43,659 $ 8,382 $ (56,020 ) $ (3,979 ) Other Comprehensive Gains and Losses Before Reclassifications 220,146 (2,039 ) (19,616 ) 198,491 Amounts Reclassified From Other Comprehensive Income (106,608 ) (374 ) 5,842 (101,140 ) Balance at September 30, 2015 $ 157,197 $ 5,969 $ (69,794 ) $ 93,372 Year Ended September 30, 2014 Balance at October 1, 2013 $ 30,722 $ 6,337 $ (56,293 ) $ (19,234 ) Other Comprehensive Gains and Losses Before Reclassifications 4,805 2,465 (5,560 ) 1,710 Amounts Reclassified From Other Comprehensive Loss 8,132 (420 ) 5,833 13,545 Balance at September 30, 2014 $ 43,659 $ 8,382 $ (56,020 ) $ (3,979 ) 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) credit was ( $1.5 million ) and $0.2 million at September 30, 2015 and 2014, respectively. The total amount for accumulated losses was $68.3 million and $56.2 million at September 30, 2015 and 2014, 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 income (loss) for the year ended September 30, 2015 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 2015 2014 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $180,069 ($14,880 ) Operating Revenues Commodity Contracts 4,884 (2,767 ) Purchased Gas Gains (Losses) on Securities Available for Sale 591 662 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit 109 131 (1) Net Actuarial Loss (9,326 ) (9,334 ) (1) 176,327 (26,188 ) Total Before Income Tax (75,187 ) 12,643 Income Tax Expense $101,140 ($13,545 ) 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 - Current	Gas Stored Underground — Current In the Utility segment, gas stored underground — current in the amount of $26.8 million is carried at lower of cost or market, on a LIFO method. Based upon the average price of spot market gas purchased in September 2015, including transportation costs, the current cost of replacing this inventory of gas stored underground — current exceeded the amount stated on a LIFO basis by approximately $13.8 million at September 30, 2015. All other gas stored underground — current, which is in the Energy Marketing segment, is carried at an average cost method, subject to lower of cost or market 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, 2015, the remaining weighted average amortization period for such costs was approximately 4 years .
Income Taxes	Income Taxes The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed. 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 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 2015 2014 (Thousands) Prepayments $ 10,743 $ 10,079 Prepaid Property and Other Taxes 13,709 13,743 Federal Income Taxes Receivable — 8,211 Fair Values of Firm Commitments 15,775 — Regulatory Assets 20,438 22,719 $ 60,665 $ 54,752
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 2015 2014 (Thousands) Accrued Capital Expenditures $ 53,652 $ 80,348 Regulatory Liabilities 5,346 18,072 Federal Income Taxes Payable 5,686 — State Income Taxes Payable 1,170 5,798 Other 30,703 32,454 $ 96,557 $ 136,672
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, 2015 and 2014, customers in the balanced billing programs had advanced excess funds of $16.2 million and $19.0 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, 2015 and 2014, the Company had received customer security deposits amounting to $16.5 million and $15.8 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 only potentially dilutive securities the Company has outstanding are stock options, SARs, restricted stock units and performance shares. As the Company recognized a net loss in 2015, the aforementioned securities, amounting to 709,063 securities, were not recognized in the diluted earnings per share calculation for 2015. For 2014 and 2013, 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. For 2014 and 2013, 1,007 securities and 181,418 securities were excluded as being antidilutive, respectively.
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. 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. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements and disclosures. In June 2014, the FASB issued authoritative guidance regarding accounting for share-based payments when the terms of an award provide that a performance target could be achieved after the employee has completed the requisite service period. This authoritative guidance requires that such performance targets that affect vesting be treated as performance conditions, meaning that the performance target should not be factored in the calculation of the award at the grant date. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2017, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements. In April 2015, the FASB issued authoritative guidance regarding the presentation of debt issuance costs. The authoritative guidance requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The Company early adopted this guidance at September 30, 2015 on a retrospective basis. In July 2015, the FASB issued authoritative guidance simplifying inventory measurement by requiring companies to value inventory at the lower of cost and net realizable value. The authoritative guidance applies to all inventory other than inventory that is measured using last-in, first-out or the retail inventory method. The intention of this authoritative guidance is to eliminate some diversity in practice. This authoritative guidance will be effective as of the Company's first quarter of fiscal 2018, with early adoption permitted. The Company is currently evaluating the impact that adoption of this guidance will have on its consolidated financial statements.

Summary Of Significant Accoun22

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Schedule Of Depreciable Plant By Segment	The following is a summary of depreciable plant by segment: As of September 30 2015 2014 (Thousands) Exploration and Production $ 4,556,096 $ 3,995,200 Pipeline and Storage 1,710,947 1,609,593 Gathering 307,274 239,507 Utility 1,888,489 1,833,104 Energy Marketing 3,494 3,366 All Other and Corporate 109,193 108,986 $ 8,575,493 $ 7,789,756
Average Depreciation Depletion And Amortization Rates	Average depreciation, depletion and amortization rates are as follows: Year Ended September 30 2015 2014 2013 Exploration and Production, per Mcfe(1) $ 1.52 $ 1.85 $ 2.02 Pipeline and Storage 2.4 % 2.4 % 2.5 % Gathering 4.0 % 3.3 % 3.7 % Utility 2.6 % 2.6 % 2.6 % Energy Marketing 6.1 % 5.8 % 3.9 % All Other and Corporate 1.4 % 0.9 % 1.3 % (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 $1.49 , $1.82 and $1.98 per Mcfe of production in 2015 , 2014 and 2013 , respectively.
Components Of Accumulated Other Comprehensive Income (Loss)	The components of Accumulated Other Comprehensive Income (Loss) and changes for the year ended September 30, 2015, 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, 2015 Balance at October 1, 2014 $ 43,659 $ 8,382 $ (56,020 ) $ (3,979 ) Other Comprehensive Gains and Losses Before Reclassifications 220,146 (2,039 ) (19,616 ) 198,491 Amounts Reclassified From Other Comprehensive Income (106,608 ) (374 ) 5,842 (101,140 ) Balance at September 30, 2015 $ 157,197 $ 5,969 $ (69,794 ) $ 93,372 Year Ended September 30, 2014 Balance at October 1, 2013 $ 30,722 $ 6,337 $ (56,293 ) $ (19,234 ) Other Comprehensive Gains and Losses Before Reclassifications 4,805 2,465 (5,560 ) 1,710 Amounts Reclassified From Other Comprehensive Loss 8,132 (420 ) 5,833 13,545 Balance at September 30, 2014 $ 43,659 $ 8,382 $ (56,020 ) $ (3,979 )
Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Income (Loss)	The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the year ended September 30, 2015 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 2015 2014 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts $180,069 ($14,880 ) Operating Revenues Commodity Contracts 4,884 (2,767 ) Purchased Gas Gains (Losses) on Securities Available for Sale 591 662 Other Income Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans: Prior Service Credit 109 131 (1) Net Actuarial Loss (9,326 ) (9,334 ) (1) 176,327 (26,188 ) Total Before Income Tax (75,187 ) 12,643 Income Tax Expense $101,140 ($13,545 ) 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 2015 2014 (Thousands) Prepayments $ 10,743 $ 10,079 Prepaid Property and Other Taxes 13,709 13,743 Federal Income Taxes Receivable — 8,211 Fair Values of Firm Commitments 15,775 — Regulatory Assets 20,438 22,719 $ 60,665 $ 54,752
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 2015 2014 (Thousands) Accrued Capital Expenditures $ 53,652 $ 80,348 Regulatory Liabilities 5,346 18,072 Federal Income Taxes Payable 5,686 — State Income Taxes Payable 1,170 5,798 Other 30,703 32,454 $ 96,557 $ 136,672

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation [Abstract]
Schedule Of Change In Asset Retirement Obligation	A reconciliation of the Company’s asset retirement obligations are shown below: Year Ended September 30 2015 2014 2013 (Thousands) Balance at Beginning of Year $ 117,713 $ 119,511 $ 119,246 Liabilities Incurred and Revisions of Estimates 38,150 (2,496 ) (4,796 ) Liabilities Settled (6,825 ) (6,955 ) (1,744 ) Accretion Expense 7,767 7,653 6,805 Balance at End of Year $ 156,805 $ 117,713 $ 119,511

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2015
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 2015 2014 (Thousands) Regulatory Assets(1): Pension Costs(2) (Note H) $ 202,781 $ 164,804 Post-Retirement Benefit Costs(2) (Note H) 34,217 17,128 Recoverable Future Taxes (Note D) 168,214 163,485 Environmental Site Remediation Costs(2) (Note I) 24,606 25,645 NYPSC Assessment(3) 13,916 12,730 Asset Retirement Obligations(2) (Note B) 12,250 12,006 Unamortized Debt Expense (Note A) 2,218 2,747 Other(4) 10,895 14,842 Total Regulatory Assets 469,097 413,387 Less: Amounts Included in Other Current Assets (20,438 ) (22,719 ) Total Long-Term Regulatory Assets $ 448,659 $ 390,668 At September 30 2015 2014 (Thousands) Regulatory Liabilities: Cost of Removal Regulatory Liability $ 184,907 $ 173,199 Taxes Refundable to Customers (Note D) 89,448 91,736 Post-Retirement Benefit Costs (Note H) 60,013 53,650 Amounts Payable to Customers (See Regulatory Mechanisms in Note A) 56,778 33,745 Off-System Sales and Capacity Release Credits(5) 21,027 12,805 Other(6) 32,923 32,769 Total Regulatory Liabilities 445,096 397,904 Less: Amounts included in Current and Accrued Liabilities (62,124 ) (51,817 ) Total Long-Term Regulatory Liabilities $ 382,972 $ 346,087 (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) Amounts are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and September 30, 2014 since such amounts are expected to be recovered from ratepayers in the next 12 months. (4) $6,522 and $9,989 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $4,373 and $4,853 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively. (5) The September 30, 2015 amount is included in Other Regulatory Liabilities on the Consolidated Balance Sheet at September 30, 2015. The September 30, 2014 amount is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2014 since such amount is expected to be passed back to ratepayers in the next 12 months. (6) $5,346 and $5,267 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $27,577 and $27,502 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2015
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 2015 2014 2013 (Thousands) Current Income Taxes — Federal $ 25,064 $ 34,579 $ (632 ) State 13,387 12,620 5,503 Deferred Income Taxes — Federal (244,336 ) 116,143 130,318 State (113,251 ) 26,272 37,569 (319,136 ) 189,614 172,758 Deferred Investment Tax Credit (414 ) (434 ) (426 ) Total Income Taxes $ (319,550 ) $ 189,180 $ 172,332 Presented as Follows: Other Income $ (414 ) $ (434 ) $ (426 ) Income Tax Expense (Benefit) (319,136 ) 189,614 172,758 Total Income Taxes $ (319,550 ) $ 189,180 $ 172,332
Schedule Of Income Tax Reconciliation By Applying Federal Income Tax Rate	The following is a reconciliation of this difference: Year Ended September 30 2015 2014 2013 (Thousands) U.S. Income (Loss) Before Income Taxes $ (698,977 ) $ 488,593 $ 432,333 Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35% $ (244,642 ) $ 171,008 $ 151,317 State Income Taxes (Benefit) (64,912 ) 25,280 27,997 Miscellaneous (9,996 ) (7,108 ) (6,982 ) Total Income Taxes $ (319,550 ) $ 189,180 $ 172,332
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 2015 2014 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment $ 1,291,718 $ 1,614,515 Pension and Other Post-Retirement Benefit Costs 141,032 113,248 Unrealized Hedging Gains 118,522 37,051 Other 51,230 50,884 Total Deferred Tax Liabilities 1,602,502 1,815,698 Deferred Tax Assets: Pension and Other Post-Retirement Benefit Costs (168,451 ) (124,452 ) Tax Loss and Credit Carryforwards (185,681 ) (171,423 ) Other (110,408 ) (103,863 ) Total Deferred Tax Assets (464,540 ) (399,738 ) Total Net Deferred Income Taxes $ 1,137,962 $ 1,415,960 Presented as Follows: Deferred Tax Liability/(Asset) — Current $ (137,200 ) $ (40,323 ) Deferred Tax Liability — Non-Current 1,275,162 1,456,283 Total Net Deferred Income Taxes $ 1,137,962 $ 1,415,960
Reconciliation Of The Change In Unrecognized Tax Benefits	The following is a reconciliation of the change in unrecognized tax benefits: Year Ended September 30 2015 2014 2013 (Thousands) Balance at Beginning of Year $ 3,147 $ 2,001 $ 11,170 Additions for Tax Positions Related to Current Year — — 700 Additions for Tax Positions of Prior Years 2,504 2,447 164 Reductions for Tax Positions of Prior Years (566 ) (1,301 ) (10,033 ) Balance at End of Year $ 5,085 $ 3,147 $ 2,001

Capitalization And Short-Term26

Capitalization And Short-Term Borrowings (Tables)	12 Months Ended
	Sep. 30, 2015
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, 2012 83,330 $ 83,330 $ 669,501 $ 1,306,284 $ (99,020 ) Net Income Available for Common Stock 260,001 Dividends Declared on Common Stock ($1.48 Per Share) (123,668 ) Other Comprehensive Income, Net of Tax 79,786 Share-Based Payment Expense(2) 11,537 Common Stock Issued Under Stock and Benefit Plans(1) 332 332 6,646 Balance at September 30, 2013 83,662 83,662 687,684 1,442,617 (19,234 ) Net Income Available for Common Stock 299,413 Dividends Declared on Common Stock ($1.52 Per Share) (127,669 ) Other Comprehensive Income, Net of Tax 15,255 Share-Based Payment Expense(2) 10,654 Common Stock Issued Under Stock and Benefit Plans(1) 495 495 17,806 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 (3) $ 93,372 (1) Paid in Capital includes tax benefits of $9.1 million , $4.6 million and $0.7 million for September 30, 2015, 2014 and 2013, 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, 2015, $959.0 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, 2014 482,000 $ 36.71 Granted in 2015 — $ — Exercised in 2015 (175,500 ) $ 34.94 Forfeited in 2015 — $ — Outstanding at September 30, 2015 306,500 $ 37.73 0.94 $ 3,754 Option shares exercisable at September 30, 2015 306,500 $ 37.73 0.94 $ 3,754 Option shares available for future grant at September 30, 2015(1) 3,184,675 (1) Includes shares available for 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, 2014 1,793,482 $ 48.11 Granted in 2015 — $ — Exercised in 2015 (60,698 ) $ 31.29 Forfeited in 2015 — $ — Outstanding at September 30, 2015 1,732,784 $ 48.70 4.98 $ 2,224 SARs exercisable at September 30, 2015 1,614,702 $ 48.36 4.82 $ 2,621
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, 2014 89,518 $ 49.05 Granted in 2015 — $ — Vested in 2015 (29,518 ) $ 52.14 Forfeited in 2015 — $ — Outstanding at September 30, 2015 60,000 $ 47.53
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, 2014 204,519 $ 56.36 Granted in 2015 88,899 $ 64.04 Vested in 2015 (48,490 ) $ 57.17 Forfeited in 2015 (7,980 ) $ 57.38 Outstanding at September 30, 2015 236,948 $ 59.04
Schedule Of Share-Based Compensation For Performance Based Restricted Stock Units	Transactions involving performance based restricted stock units for all plans are summarized as follows: Number of Performance Based Restricted Stock Units Weighted Average Fair Value per Award Outstanding at September 30, 2014 233,876 $ 49.61 Granted in 2015 — $ — Vested in 2015 — $ — Forfeited in 2015 (389 ) $ 48.49 Outstanding at September 30, 2015 233,487 $ 49.61
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, 2014 98,466 $ 67.16 Granted in 2015 107,044 $ 65.26 Vested in 2015 — $ — Forfeited in 2015 (768 ) $ 67.16 Outstanding at September 30, 2015 204,742 $ 66.17
Schedule Of Long-Term Debt	The outstanding long-term debt is as follows: At September 30 2015 2014 (Thousands) Medium-Term Notes(1): 7.4% due March 2023 to June 2025 $ 99,000 $ 99,000 Notes(1)(3): 3.75% to 8.75% due April 2018 to July 2025 2,000,000 1,550,000 Total Long-Term Debt 2,099,000 1,649,000 Less Unamortized Discount and Debt Issuance Costs 14,991 11,557 Less Current Portion(2) — — $ 2,084,009 $ 1,637,443 (1) The Medium-Term Notes and Notes are unsecured. (2) None of the Company’s long-term debt at September 30, 2015 and 2014 will mature within the following twelve-month period. (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.
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 2015 2014 2013 Risk-Free Interest Rate 1.01 % 0.62 % N/A Remaining Term at Date of Grant (Years) 2.78 2.78 N/A Expected Volatility 20.1 % 28.3 % N/A Expected Dividend Yield (Quarterly) N/A N/A N/A
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Weighted Average Assumptions Used in Estimating Fair Value	The following weighted average assumptions were used in estimating the fair value of SARs at the date of grant: Year Ended September 30 2015 2014 2013 Risk-Free Interest Rate N/A N/A 1.55 % Expected Life (Years) N/A N/A 8.25 Expected Volatility N/A N/A 25.61 % Expected Dividend Yield (Quarterly) N/A N/A 0.69 %

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Sep. 30, 2015
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, 2015 and 2014. 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, 2015 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 $ 92,196 $ — $ — $ — $ 92,196 Derivative Financial Instruments: Commodity Futures Contracts — Gas 6,373 — — (6,373 ) — Over the Counter Swaps — Gas and Oil — 272,335 1,791 (808 ) 273,318 Foreign Currency Contracts — — — (2,955 ) (2,955 ) Other Investments: Balanced Equity Mutual Fund 34,884 — — — 34,884 Fixed Income Mutual Funds 8,004 — — — 8,004 Common Stock — Financial Services Industry 4,318 — — — 4,318 Other Common Stock 450 — — — 450 Hedging Collateral Deposits 11,124 — — — 11,124 Total $ 157,349 $ 272,335 $ 1,791 $ (10,136 ) $ 421,339 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 15,276 $ — $ — $ (6,373 ) $ 8,903 Over the Counter Swaps — Gas and Oil — 1,981 — (808 ) 1,173 Foreign Currency Contracts — 2,955 — (2,955 ) — Total $ 15,276 $ 4,936 $ — $ (10,136 ) $ 10,076 Total Net Assets/(Liabilities) $ 142,073 $ 267,399 $ 1,791 $ — $ 411,263 At Fair Value as of September 30, 2014 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 $ 23,794 $ — $ — $ — $ 23,794 Derivative Financial Instruments: Commodity Futures Contracts — Gas 2,725 — — (1,987 ) 738 Over the Counter Swaps — Gas and Oil — 75,951 1,368 (5,451 ) 71,868 Other Investments: Balanced Equity Mutual Fund 35,331 — — — 35,331 Common Stock — Financial Services Industry 6,629 — — — 6,629 Other Common Stock 455 — — — 455 Hedging Collateral Deposits 2,734 — — — 2,734 Total $ 71,668 $ 75,951 $ 1,368 $ (7,438 ) $ 141,549 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts — Gas $ 2,674 $ — $ — $ (1,987 ) $ 687 Over the Counter Swaps — Gas and Oil — 5,523 — (5,451 ) 72 Total $ 2,674 $ 5,523 $ — $ (7,438 ) $ 759 Total Net Assets/(Liabilities) $ 68,994 $ 70,428 $ 1,368 $ — $ 140,790 (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 Using Unobservable Inputs (Level 3)	All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below (amounts in parentheses indicate credits in the derivative asset/liability accounts). Fair Value Measurements Using Unobservable Inputs (Level 3) Total Gains/Losses October 1, 2014 (Gains)/Losses Realized and Included in Earnings Gains/(Losses) Unrealized and Included in Other Comprehensive Income (Loss) Transfer In/(Out) of Level 3 September 30, 2015 (Dollars in thousands) Derivative Financial Instruments(2) $ 1,368 $ (12,738 ) (1) $ 13,161 $ — $ 1,791 (1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2015. (2) Derivative Financial Instruments are shown on a net basis. Total Gains/Losses October 1, 2013 (Gains)/Losses Realized and Included in Earnings Gains/(Losses) Transfer In/(Out) of Level 3 September 30, 2014 (Dollars in thousands) Derivative Financial Instruments(2) $ (5,190 ) $ 2,217 (1) $ 4,341 $ — $ 1,368 (1) Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2014. (2) Derivative Financial Instruments are shown on a net basis.

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Sep. 30, 2015
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 2015 Carrying Amount 2015 Fair Value 2014 Carrying Amount 2014 Fair Value (Thousands) Long-Term Debt $ 2,084,009 $ 2,129,558 $ 1,637,443 $ 1,775,715
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, 2015 and 2014 (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, 2015 2014 2015 2014 2015 2014 Commodity Contracts $ 377,957 $ 9,763 Operating Revenue $ 180,069 $ (14,880 ) Operating Revenue $ 3,563 $ 624 Commodity Contracts $ 6,016 $ (4,429 ) Purchased Gas $ 4,884 $ (2,767 ) Not Applicable $ — $ — Foreign Currency Contracts $ (2,955 ) $ — Not Applicable $ — $ — Not Applicable $ — $ — Total $ 381,018 $ 5,334 $ 184,953 $ (17,647 ) $ 3,563 $ 624
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, 2015 Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income for the Year Ended September 30, 2015 (In thousands) Commodity Contracts Operating Revenues $ (13,944 ) $ 13,944 Commodity Contracts Purchased Gas (18 ) 18 $ (13,962 ) $ 13,962

Retirement Plan And Other Pos29

Retirement Plan And Other Post-Retirement Benefits (Tables)	12 Months Ended
	Sep. 30, 2015
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 2015, 2014 and 2013. Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2015 2014 2013 2015 2014 2013 (Thousands) Change in Benefit Obligation Benefit Obligation at Beginning of Period $ 999,499 $ 946,305 $ 1,070,744 $ 465,583 $ 460,634 $ 561,263 Service Cost 12,047 11,987 15,846 2,693 2,939 4,705 Interest Cost 41,217 43,574 36,498 19,285 21,308 19,212 Plan Participants’ Contributions — — — 2,242 2,265 2,141 Retiree Drug Subsidy Receipts — — — 1,338 1,419 1,526 Amendments(1) 7,752 — — — — — Actuarial (Gain) Loss 23,426 53,887 (121,631 ) (1,575 ) 1,087 (104,455 ) Benefits Paid (57,751 ) (56,254 ) (55,152 ) (24,579 ) (24,069 ) (23,758 ) Benefit Obligation at End of Period $ 1,026,190 $ 999,499 $ 946,305 $ 464,987 $ 465,583 $ 460,634 Change in Plan Assets Fair Value of Assets at Beginning of Period $ 869,791 $ 799,307 $ 701,676 $ 497,601 $ 472,392 $ 414,134 Actual Return on Plan Assets (13,370 ) 93,238 98,783 534 44,898 61,715 Employer Contributions 36,200 33,500 54,000 2,161 2,115 18,160 Plan Participants’ Contributions — — — 2,242 2,265 2,141 Benefits Paid (57,751 ) (56,254 ) (55,152 ) (24,579 ) (24,069 ) (23,758 ) Fair Value of Assets at End of Period $ 834,870 $ 869,791 $ 799,307 $ 477,959 $ 497,601 $ 472,392 Net Amount Recognized at End of Period (Funded Status) $ (191,320 ) $ (129,708 ) $ (146,998 ) $ 12,972 $ 32,018 $ 11,758 Amounts Recognized in the Balance Sheets Consist of: Non-Current Liabilities $ (191,320 ) $ (129,708 ) $ (146,998 ) $ (11,487 ) $ (4,494 ) $ (11,016 ) Non-Current Assets — — — 24,459 36,512 22,774 Net Amount Recognized at End of Period $ (191,320 ) $ (129,708 ) $ (146,998 ) $ 12,972 $ 32,018 $ 11,758 Accumulated Benefit Obligation $ 968,984 $ 940,068 $ 886,942 N/A N/A N/A Weighted Average Assumptions Used to Determine Benefit Obligation at September 30 Discount Rate 4.25 % 4.25 % 4.75 % 4.50 % 4.25 % 4.75 % Rate of Compensation Increase 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % 4.75 % Retirement Plan Other Post-Retirement Benefits Year Ended September 30 Year Ended September 30 2015 2014 2013 2015 2014 2013 (Thousands) Components of Net Periodic Benefit Cost Service Cost $ 12,047 $ 11,987 $ 15,846 $ 2,693 $ 2,939 $ 4,705 Interest Cost 41,217 43,574 36,498 19,285 21,308 19,212 Expected Return on Plan Assets (59,615 ) (59,974 ) (57,346 ) (34,089 ) (37,424 ) (32,872 ) Amortization of Prior Service Cost (Credit) 183 210 238 (1,913 ) (2,138 ) (2,138 ) Amortization of Transition Amount — — — — — 8 Recognition of Actuarial Loss(2) 36,129 36,007 52,776 4,148 2,645 20,892 Net Amortization and Deferral for Regulatory Purposes 7,739 8,151 (10,406 ) 20,322 23,263 11,844 Net Periodic Benefit Cost $ 37,700 $ 39,955 $ 37,606 $ 10,446 $ 10,593 $ 21,651 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30 Discount Rate 4.25 % 4.75 % 3.50 % 4.25 % 4.75 % 3.50 % Expected Return on Plan Assets 7.50 % 8.00 % 8.00 % 7.00 % 8.00 % 8.00 % 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 2015, the changes in such amounts during 2015, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal 2016 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 $ (287,180 ) $ (59,914 ) $ (24,929 ) Prior Service (Cost) Credit (8,425 ) 5,027 — Net Amount Recognized $ (295,605 ) $ (54,887 ) $ (24,929 ) Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2015(1) Increase in Actuarial Loss, excluding amortization(2) $ (96,412 ) $ (31,980 ) $ (4,321 ) Change due to Amortization of Actuarial Loss 36,129 4,148 2,925 Prior Service (Cost) Credit (7,569 ) (1,913 ) — Net Change $ (67,852 ) $ (29,745 ) $ (1,396 ) Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1) Net Actuarial Loss $ (32,248 ) $ (5,530 ) $ (3,295 ) Prior Service (Cost) Credit (1,234 ) 912 — Net Amount Expected to be Recognized $ (33,482 ) $ (4,618 ) $ (3,295 ) (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 2016 $ 25,728 $ (1,786 ) 2017 $ 26,942 $ (1,935 ) 2018 $ 28,059 $ (2,094 ) 2019 $ 29,038 $ (2,259 ) 2020 $ 30,079 $ (2,405 ) 2021 through 2025 $ 161,958 $ (14,197 )
Schedule Of Health Care Cost Trend Rates	Assumed health care cost trend rates as of September 30 were: 2015 2014 2013 Rate of Medical Cost Increase for Pre Age 65 Participants 6.93 % (1) 7.10 % (1) 7.28 % (1) Rate of Medical Cost Increase for Post Age 65 Participants 6.68 % (1) 6.73 % (1) 6.78 % (1) Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 7.17 % (1) 7.47 % (1) 7.78 % (1) Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 6.68 % (1) 6.73 % (1) 6.78 % (1) Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 6.65 % (1) 6.79 % (1) 7.03 % (1) (1) It was assumed that this rate would gradually decline to 4.5% by 2028.
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 Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Domestic Equities $ 128,336 $ — $ 128,336 $ — Collective Trust Funds — International Equities 48,857 — 48,857 — Exchange Traded Funds — Fixed Income 233,471 233,471 — — Cash Held in Collective Trust Funds 13,119 — 13,119 — Total VEBA Trust Investments 423,783 233,471 190,312 — 401(h) Investments 53,686 10,420 41,381 1,885 Total Investments (including 401(h) Investments) $ 477,469 $ 243,891 $ 231,693 $ 1,885 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 490 Total Other Post-Retirement Benefit Assets $ 477,959 Total Fair Value Level 1 Level 2 Level 3 Other Post-Retirement Benefit Assets held in VEBA Trusts Collective Trust Funds — Domestic Equities $ 148,219 $ — $ 148,219 $ — Collective Trust Funds — International Equities 54,881 — 54,881 — Exchange Traded Funds — Fixed Income 236,513 236,513 — — Cash Held in Collective Trust Funds 6,412 — 6,412 — Total VEBA Trust Investments 446,025 236,513 209,512 — 401(h) Investments 54,921 14,105 37,907 2,909 Total Investments (including 401(h) Investments) $ 500,946 $ 250,618 $ 247,419 $ 2,909 Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (3,345 ) Total Other Post-Retirement Benefit Assets $ 497,601
Schedule Of Significant Unobservable Input Changes In Plan Assets	Other Post-Retirement Benefit Level 3 Assets (Thousands) VEBA Trust Investments Including 401(h) Investments Other Post-Retirement Benefit Investments Real Estate Balance at September 30, 2013 $ 55 $ 2,606 $ 2,661 Realized Gains/(Losses) (40 ) 4 (36 ) Unrealized Gains/(Losses) — 239 239 Purchases — 65 65 Sales (15 ) (5 ) (20 ) Balance at September 30, 2014 — 2,909 2,909 Realized Gains/(Losses) — 135 135 Unrealized Gains/(Losses) — 103 103 Purchases — 5 5 Sales — (1,267 ) (1,267 ) Balance at September 30, 2015 $ — $ 1,885 $ 1,885
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Schedule Of Fair Value Of Plan Assets	Total Fair Value Amounts at September 30, 2015 Level 1 Level 2 Level 3 Retirement Plan Investments Domestic Equities(1) $ 229,811 $ 170,166 $ 59,645 $ — International Equities(2) 96,478 — 96,478 — Global Equities(3) 112,802 — 112,802 — Domestic Fixed Income(4) 303,508 1,539 301,969 — International Fixed Income(5) 883 883 — — Global Fixed Income(6) 86,773 — 86,773 — Hedge Fund Investments 26,490 — — 26,490 Real Estate 4,724 — — 4,724 Cash and Cash Equivalents 27,723 — 27,723 — Total Retirement Plan Investments 889,192 172,588 685,390 31,214 401(h) Investments (53,686 ) (10,420 ) (41,381 ) (1,885 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 835,506 $ 162,168 $ 644,009 $ 29,329 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (636 ) Total Retirement Plan Assets $ 834,870 Total Fair Value Level 1 Level 2 Level 3 Retirement Plan Investments Domestic Equities(1) $ 268,649 $ 171,979 $ 96,670 $ — International Equities(2) 80,957 1,969 78,988 — Global Equities(3) 104,238 — 104,238 — Domestic Fixed Income(4) 299,494 63,187 236,307 — International Fixed Income(5) 1,240 508 732 — Global Fixed Income(6) 93,704 — 93,704 — Hedge Fund Investments 45,213 — — 45,213 Real Estate 3,792 — — 3,792 Cash and Cash Equivalents 33,544 — 33,544 — Total Retirement Plan Investments 930,831 237,643 644,183 49,005 401(h) Investments (54,921 ) (14,105 ) (37,907 ) (2,909 ) Total Retirement Plan Investments (excluding 401(h) Investments) $ 875,910 $ 223,538 $ 606,276 $ 46,096 Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (6,119 ) Total Retirement Plan Assets $ 869,791 (1) Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds. (2) International Equities include mostly collective trust funds and common stock. (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 include mostly collective trust funds and exchange traded funds. (6) Global Fixed Income securities are comprised of a collective trust fund.
Schedule Of Significant Unobservable Input Changes In Plan Assets	Retirement Plan Level 3 Assets (Thousands) Hedge Funds Real Estate Excluding 401(h) Investments Total Balance at September 30, 2013 $ 42,027 $ 2,723 $ (2,606 ) $ 42,144 Realized Gains/(Losses) — 62 (4 ) 58 Unrealized Gains/(Losses) 3,186 (10 ) (239 ) 2,937 Purchases — 1,111 (65 ) 1,046 Sales — (94 ) 5 (89 ) Balance at September 30, 2014 45,213 3,792 (2,909 ) 46,096 Realized Gains/(Losses) 2,284 — (135 ) 2,149 Unrealized Gains/(Losses) 317 871 (103 ) 1,085 Purchases — 82 (5 ) 77 Sales (21,324 ) (21 ) 1,267 (20,078 ) Balance at September 30, 2015 $ 26,490 $ 4,724 $ (1,885 ) $ 29,329

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Sep. 30, 2015
Segment Reporting [Abstract]
Segment Information By Segment	Year Ended September 30, 2015 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) $ 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 $ 2,549,374 $ 1,597,173 $ 447,968 $ 1,960,158 $ 88,193 $ 6,642,866 $ 77,350 $ (18,077 ) $ 6,702,139 Year Ended September 30, 2014 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) $ 804,096 $ 200,664 $ 673 $ 831,156 $ 271,993 $ 2,108,582 $ 3,532 $ 967 $ 2,113,081 Intersegment Revenues $ — $ 83,744 $ 69,937 $ 18,462 $ 1,159 $ 173,302 $ — $ (173,302 ) $ — Interest Income $ 1,909 $ 284 $ 120 $ 3,010 $ 173 $ 5,496 $ 106 $ (1,432 ) $ 4,170 Interest Expense $ 42,232 $ 26,428 $ 1,726 $ 27,693 $ 31 $ 98,110 $ 6 $ (3,839 ) $ 94,277 Depreciation, Depletion and Amortization $ 296,210 $ 36,642 $ 6,116 $ 43,594 $ 197 $ 382,759 $ 344 $ 678 $ 383,781 Income Tax Expense (Benefit) $ 81,370 $ 47,100 $ 23,636 $ 33,918 $ 3,761 $ 189,785 $ 822 $ (993 ) $ 189,614 Segment Profit: Net Income (Loss) $ 121,569 $ 77,559 $ 32,709 $ 64,059 $ 6,631 $ 302,527 $ 1,160 $ (4,274 ) $ 299,413 Expenditures for Additions to Long-Lived Assets $ 602,705 $ 139,821 $ 137,799 $ 88,810 $ 264 $ 969,399 $ 274 $ 234 $ 969,907 At September 30, 2014 (Thousands) Segment Assets $ 3,100,514 $ 1,367,181 $ 326,662 $ 1,862,850 $ 76,238 $ 6,733,445 $ 86,460 $ (91,865 ) $ 6,728,040 Year Ended September 30, 2013 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) $ 702,937 $ 178,184 $ 1,324 $ 730,319 $ 211,990 $ 1,824,754 $ 3,910 $ 887 $ 1,829,551 Intersegment Revenues $ — $ 89,424 $ 33,457 $ 16,020 $ 1,384 $ 140,285 $ — $ (140,285 ) $ — Interest Income $ 1,501 $ 193 $ 55 $ 3,417 $ 169 $ 5,335 $ 115 $ (1,115 ) $ 4,335 Interest Expense $ 39,745 $ 26,248 $ 2,283 $ 29,076 $ 36 $ 97,388 $ 2 $ (3,279 ) $ 94,111 Depreciation, Depletion and Amortization $ 243,431 $ 35,156 $ 3,945 $ 42,729 $ 123 $ 325,384 $ 577 $ 799 $ 326,760 Income Tax Expense (Benefit) $ 95,317 $ 38,626 $ 10,287 $ 31,065 $ 2,450 $ 177,745 $ 529 $ (5,516 ) $ 172,758 Segment Profit: Net Income (Loss) $ 115,391 $ 63,245 $ 13,321 $ 65,686 $ 4,589 $ 262,232 $ 894 $ (3,125 ) $ 260,001 Expenditures for Additions to Long-Lived Assets $ 533,129 $ 56,144 $ 54,792 $ 71,970 $ 595 $ 716,630 $ 307 $ 160 $ 717,097 At September 30, 2013 (Thousands) Segment Assets $ 2,746,233 $ 1,246,027 $ 203,323 $ 1,870,587 $ 67,267 $ 6,133,437 $ 95,793 $ (24,253 ) $ 6,204,977 (1) All Revenue from External Customers originated in the United States.
Schedule Of Long-Lived Assets, By Geographical Areas	Geographic Information At September 30 2015 2014 2013 (Thousands) Long-Lived Assets: United States $ 6,189,138 $ 6,350,708 $ 5,756,300

Quarterly Financial Data (Table

Quarterly Financial Data (Tables)	12 Months Ended
	Sep. 30, 2015
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) 2015 9/30/2015 $ 301,062 $ (326,731 ) $ (187,703 ) (1) $ (2.22 ) $ (2.22 ) 6/30/2015 $ 339,815 $ (489,214 ) $ (293,134 ) (2) $ (3.47 ) $ (3.44 ) 3/31/2015 $ 596,127 $ 44,331 $ 16,669 (3) $ 0.20 $ 0.20 12/31/2014 $ 523,909 $ 160,561 $ 84,741 $ 1.01 $ 1.00 2014 9/30/2014 $ 366,623 $ 102,004 $ 57,431 $ 0.68 $ 0.68 6/30/2014 $ 440,144 $ 127,013 $ 64,520 $ 0.77 $ 0.76 3/31/2014 $ 756,242 $ 180,075 $ 95,210 (4) $ 1.14 $ 1.12 12/31/2013 $ 550,072 $ 160,581 $ 82,252 $ 0.98 $ 0.97 (1) Includes a non-cash $417.2 million impairment charge ( $240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ( $5.2 million after tax) related to performance based restricted stock units. (2) Includes a non-cash $588.7 million impairment charge ( $339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (3) Includes a non-cash $120.3 million impairment charge ( $69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties. (4) Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.

Market For Common Stock And R32

Market For Common Stock And Related Shareholder Matters (Tables)	12 Months Ended
	Sep. 30, 2015
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, 2015 and 2014, are shown below: Price Range Dividends Declared Quarter Ended High Low 2015 9/30/2015 $ 59.39 $ 48.61 $ 0.395 6/30/2015 $ 66.07 $ 58.83 $ 0.395 3/31/2015 $ 70.19 $ 57.73 $ 0.385 12/31/2014 $ 72.21 $ 64.31 $ 0.385 2014 9/30/2014 $ 78.79 $ 65.29 $ 0.385 6/30/2014 $ 78.46 $ 68.50 $ 0.385 3/31/2014 $ 77.05 $ 68.12 $ 0.375 12/31/2013 $ 72.53 $ 65.23 $ 0.375

Supplementary Information For33

Supplementary Information For Oil And Gas Producing Activities (Tables)	12 Months Ended
	Sep. 30, 2015
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 2015 2014 (Thousands) Proved Properties(1) $ 4,473,721 $ 3,941,143 Unproved Properties 176,327 141,719 4,650,048 4,082,862 Less — Accumulated Depreciation, Depletion and Amortization 2,572,348 1,211,610 $ 2,077,700 $ 2,871,252 (1) Includes asset retirement costs of $113.3 million and $75.7 million at September 30, 2015 and 2014, respectively.
Summary Of Capitalized Costs Of Unproved Properties Excluded From Amortization	Following is a summary of costs excluded from amortization at September 30, 2015: Total as of September 30, 2015 Year Costs Incurred 2015 2014 2013 Prior (Thousands) Acquisition Costs $ 61,253 $ 2,777 $ 7,057 $ 905 $ 50,514 Development Costs 86,641 74,444 9,343 665 2,189 Exploration Costs 27,815 10,210 17,605 — — Capitalized Interest 618 303 315 — — $ 176,327 $ 87,734 $ 34,320 $ 1,570 $ 52,703
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 2015 2014 2013 (Thousands) United States Property Acquisition Costs: Proved $ 1,767 $ 18,213 $ 7,575 Unproved 19,998 7,884 9,274 Exploration Costs(1) 53,222 71,850 49,483 Development Costs(2) 454,605 490,164 460,554 Asset Retirement Costs 37,595 (4,946 ) 37,546 $ 567,187 $ 583,165 $ 564,432 (1) Amounts for 2015, 2014 and 2013 include capitalized interest of $0.4 million , $0.7 million and $0.4 million , respectively. (2) Amounts for 2015, 2014 and 2013 include capitalized interest of $0.5 million , $0.7 million and $0.7 million , respectively.
Results Of Operations For Producing Activities	Results of Operations for Producing Activities Year Ended September 30 2015 2014 2013 (Thousands, except per Mcfe amounts) United States Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $1 for all years presented and transfers to operations of $1,946, $2,145 and $612, respectively) $ 350,673 $ 515,080 $ 371,311 Oil, Condensate and Other Liquids 156,048 298,179 291,762 Total Operating Revenues(1) 506,721 813,259 663,073 Production/Lifting Costs 167,800 165,534 119,243 Franchise/Ad Valorem Taxes 20,167 20,765 17,200 Purchased Emission Allowance Expense 3,089 — — Accretion Expense 6,186 6,192 3,929 Depreciation, Depletion and Amortization ($1.49, $1.82 and $1.98 per Mcfe of production) 234,480 291,651 238,467 Impairment of Oil and Gas Producing Properties 1,126,257 — — Income Tax Expense (444,393 ) 140,484 120,431 Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ (606,865 ) $ 188,633 $ 163,803 (1) 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, 2012 925,411 63,023 988,434 Extensions and Discoveries 360,922 (1) 702 361,624 Revisions of Previous Estimates 53,038 112 53,150 Production (100,633 ) (2) (3,060 ) (103,693 ) September 30, 2013 1,238,738 60,777 1,299,515 Extensions and Discoveries 446,821 (1) — 446,821 Revisions of Previous Estimates 43,690 1,358 45,048 Production (139,097 ) (2) (3,210 ) (142,307 ) Purchases of Minerals in Place 33,986 — 33,986 Sale of Minerals in Place (76 ) (103 ) (179 ) 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 Proved Developed Reserves: September 30, 2012 544,560 59,923 604,483 September 30, 2013 807,055 59,862 866,917 September 30, 2014 1,119,901 57,907 1,177,808 September 30, 2015 1,267,498 49,346 1,316,844 Proved Undeveloped Reserves: September 30, 2012 380,851 3,100 383,951 September 30, 2013 431,683 915 432,598 September 30, 2014 504,161 915 505,076 September 30, 2015 825,284 — 825,284 (1) Extensions and discoveries include 355 Bcf (during 2013), 442 Bcf (during 2014) and 598 Bcf (during 2015), of Marcellus Shale gas in the Appalachian Region. (2) Production includes 93,999 MMcf (during 2013), 131,590 MMcf (during 2014) and 130,291 MMcf (during 2015), 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, 2012 306 42,556 42,862 Extensions and Discoveries — 2,443 2,443 Revisions of Previous Estimates 5 (881 ) (876 ) Production (28 ) (2,803 ) (2,831 ) September 30, 2013 283 41,315 41,598 Extensions and Discoveries 18 1,521 1,539 Revisions of Previous Estimates (17 ) (1,677 ) (1,694 ) Production (31 ) (3,005 ) (3,036 ) Purchases of Minerals in Place — 83 83 Sales of Minerals in Place — (13 ) (13 ) 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 Proved Developed Reserves: September 30, 2012 306 38,138 38,444 September 30, 2013 283 38,082 38,365 September 30, 2014 253 37,002 37,255 September 30, 2015 220 33,150 33,370 Proved Undeveloped Reserves: September 30, 2012 — 4,418 4,418 September 30, 2013 — 3,233 3,233 September 30, 2014 — 1,222 1,222 September 30, 2015 — 352 352
Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves	Year Ended September 30 2015 2014 2013 (Thousands) United States Future Cash Inflows $ 6,916,775 $ 10,001,545 $ 8,943,942 Less: Future Production Costs 2,854,142 2,795,657 2,334,393 Future Development Costs 761,922 790,033 749,876 Future Income Tax Expense at Applicable Statutory Rate 1,117,433 2,434,370 2,113,101 Future Net Cash Flows 2,183,278 3,981,485 3,746,572 Less: 10% Annual Discount for Estimated Timing of Cash Flows 860,244 1,914,607 1,780,206 Standardized Measure of Discounted Future Net Cash Flows $ 1,323,034 $ 2,066,878 $ 1,966,366
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 2015 2014 2013 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year $ 2,066,878 $ 1,966,366 $ 1,469,791 Sales, Net of Production Costs (318,753 ) (626,960 ) (526,630 ) Net Changes in Prices, Net of Production Costs (1,752,843 ) (38,723 ) 339,655 Extensions and Discoveries 266,159 381,008 390,255 Changes in Estimated Future Development Costs 164,510 68,731 6,117 Purchases of Minerals in Place — 34,705 — Sales of Minerals in Place (1 ) (691 ) — Previously Estimated Development Costs Incurred 161,833 179,502 148,535 Net Change in Income Taxes at Applicable Statutory Rate 545,442 (231,807 ) (130,574 ) Revisions of Previous Quantity Estimates (16,573 ) 55,184 34,864 Accretion of Discount and Other 206,382 279,563 234,353 Standardized Measure of Discounted Future Net Cash Flows at End of Year $ 1,323,034 $ 2,066,878 $ 1,966,366

Summary Of Significant Accoun34

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Summary Of Significant Accounting Policies [Line Items]
Full cost ceiling test discount factor	10.00%			10.00%
Impairment of Oil and Gas Producing Properties	$ 417,200	$ 588,700	$ 120,300	$ 1,126,257	$ 0	$ 0
Increase (decrease) estimated future net cash flows				194,500	(33,600)	$ 71,600
Goodwill	5,476			5,476	5,476
Prior service (cost) credit	(1,500)			(1,500)	200
Gas stored underground - current	34,252			34,252	39,422
Customer Advances	16,236			16,236	19,005
Customer Security Deposits	16,490			$ 16,490	$ 15,761
Antidilutive securities				709,063	1,007	181,418
Accumulated Losses [Member]
Summary Of Significant Accounting Policies [Line Items]
Accumulated losses	68,300			$ 68,300	$ 56,200
Unamortized Debt Expense [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulated Reacquisition of Debt Cost Weighted Average Amortization Period				4 years
Amount Exceeds LIFO Basis [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground - current	13,800			$ 13,800
LIFO Method [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground - current	$ 26,800			26,800
Impairment of Oil and Gas Producing Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred Income Tax Benefit				$ 476,100

Summary Of Significant Accoun35

Summary Of Significant Accounting Policies (Schedule Of Depreciable Plant By Segment) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Depreciable plant	$ 8,575,493	$ 7,789,756
Utility [Member]
Segment Reporting Information [Line Items]
Depreciable plant	1,888,489	1,833,104
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Depreciable plant	1,710,947	1,609,593
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciable plant	4,556,096	3,995,200
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Depreciable plant	3,494	3,366
Gathering [Member]
Segment Reporting Information [Line Items]
Depreciable plant	307,274	239,507
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Depreciable plant	$ 109,193	$ 108,986

Summary Of Significant Accoun36

Summary Of Significant Accounting Policies (Average Depreciation Depletion And Amortization Rates) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe	[1]	$ 1.52	$ 1.85	$ 2.02
Utility [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.60%	2.60%	2.60%
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		2.40%	2.40%	2.50%
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		6.10%	5.80%	3.90%
Gathering [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		4.00%	3.30%	3.70%
All Other And Corporate [Member]
Segment Reporting Information [Line Items]
Average depreciation, depletion and amortization rates		1.40%	0.90%	1.30%
Oil And Gas Producing Properties [Member]
Segment Reporting Information [Line Items]
Depreciation depletion and amortization rate per Mcfe		$ 1.49	$ 1.82	$ 1.98
[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 $1.49, $1.82 and $1.98 per Mcfe of production in 2015, 2014 and 2013, 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, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	$ (3,979)	$ (19,234)
Other Comprehensive Gains and Losses Before Reclassifications	198,491	1,710
Amounts Reclassified From Other Comprehensive Income (Loss)	(101,140)	13,545
Ending balance	93,372	(3,979)
Gains and Losses on Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	43,659	30,722
Other Comprehensive Gains and Losses Before Reclassifications	220,146	4,805
Amounts Reclassified From Other Comprehensive Income (Loss)	(106,608)	8,132
Ending balance	157,197	43,659
Gains And Losses On Securities Available For Sale [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	8,382	6,337
Other Comprehensive Gains and Losses Before Reclassifications	(2,039)	2,465
Amounts Reclassified From Other Comprehensive Income (Loss)	(374)	(420)
Ending balance	5,969	8,382
Funded Status of the Pension and Other Post-Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	(56,020)	(56,293)
Other Comprehensive Gains and Losses Before Reclassifications	(19,616)	(5,560)
Amounts Reclassified From Other Comprehensive Income (Loss)	5,842	5,833
Ending balance	$ (69,794)	$ (56,020)

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, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014		Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues		$ 301,062		$ 339,815		$ 596,127		$ 523,909	$ 366,623		$ 440,144	$ 756,242		$ 550,072	$ 1,760,913	$ 2,113,081	$ 1,829,551
Purchased Gas															(349,984)	(605,838)	(460,432)
Other Income															8,039	9,461	4,697
Income Before Income Taxes															(698,563)	489,027	432,759
Income Tax Expense															319,136	(189,614)	(172,758)
Net Income (Loss) Available for Common Stock		$ (187,703)	[1]	$ (293,134)	[2]	$ 16,669	[3]	$ 84,741	$ 57,431	[2]	$ 64,520	$ 95,210	[4]	$ 82,252	(379,427)	299,413	$ 260,001
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															176,327	(26,188)
Income Tax Expense															(75,187)	12,643
Net Income (Loss) Available for Common Stock															101,140	(13,545)
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															591	662
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]														109	131
Recognition of Net Actuarial Loss	[5]														(9,326)	(9,334)
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Income (Loss) [Member] | Commodity Contract [Member] | Gains and Losses on Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income (Loss) [Line Items]
Operating Revenues															180,069	(14,880)
Purchased Gas															$ 4,884	$ (2,767)
[1]	Includes a non-cash $417.2 million impairment charge ($240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ($5.2 million after tax) related to performance based restricted stock units.
[2]	Includes a non-cash $588.7 million impairment charge ($339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $120.3 million impairment charge ($69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.
[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, 2015	Sep. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Prepayments		$ 10,743	$ 10,079
Prepaid Property and Other Taxes		13,709	13,743
Fair Values of Firm Commitments		15,775	0
Regulatory Assets	[1]	20,438	22,719
Other Current Assets		60,665	54,752
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable		$ 0	$ 8,211
[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, 2015	Sep. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liability	$ 62,124	$ 51,817
Other Accruals and Current Liabilities	96,557	136,672
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	53,652	80,348
Regulatory Liabilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liability	5,346	18,072
Other Accruals [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	30,703	32,454
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	5,686	0
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	$ 1,170	$ 5,798

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at Beginning of Year	$ 117,713	$ 119,511	$ 119,246
Liabilities Incurred and Revisions of Estimates	38,150	(2,496)	(4,796)
Liabilities Settled	(6,825)	(6,955)	(1,744)
Accretion Expense	7,767	7,653	6,805
Balance at End of Year	$ 156,805	$ 117,713	$ 119,511

Regulatory Matters (Narrative)

Regulatory Matters (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Regulatory Matters [Line Items]
Authorized Increase In Distribution Corporation's Pipeline Replacement Spending	$ 8.2
Allowed Rate Of Return On Equity	9.10%
Rate proceeding refund provision pre tax		$ 7.5
Maximum [Member]
Regulatory Matters [Line Items]
Allowed Rate Of Return On Equity Range	10.50%
Minimum [Member]
Regulatory Matters [Line Items]
Allowed Rate Of Return On Equity Range	9.50%
Shareholder Allocation [Member] | 9.5 Percent To 10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings Sharing Mechanism Allocation Of Earnings	50.00%
Shareholder Allocation [Member] | Above10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings Sharing Mechanism Allocation Of Earnings	20.00%
Deferred For Benefit Of Customers [Member] | 9.5 Percent To 10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings Sharing Mechanism Allocation Of Earnings	50.00%
Deferred For Benefit Of Customers [Member] | Above10.5 Percent Rate Of Return On Equity [Member]
Regulatory Matters [Line Items]
Earnings Sharing Mechanism Allocation Of Earnings	80.00%
November 1, 2015 [Member] | Supply Corporation [Member]
Regulatory Matters [Line Items]
Reduction in Rates	2.00%
November 1, 2016 [Member] | Supply Corporation [Member]
Regulatory Matters [Line Items]
Reduction in Rates	2.00%

Regulatory Matters (Schedule Of

Regulatory Matters (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	$ 469,097	$ 413,387
Less: Amounts Included in Other Current Assets	[1]	(20,438)	(22,719)
Total Long-Term Regulatory Assets		278,227	224,436
Total Regulatory Liabilities		445,096	397,904
Less: Amounts Included in Current and Accrued Liabilities		(62,124)	(51,817)
Total Long-Term Regulatory Liabilities		108,617	81,152
Cost Of Removal Regulatory Liability [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		184,907	173,199
Taxes Refundable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		89,448	91,736
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		60,013	53,650
Amounts Payable To Customers [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities		56,778	33,745
Off-System Sales And Capacity Release Credits [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[2]	21,027	12,805
Other Accruals and Current Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Current and Accrued Liabilities		(5,346)	(5,267)
Other Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Liabilities	[3]	32,923	32,769
Total Long-Term Regulatory Liabilities		27,577	27,502
Non-Current Regulatory Liabilities [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Liabilities		382,972	346,087
Pension Costs Asset [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	202,781	164,804
Post-Retirement Benefit Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	34,217	17,128
Recoverable Future Taxes [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	168,214	163,485
Environmental Site Remediation Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	24,606	25,645
NYPSC Assessment [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[5]	13,916	12,730
Asset Retirement Obligations [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[4]	12,250	12,006
Unamortized Debt Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1]	2,218	2,747
Other Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Total Regulatory Assets	[1],[6]	10,895	14,842
Total Long-Term Regulatory Assets		4,373	4,853
Other Current Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Less: Amounts Included in Other Current Assets		(6,522)	(9,989)
Long-Term Regulatory Assets [Member]
Regulatory Assets And Liabilities [Line Items]
Total Long-Term Regulatory Assets	[1]	$ 448,659	$ 390,668
[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]	The September 30, 2015 amount is included in Other Regulatory Liabilities on the Consolidated Balance Sheet at September 30, 2015. The September 30, 2014 amount is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2014 since such amount is expected to be passed back to ratepayers in the next 12 months.
[3]	$5,346 and $5,267 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $27,577 and $27,502 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively.
[4]	Included in Other Regulatory Assets on the Consolidated Balance Sheets.
[5]	Amounts are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and September 30, 2014 since such amounts are expected to be recovered from ratepayers in the next 12 months.
[6]	$6,522 and $9,989 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $4,373 and $4,853 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2015 and 2014, respectively.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Taxes [Line Items]
Tax benefit recorded from exercise of stock options	$ 9,100	$ 4,600	$ 700
Tax benefit not realized due to tax loss carryforwards	32,800	34,200
Taxes Refundable to Customers	89,448	91,736
Recoverable Future Taxes	168,214	163,485
Tax Credit Carryforwards	54,000
Federal net operating loss, certain annual limitations	7,300
Federal net operating loss, excess tax deductions related to stock based compensation	87,000
Tax benefit from change in enacted rate	113,251	(26,272)	$ (37,569)
Deferred Income Taxes [Member]
Income Taxes [Line Items]
Taxes Refundable to Customers	89,400	91,700
Recoverable Future Taxes	168,200	163,500
Regulatory liabilities	52,600	52,600
Regulatory assets	88,700	$ 85,300
Pennsylvania [Member]
Income Taxes [Line Items]
Net operating loss	333,000
California [Member]
Income Taxes [Line Items]
Net operating loss	207,000
New York [Member]
Income Taxes [Line Items]
Net operating loss	96,000
Federal [Member]
Income Taxes [Line Items]
Net operating loss	343,000
State Tax Law Change [Member]
Income Taxes [Line Items]
Tax benefit from change in enacted rate	$ 2,800
New York [Member] | State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Corporate Tax Rate	7.10%
Tax Year 2016 [Member] | New York [Member] | State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Corporate Tax Rate	6.50%

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, 2015	Sep. 30, 2014	Sep. 30, 2013
Current Income Taxes [Abstract]
Federal	$ 25,064	$ 34,579	$ (632)
State	13,387	12,620	5,503
Deferred Income Taxes [Abstract]
Federal	(244,336)	116,143	130,318
State	(113,251)	26,272	37,569
Income Tax Expense	(319,136)	189,614	172,758
Deferred Investment Tax Credit	(414)	(434)	(426)
Total Income Taxes	(319,550)	189,180	172,332
Presented as Follows [Abstract]
Other Income	(414)	(434)	(426)
Income Tax Expense (Benefit)	$ (319,136)	$ 189,614	$ 172,758

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, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]
U.S. Income (Loss) Before Income Taxes	$ (698,977)	$ 488,593	$ 432,333
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 35%	(244,642)	171,008	151,317
State Income Taxes (Benefit)	(64,912)	25,280	27,997
Miscellaneous	(9,996)	(7,108)	(6,982)
Total Income Taxes	$ (319,550)	$ 189,180	$ 172,332
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, 2015	Sep. 30, 2014
Income Tax Disclosure [Abstract]
Property, Plant and Equipment	$ 1,291,718	$ 1,614,515
Pension and Other Post-Retirement Benefit Costs	141,032	113,248
Unrealized Hedging Gains	118,522	37,051
Other	51,230	50,884
Total Deferred Tax Liabilities	1,602,502	1,815,698
Pension and Other Post-Retirement Benefit Costs	(168,451)	(124,452)
Tax Loss and Credit Carryforwards	(185,681)	(171,423)
Other	(110,408)	(103,863)
Total Deferred Tax Assets	(464,540)	(399,738)
Total Net Deferred Income Taxes	1,137,962	1,415,960
Deferred Tax Liability/(Asset) - Current	(137,200)	(40,323)
Deferred Tax Liability - Non-Current	$ 1,275,162	$ 1,456,283

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of The Change In Unrecognized Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Balance at Beginning of Year	$ 3,147	$ 2,001	$ 11,170
Additions for Tax Positions Related to Current Year	0	0	700
Additions for Tax Positions of Prior Years	2,504	2,447	164
Reductions for Tax Positions of Prior Years	(566)	(1,301)	(10,033)
Balance at End of Year	$ 5,085	$ 3,147	$ 2,001

Capitalization And Short-Term49

Capitalization And Short-Term Borrowings (Narrative) (Details)	Jun. 25, 2015USD ($)	Sep. 30, 2015USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / sharesshares	Sep. 30, 2014USD ($)$ / sharesshares	Sep. 30, 2013USD ($)$ / sharesshares
Debt Instrument [Line Items]
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan | shares			124,214
Common stock issued for 401(k) plans | shares			92,887
Common stock shares issued due to stock option and SARs exercises | shares			(175,500)
Shares tendered | shares			50,467
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			$ 2,100,000	$ 10,500,000	$ 11,500,000
Tax benefit related to stock-based compensation expense			900,000	4,300,000	4,600,000
Capitalized stock-based compensation costs			100,000	100,000	100,000
Tax benefit realized from exercise of stock-based compensation			7,700,000	3,100,000	3,600,000
Tax benefit recorded from exercise of stock-based compensation			9,100,000	4,600,000	700,000
Reversal of Stock-Based Compensation Expense		$ 8,000,000	8,000,000
Carrying Amount		2,084,009,000	$ 2,084,009,000	1,637,443,000
Percentage of Long-Term Debt issued under 1974 Indenture			4.70%
Net proceeds from issuance of long-term debt			$ 444,635,000	0	495,415,000
Principal amounts of long-term debt maturing in 2016		0	0
Principal amounts of long-term debt maturing in 2017		0	0
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 after 2020		1,549,000,000	1,549,000,000
Commercial paper available		500,000,000	500,000,000
Line of Credit Facility, Maximum Borrowing Capacity		750,000,000	750,000,000
Commercial paper, outstanding		0	$ 0	85,600,000
Line of Credit Facility, Expiration Date			Dec. 5, 2019
Short-term notes payable outstanding		0	$ 0	0
Committed credit facility debt to capitalization ratio			0.65
Debt to capitalization ratio			0.51
Additional borrowing		$ 1,670,000,000	$ 1,670,000,000
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			206,523
Stock Options [Member]
Debt Instrument [Line Items]
Options, exercises in period, total intrinsic value			$ 5,100,000	13,700,000	11,600,000
Proceeds from Stock Options Exercised			$ 5,600,000	$ 7,400,000	$ 2,600,000
Stock Appreciation Rights (SARs) [Member]
Debt Instrument [Line Items]
Number of Shares Forfeited | shares			0
Number of Shares Granted | shares			0	0	412,970
Weighted Average Fair Value per Award Granted | $ / shares					$ 10.66
Total intrinsic value of SAR's exercised			$ 2,000,000	$ 8,400,000	$ 800,000
Equity instruments other than options, vested in period, total fair value			1,700,000	$ 3,800,000	$ 3,600,000
Unrecognized compensation expense		100,000	$ 100,000
Unrecognized compensation expense recognized weighted average period			6 months
Stock Appreciation Right [Member]
Debt Instrument [Line Items]
Number of Awards Vested | shares			157,386	323,188	287,168
Restricted Share Awards [Member]
Debt Instrument [Line Items]
Number of Shares Forfeited | shares			0
Number of Shares Granted | shares			0	0	0
Weighted Average Fair Value per Award Granted | $ / shares			$ 0
Number of Awards Vested | shares			29,518
Unrecognized compensation expense		900,000	$ 900,000
Unrecognized compensation expense recognized weighted average period			2 years 4 months 20 days
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Number of Shares Forfeited | shares			7,980
Number of Shares Granted | shares			88,899	82,151	44,200
Weighted Average Fair Value per Award Granted | $ / shares			$ 64.04	$ 65.24	$ 51.11
Number of Awards Vested | shares			48,490
Unrecognized compensation expense		5,700,000	$ 5,700,000
Unrecognized compensation expense recognized weighted average period			1 year 6 months 30 days
Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Number of Shares Forfeited | shares			389
Number of Shares Granted | shares			0	0	255,604
Weighted Average Fair Value per Award Granted | $ / shares			$ 0		$ 49.51
Number of Awards Vested | shares			0
Unrecognized compensation expense		0	$ 0
Performance Shares [Member]
Debt Instrument [Line Items]
Number of Shares Forfeited | shares			768
Number of Shares Granted | shares			107,044	116,090	0
Weighted Average Fair Value per Award Granted | $ / shares			$ 65.26	$ 67.16
Number of Awards Vested | shares			0
Unrecognized compensation expense		7,000,000	$ 7,000,000
Unrecognized compensation expense recognized weighted average period			1 year 3 months 19 days
Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Common stock issued | shares			48,490
5.20% Notes Due July 2025 [Member]
Debt Instrument [Line Items]
Long-term debt, face value	$ 450,000,000
Long-term debt, interest rate	5.20%
Net proceeds from issuance of long-term debt	$ 444,600,000
Indenture From 1974 [Member]
Debt Instrument [Line Items]
Carrying Amount		99,000,000	$ 99,000,000
Commercial Paper [Member]
Debt Instrument [Line Items]
Weighted average interest rate				0.31%
2016 [Member] | Restricted Share Awards [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			5,000
2016 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			77,837
2017 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			76,156
2017 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			97,698
2018 [Member] | Restricted Share Awards [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			35,000
2018 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			50,600
2018 [Member] | Performance Shares [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			107,044
2019 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			21,245
2020 [Member] | Non-Performance Based Restricted Stock Units (RSUs) [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			11,110
2021 [Member] | Restricted Share Awards [Member]
Debt Instrument [Line Items]
Non-vested stock-based compensation lapse | shares			20,000
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued | shares			15,516
Amended & Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		750,000,000	$ 750,000,000
Second 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

Capitalization And Short-Term50

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, 2015		Jun. 30, 2015	[2]	Mar. 31, 2015	[3]	Dec. 31, 2014	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	[4]	Dec. 31, 2013	Sep. 30, 2015		Sep. 30, 2014	Sep. 30, 2013
Schedule of Capitalization [Line Items]
Beginning balance (shares)								84,157,220							84,157,220
Beginning balance								$ 716,144							$ 716,144
Balance at Beginning of Year								1,614,361						$ 1,442,617	1,614,361		$ 1,442,617	$ 1,306,284
Beginning balance								(3,979)						(19,234)	(3,979)		(19,234)
Net Income (Loss) Available for Common Stock		$ (187,703)	[1]	$ (293,134)		$ 16,669		$ 84,741	$ 57,431	[2]	$ 64,520	$ 95,210		$ 82,252	(379,427)		299,413	260,001
Dividends Declared on Common Stock															(131,734)		(127,669)	(123,668)
Other Comprehensive Income, Net of Tax															97,351		15,255	79,786
Share-Based Payment Expense															$ 2,100		$ 10,500	11,500
Ending balance (Shares)		84,594,383							84,157,220						84,594,383		84,157,220
Ending balance		$ 744,274							$ 716,144						$ 744,274		$ 716,144
Balance at End of Year		1,103,200							1,614,361						1,103,200		1,614,361	1,442,617
Ending balance		93,372							$ (3,979)						93,372		(3,979)	(19,234)
Tax benefits related to stock-based compensation															$ 9,064		$ 4,641	$ 675
Dividend per share															$ 1.56		$ 1.52	$ 1.48
Accumulated earnings free from limitations		$ 959,000													$ 959,000
Common Stock [Member]
Schedule of Capitalization [Line Items]
Beginning balance (shares)								84,157,000						83,662,000	84,157,000		83,662,000	83,330,000
Beginning balance (value)								$ 84,157						$ 83,662	$ 84,157		$ 83,662	$ 83,330
Common Stock Issued Under Stock and Benefit Plans (Shares)	[5]														437,000		495,000	332,000
Common Stock Issued Under Stock and Benefit Plans (Value)	[5]														$ 437		$ 495	$ 332
Ending balance (Shares)		84,594,000							84,157,000						84,594,000		84,157,000	83,662,000
Ending balance (Value)		$ 84,594							$ 84,157						$ 84,594		$ 84,157	$ 83,662
Paid In Capital [Member]
Schedule of Capitalization [Line Items]
Beginning balance								716,144						687,684	716,144		687,684	669,501
Share-Based Payment Expense	[6]														2,207		10,654	11,537
Common Stock Issued Under Stock and Benefit Plans (Value)	[5]														25,923		17,806	6,646
Ending balance		744,274							716,144						744,274		716,144	687,684
Earnings Reinvested In The Business [Member]
Schedule of Capitalization [Line Items]
Balance at Beginning of Year								1,614,361						1,442,617	1,614,361		1,442,617	1,306,284
Net Income (Loss) Available for Common Stock															(379,427)		299,413	260,001
Dividends Declared on Common Stock															(131,734)		(127,669)	(123,668)
Balance at End of Year		1,103,200	[7]						1,614,361						1,103,200	[7]	1,614,361	1,442,617
Accumulated Other Comprehensive Income (Loss) [Member]
Schedule of Capitalization [Line Items]
Beginning balance								$ (3,979)						$ (19,234)	(3,979)		(19,234)	(99,020)
Other Comprehensive Income, Net of Tax															97,351		15,255	79,786
Ending balance		$ 93,372							$ (3,979)						$ 93,372		$ (3,979)	$ (19,234)
[1]	Includes a non-cash $417.2 million impairment charge ($240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ($5.2 million after tax) related to performance based restricted stock units.
[2]	Includes a non-cash $588.7 million impairment charge ($339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $120.3 million impairment charge ($69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.
[5]	Paid in Capital includes tax benefits of $9.1 million, $4.6 million and $0.7 million for September 30, 2015, 2014 and 2013, 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, 2015, $959.0 million of accumulated earnings was free of such limitations.

Capitalization And Short-Term51

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, 2015	Sep. 30, 2014	Sep. 30, 2013
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		482,000
Number of Shares Granted		0
Number of Shares Exercised		(175,500)
Number of Shares Forfeited		0
Number of Shares Outstanding, End of Year		306,500	482,000
Number of Option shares exercisable		306,500
Number of Shares Subject to Option, Option shares available for future grant	[1]	3,184,675
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 36.71
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		34.94
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Outstanding End of Year		37.73	$ 36.71
Weighted Average Exercise Price, Option shares exercisable		$ 37.73
Weighted Average Remaining Contractual Life, Outstanding		11 months 7 days
Weighted Average Remaining Contractual Life, Option shares exercisable		11 months 7 days
Aggregate Intrinsic Value Outstanding		$ 3,754
Aggregate Intrinsic Value, Option Shares exercisable		$ 3,754
Performance Shares [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		98,466
Number of Shares Granted		107,044	116,090	0
Number of Awards Vested		0
Number of Shares Forfeited		(768)
Number of Shares Outstanding, End of Year		204,742	98,466
Weighted Average Fair Value per Award, Beginning of Year		$ 67.16
Weighted Average Fair Value per Award Granted		65.26	$ 67.16
Weighted Average Fair Value per Award Vested		0
Weighted Average Fair Value per Award Forfeited		67.16
Weighted Average Fair Value per Award, End of Year		$ 66.17	$ 67.16
Stock Appreciation Rights (SARs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year		1,793,482
Number of Shares Granted		0	0	412,970
Number of Shares Exercised		(60,698)
Number of Shares Forfeited		0
Number of Shares Outstanding, End of Year		1,732,784	1,793,482
Number of SARs exercisable		1,614,702
Weighted Average Exercise Price, Outstanding Beginning of Year		$ 48.11
Weighted Average Exercise Price, Granted		0
Weighted Average Exercise Price, Exercised		31.29
Weighted Average Exercise Price, Forfeited		0
Weighted Average Exercise Price, Outstanding End of Year		48.70	$ 48.11
Weighted Average Exercise Price, SARs exercisable		$ 48.36
Weighted Average Remaining Contractual Life, Outstanding		4 years 11 months 22 days
Weighted Average Remaining Contractual Life, SARs exercisable		4 years 9 months 25 days
Aggregate Intrinsic Value Outstanding		$ 2,224
Aggregate Intrinsic Value, SARs exercisable		$ 2,621
Weighted Average Fair Value per Award Granted				$ 10.66
[1]	Includes shares available for SARs, restricted stock and performance share grants.

Capitalization And Short-Term52

Capitalization And Short-Term Borrowings (Schedule Of Share-Based Compensation For Restricted Stock Units) (Details) - $ / shares	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Restricted Share Awards [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year	89,518
Number of Shares Granted	0	0	0
Number of Awards Vested	(29,518)
Number of Shares Forfeited	0
Number of Shares Outstanding, End of Year	60,000	89,518
Weighted Average Fair Value per Award, Beginning of Year	$ 49.05
Weighted Average Fair Value per Award Granted	0
Weighted Average Fair Value per Award Vested	52.14
Weighted Average Fair Value per Award Forfeited	0
Weighted Average Fair Value per Award, End of Year	$ 47.53	$ 49.05
Non-Performance Based Restricted Stock Units (RSUs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year	204,519
Number of Shares Granted	88,899	82,151	44,200
Number of Awards Vested	(48,490)
Number of Shares Forfeited	(7,980)
Number of Shares Outstanding, End of Year	236,948	204,519
Weighted Average Fair Value per Award, Beginning of Year	$ 56.36
Weighted Average Fair Value per Award Granted	64.04	$ 65.24	$ 51.11
Weighted Average Fair Value per Award Vested	57.17
Weighted Average Fair Value per Award Forfeited	57.38
Weighted Average Fair Value per Award, End of Year	$ 59.04	$ 56.36
Performance Based Restricted Stock Units (RSUs) [Member]
Schedule of Capitalization [Line Items]
Number of Shares Outstanding, Beginning of Year	233,876
Number of Shares Granted	0	0	255,604
Number of Awards Vested	0
Number of Shares Forfeited	(389)
Number of Shares Outstanding, End of Year	233,487	233,876
Weighted Average Fair Value per Award, Beginning of Year	$ 49.61
Weighted Average Fair Value per Award Granted	0		$ 49.51
Weighted Average Fair Value per Award Vested	0
Weighted Average Fair Value per Award Forfeited	48.49
Weighted Average Fair Value per Award, End of Year	$ 49.61	$ 49.61

Capitalization And Short-Term53

Capitalization And Short-Term Borrowings (Weighted Average Assumptions Used In Estimating Fair Value) (Details)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk Free Interest Rate	1.01%	0.62%
Remaining Term at Date of Grant (Years)	2 years 9 months 12 days	2 years 9 months 12 days
Expected Volatility Rate	20.10%	28.30%
Stock Appreciation Rights (SARs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk Free Interest Rate			1.55%
Expected Life (Years)			8 years 3 months
Expected Volatility Rate			25.61%
Expected Dividend Yield (Quarterly)			0.69%

Capitalization And Short-Term54

Capitalization And Short-Term Borrowings (Schedule Of Long-Term Debt) (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
Debt Instrument [Line Items]
Total Long-Term Debt		$ 2,099,000	$ 1,649,000
Less Unamortized Discount and Debt Issuance Costs		14,991	11,557
Less Current Portion	[1]	0	0
Long-term Debt, Net of Unamortized Discount and Debt Issuance Costs		$ 2,084,009	1,637,443
7.4% Due March 2023 To June 2025 [Member]
Debt Instrument [Line Items]
Debt interest rate, minimum		7.40%
Medium-Term Notes	[2]	$ 99,000	$ 99,000
3.75% To 8.75% Due April 2018 To July 2025 [Member]
Debt Instrument [Line Items]
Debt interest rate, minimum		3.75%	3.75%
Debt interest rate, maximum		8.75%	8.75%
Notes	[2],[3]	$ 2,000,000	$ 1,550,000
Percentage of principal amount		101.00%	101.00%
[1]	None of the Company’s long-term debt at September 30, 2015 and 2014 will mature within the following twelve-month period.
[2]	The Medium-Term Notes and Notes are unsecured.
[3]	The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	[1]	$ 11,124,000	$ 2,734,000
Assumed 12 month Midway Sunset Oil comparison to NYMEX		91.80%
Assumed 12 month minimum Midway Sunset Oil comparison to NYMEX		87.80%
Assumed 12 month maximum Midway Sunset Oil comparison to NYMEX		94.60%
Fair value measured on recurring basis, net	[1]	$ 411,263,000	140,790,000
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 1 or Level 2 Transfers		0	0
Sales of Derivative Financial Instruments		0	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		11,124,000	2,734,000
Fair value measured on recurring basis, net		142,073,000	68,994,000
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		11,100,000	2,700,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		0	0
Fair value measured on recurring basis, net		$ 1,791,000	$ 1,368,000
Lower [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Midway Sunset Oil Comparison to NYMEX Sensitivity percentage points		10.00%
Lower [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of crude oil price swap sensitivity		$ 200,000
Higher [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Midway Sunset Oil Comparison to NYMEX Sensitivity percentage points		10.00%
Higher [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of crude oil price swap sensitivity		$ (200,000)
[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.

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measures Of Assets And Liabilities) (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 92,196	$ 23,794
Hedging Collateral Deposits	[1]	11,124	2,734
Total Assets	[1]	421,339	141,549
Total Liabilities	[1]	10,076	759
Total Net Assets/(Liabilities)	[1]	411,263	140,790
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0	738
Derivative Liability	[1]	8,903	687
Over Counter Swaps Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	273,318	71,868
Derivative Liability	[1]	1,173	72
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(2,955)
Derivative Liability		0
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	34,884	35,331
Fixed Income Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	8,004
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	4,318	6,629
Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	450	455
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		92,196	23,794
Hedging Collateral Deposits		11,124	2,734
Total Assets		157,349	71,668
Total Liabilities		15,276	2,674
Total Net Assets/(Liabilities)		142,073	68,994
Fair Value, Inputs, Level 1 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		6,373	2,725
Derivative Liability		15,276	2,674
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
Derivative Liability		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		34,884	35,331
Fair Value, Inputs, Level 1 [Member] | Fixed Income Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		8,004
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		4,318	6,629
Fair Value, Inputs, Level 1 [Member] | Other Common Stock [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		450	455
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		272,335	75,951
Total Liabilities		4,936	5,523
Total Net Assets/(Liabilities)		267,399	70,428
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		272,335	75,951
Derivative Liability		1,981	5,523
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0
Derivative Liability		2,955
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 Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		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 2 [Member] | Other Common Stock [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		1,791	1,368
Total Liabilities		0	0
Total Net Assets/(Liabilities)		1,791	1,368
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		1,791	1,368
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
Derivative Liability		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 Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		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
Fair Value, Inputs, Level 3 [Member] | Other Common Stock [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]	(10,136)	(7,438)
Total Liabilities	[1]	(10,136)	(7,438)
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]	(6,373)	(1,987)
Derivative Liability	[1]	(6,373)	(1,987)
Netting Adjustments [Member] | Over Counter Swaps Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(808)	(5,451)
Derivative Liability	[1]	(808)	(5,451)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(2,955)
Derivative Liability		(2,955)
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 Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	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
Netting Adjustments [Member] | Other Common Stock [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.

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Measurements Using Unobservable Inputs (Level 3)) (Details) - Derivative Financial Instruments [Member] - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015		Sep. 30, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Balance, Beginning of Year	[1]	$ 1,368		$ (5,190)
Total Gains/Losses, Realized and Included in Earnings	[1]	(12,738)	[2]	2,217	[3]
Total Gains/Losses, Unrealized and Included in Other Comprehensive Income (Loss)	[1]	13,161		4,341
Transfer In/(Out) of Level 3	[1]	0		0
Balance, End of Year	[1]	$ 1,791		$ 1,368
[1]	Derivative Financial Instruments are shown on a net basis.
[2]	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2015.
[3]	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the year ended September 30, 2014.

Financial Instruments (Narrativ

Financial Instruments (Narrative) (Details)		12 Months Ended
		Sep. 30, 2015USD ($)counterpartyMMcfbbl	Sep. 30, 2014USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Cash Surrender Value of Life Insurance		$ 45,300,000	$ 44,400,000
Net hedging gains (losses) in accumulated other comprehensive income (loss)		272,200,000
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)		157,200,000
Pre-tax Net hedging gains (losses) reclassified within twelve months		168,100,000
After tax Net hedging gains (losses) reclassified within twelve months		$ 97,100,000
Number of counterparties in which the company holds over-the-counter swap positions | counterparty		16
Number of counterparties in net gain position | counterparty		15
Collateral Received from Counterparties by the Company		$ 29,700,000
Fair market value of derivative asset with a credit-risk related contingency		174,600,000
Hedging collateral deposits	[1]	11,124,000	2,734,000
Equity Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		34,900,000	35,300,000
Gross unrealized gain		6,500,000	8,400,000
Fixed Income Funds [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		8,000,000
Insurance Company Stock [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair value		4,300,000	6,600,000
Gross unrealized gain		2,600,000	$ 4,500,000
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount		58,000,000
Over-The-Counter Swap Position [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Credit risk exposure per counterparty		18,000,000
Maximum credit risk exposure per counterparty		50,500,000
Hedging collateral deposits		$ 0
Over-The-Counter Swap Position [Member] | Credit Risk Related Contingency Feature [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties with a common credit-risk related contingency | counterparty		13
Exchange-Traded Futures Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedging collateral deposits		$ 11,100,000
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		17,900
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		180,500
Cash Flow Hedges Short Position [Member] | Crude Oil Bbls [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivative, crude oil | bbl		2,196,000
Cash Flow Hedges Long Position [Member] | Natural Gas MMCf [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas | MMcf		2,800
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Financial Instruments (Long-Ter

Financial Instruments (Long-Term Debt) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,084,009	$ 1,637,443
Fair Value	$ 2,129,558	$ 1,775,715

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, 2015	Sep. 30, 2014	Sep. 30, 2013
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)	$ 381,018	$ 5,334	$ 91,790
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)	184,953	(17,647)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	3,563	624
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)	377,957	9,763
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)	180,069	(14,880)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	3,563	624
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)	6,016	(4,429)
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)	4,884	(2,767)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0	0
Foreign Currency Contracts [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)	(2,955)	0
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)	0	0
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$ 0	$ 0

Financial Instruments (Schedu61

Financial Instruments (Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships) (Details) $ in Thousands	12 Months Ended
	Sep. 30, 2015USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	$ (13,962)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	13,962
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(13,944)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	13,944
Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(18)
Amount of Gain or (Loss) on Hedged Item Recognized in the Consolidated Statement of Income	$ 18

Retirement Plan And Other Pos62

Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2012
Defined Benefit Plan Disclosure [Line Items]
Decrease to accumulated other comprehensive income	$ (169,919,000)	$ (27,105,000)	$ (132,024,000)
Expected future benefit payments in year one	61,100,000
Expected future benefit payments in year two	62,100,000
Expected future benefit payments in year three	63,000,000
Expected future benefit payments in year four	63,700,000
Expected future benefit payments in year five	64,400,000
Expected future benefit payments in five years thereafter	332,100,000
Effect of one percentage point increase on accumulated postretirement benefit obligation	53,900,000
Effect of one percentage point increase on service and interest cost components	2,900,000
Effect of one percentage point decrease on accumulated postretirement benefit obligation	45,200,000
Effect of one percentage point decrease on service and interest cost components	2,400,000
Benefit assets transferred	0	0
Benefit assets transferred in/out of Level 3	0	0
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	37,700,000	39,955,000	37,606,000
Accumulated benefit obligation	968,984,000	940,068,000	886,942,000
Benefit obligation	$ 1,026,190,000	$ 999,499,000	$ 946,305,000	$ 1,070,744,000
Discount rate	4.25%	4.25%	4.75%
Rate of compensation increase	4.75%	4.75%	4.75%
Employer Contributions	$ 36,200,000	$ 33,500,000	$ 54,000,000
Expected long term rate of return on plan assets	7.50%	8.00%	8.00%
Retirement Plan [Member] | Actuarial Experience [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ (800,000)
Retirement Plan [Member] | Discount Rate Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	24,200,000	$ 53,700,000	$ (147,900,000)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	10,446,000	10,593,000	21,651,000
Benefit obligation	$ 464,987,000	$ 465,583,000	$ 460,634,000	$ 561,263,000
Discount rate	4.50%	4.25%	4.75%
Rate of compensation increase	4.75%	4.75%	4.75%
Employer Contributions	$ 2,161,000	$ 2,115,000	$ 18,160,000
Expected future benefit payments in year one	25,728,000
Expected future benefit payments in year two	26,942,000
Expected future benefit payments in year three	28,059,000
Expected future benefit payments in year four	29,038,000
Expected future benefit payments in year five	30,079,000
Expected future benefit payments in five years thereafter	$ 161,958,000
Expected long term rate of return on plan assets	7.00%	8.00%	8.00%
Other Post-Retirement Benefit Plans [Member] | Actuarial Experience [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	$ 12,800,000	$ (25,300,000)	$ (28,600,000)
Other Post-Retirement Benefit Plans [Member] | Discount Rate Change [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (decrease) in benefit obligation	(14,300,000)	26,400,000	(75,900,000)
Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net periodic benefit cost	7,000,000	7,500,000	9,600,000
Accumulated benefit obligation	66,000,000	65,700,000	57,200,000
Benefit obligation	$ 85,800,000	$ 85,500,000	$ 77,100,000
Discount rate	3.50%	3.50%	3.75%
Rate of compensation increase	7.75%	7.50%	7.75%
VEBA Trusts And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	$ 2,000,000
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.25%
Other Than Veba Trust And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer Contributions	$ 200,000
Non-Qualified Benefit Plans, Other Post-Retirement Benefit Plan And Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase in other regulatory assets	76,700,000
Decrease to accumulated other comprehensive income	$ 22,300,000
Equity Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation, minimum	40.00%
Target allocation, maximum	60.00%
Fixed Income Funds [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation, minimum	40.00%
Target allocation, maximum	60.00%
Other Securities [Member] | Retirement Plan and Veba Trusts And 401H Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Target allocation, minimum	0.00%
Target allocation, maximum	15.00%
Effective Fiscal 2016 [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	7.25%
Effective Fiscal 2016 [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long term rate of return on plan assets	6.75%
Minimum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	$ 5,000,000
Minimum [Member] | VEBA Trusts And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	2,000,000
Maximum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	10,000,000
Maximum [Member] | VEBA Trusts And 401(h) Accounts [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future employer contributions in next fiscal year	5,000,000
Other Accruals And Current Liabilities [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	4,500,000	$ 6,600,000
Non-Current [Member] | Non-Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation	81,300,000	78,900,000
Retirement Savings Account [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	2,300,000	1,900,000	$ 1,200,000
Tax-Deferred Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Costs Recognized	$ 5,800,000	$ 5,200,000	$ 4,400,000

Retirement Plan And Other Pos63

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, 2015	Sep. 30, 2014	Sep. 30, 2013
Defined Benefit Plan Disclosure [Line Items]
Non-Current Assets		$ 24,459	$ 36,512
Amortization period		10 years
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation at Beginning of Period		$ 999,499	946,305	$ 1,070,744
Service Cost		12,047	11,987	15,846
Interest Cost		41,217	43,574	36,498
Plan Participants' Contributions		0	0	0
Retiree Drug Subsidy Receipts		0	0	0
Amendments	[1]	7,752	0	0
Actuarial (Gain) Loss		23,426	53,887	(121,631)
Benefits Paid		(57,751)	(56,254)	(55,152)
Benefit Obligation at End of Period		1,026,190	999,499	946,305
Fair Value of Assets at Beginning of Period		869,791	799,307	701,676
Actual Return on Plan Assets		(13,370)	93,238	98,783
Employer Contributions		36,200	33,500	54,000
Fair Value of Assets at End of Period		834,870	869,791	799,307
Net Amount Recognized at End of Period (Funded Status)		(191,320)	(129,708)	(146,998)
Non-Current Liabilities		(191,320)	(129,708)	(146,998)
Non-Current Assets		0	0	0
Accumulated Benefit Obligation		$ 968,984	$ 940,068	$ 886,942
Discount Rate		4.25%	4.25%	4.75%
Rate of Compensation Increase		4.75%	4.75%	4.75%
Expected Return on Plan Assets		$ (59,615)	$ (59,974)	$ (57,346)
Amortization of Prior Service Cost (Credit)		183	210	238
Amortization of Transition Amount		0	0	0
Recognition of Actuarial Loss	[2]	36,129	36,007	52,776
Net Amortization and Deferral for Regulatory Purposes		7,739	8,151	(10,406)
Net Periodic Benefit Cost		$ 37,700	$ 39,955	$ 37,606
Discount Rate		4.25%	4.75%	3.50%
Expected Return on Plan Assets		7.50%	8.00%	8.00%
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		$ 465,583	$ 460,634	$ 561,263
Service Cost		2,693	2,939	4,705
Interest Cost		19,285	21,308	19,212
Plan Participants' Contributions		2,242	2,265	2,141
Retiree Drug Subsidy Receipts		1,338	1,419	1,526
Amendments	[1]	0	0	0
Actuarial (Gain) Loss		(1,575)	1,087	(104,455)
Benefits Paid		(24,579)	(24,069)	(23,758)
Benefit Obligation at End of Period		464,987	465,583	460,634
Fair Value of Assets at Beginning of Period		497,601	472,392	414,134
Actual Return on Plan Assets		534	44,898	61,715
Employer Contributions		2,161	2,115	18,160
Fair Value of Assets at End of Period		477,959	497,601	472,392
Net Amount Recognized at End of Period (Funded Status)		12,972	32,018	11,758
Non-Current Liabilities		(11,487)	(4,494)	(11,016)
Non-Current Assets		$ 24,459	$ 36,512	$ 22,774
Discount Rate		4.50%	4.25%	4.75%
Rate of Compensation Increase		4.75%	4.75%	4.75%
Expected Return on Plan Assets		$ (34,089)	$ (37,424)	$ (32,872)
Amortization of Prior Service Cost (Credit)		(1,913)	(2,138)	(2,138)
Amortization of Transition Amount		0	0	8
Recognition of Actuarial Loss	[2]	4,148	2,645	20,892
Net Amortization and Deferral for Regulatory Purposes		20,322	23,263	11,844
Net Periodic Benefit Cost		$ 10,446	$ 10,593	$ 21,651
Discount Rate		4.25%	4.75%	3.50%
Expected Return on Plan Assets		7.00%	8.00%	8.00%
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 Pos64

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, 2015USD ($)	[1]
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	$ (287,180)
Prior Service (Cost) Credit	(8,425)
Net Amount Recognized	(295,605)
Decrease (Increase) in Actuarial Loss, excluding amortization	(96,412)	[2]
Change due to Amortization of Actuarial Loss	36,129
Prior Service (Cost) Credit	(7,569)
Net Change	(67,852)
Net Actuarial Loss	(32,248)
Prior Service (Cost) Credit	(1,234)
Net Amount Expected to be Recognized	(33,482)
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(59,914)
Prior Service (Cost) Credit	5,027
Net Amount Recognized	(54,887)
Decrease (Increase) in Actuarial Loss, excluding amortization	(31,980)	[2]
Change due to Amortization of Actuarial Loss	4,148
Prior Service (Cost) Credit	(1,913)
Net Change	(29,745)
Net Actuarial Loss	(5,530)
Prior Service (Cost) Credit	912
Net Amount Expected to be Recognized	(4,618)
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Net Actuarial Loss	(24,929)
Prior Service (Cost) Credit	0
Net Amount Recognized	(24,929)
Decrease (Increase) in Actuarial Loss, excluding amortization	(4,321)	[2]
Change due to Amortization of Actuarial Loss	2,925
Prior Service (Cost) Credit	0
Net Change	(1,396)
Net Actuarial Loss	(3,295)
Prior Service (Cost) Credit	0
Net Amount Expected to be Recognized	$ (3,295)
[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 Pos65

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Expected Benefit Payments) (Details) $ in Thousands	Sep. 30, 2015USD ($)
Defined Benefit Plan Disclosure [Line Items]
2016 - Benefit Payments	$ 61,100
2017 - Benefit Payments	62,100
2018 - Benefit Payments	63,000
2019 - Benefit Payments	63,700
2020 - Benefit Payments	64,400
2021 through 2025 - Benefit Payments	332,100
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
2016 - Benefit Payments	25,728
2016 - Subsidy Receipts	(1,786)
2017 - Benefit Payments	26,942
2017 - Subsidy Receipts	(1,935)
2018 - Benefit Payments	28,059
2018 - Subsidy Receipts	(2,094)
2019 - Benefit Payments	29,038
2019 - Subsidy Receipts	(2,259)
2020 - Benefit Payments	30,079
2020 - Subsidy Receipts	(2,405)
2021 through 2025 - Benefit Payments	161,958
2021 through 2025 - Subsidy Receipts	$ (14,197)

Retirement Plan And Other Pos66

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Health Care Cost Trend Rates) (Details)		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Compensation and Retirement Disclosure [Abstract]
Rate of Medical Increase for Pre Age 65 Participants	[1]	6.93%	7.10%	7.28%
Rate of Medical Increase for Post Age 65 Participants	[1]	6.68%	6.73%	6.78%
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	[1]	7.17%	7.47%	7.78%
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	[1]	6.68%	6.73%	6.78%
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	[1]	6.65%	6.79%	7.03%
Ultimate health care trend rate by 2028		4.50%
[1]	It was assumed that this rate would gradually decline to 4.5% by 2028.

Retirement Plan And Other Pos67

Retirement Plan And Other Post-Retirement Benefits (Schedule Of Fair Value Of Plan Assets) (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2012
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ 834,870	$ 869,791	$ 799,307	$ 701,676
Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	229,811	268,649
Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	96,478	80,957
Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	112,802	104,238
Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	303,508	299,494
Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	883	1,240
Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	86,773	93,704
Retirement Plan [Member] | Hedge Funds Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		26,490	45,213
Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		4,724	3,792
Retirement Plan [Member] | Cash And Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		27,723	33,544
Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		889,192	930,831
Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(53,686)	(54,921)
Retirement Plan [Member] | Total Retirement Plan Investments Excluding 401 H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		835,506	875,910
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		477,959	497,601	$ 472,392	$ 414,134
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		128,336	148,219
Other Post-Retirement Benefit Plans [Member] | Collective Trust Funds International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		48,857	54,881
Other Post-Retirement Benefit Plans [Member] | Exchange Traded Funds Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		233,471	236,513
Other Post-Retirement Benefit Plans [Member] | Cash Held In Collective Trust Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		13,119	6,412
Other Post-Retirement Benefit Plans [Member] | Total VEBA Trust Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		423,783	446,025
Other Post-Retirement Benefit Plans [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		53,686	54,921
Other Post-Retirement Benefit Plans [Member] | Total Investments Including 401H Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		477,469	500,946
Other Post-Retirement Benefit Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		477,959	497,601
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	170,166	171,979
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	0	1,969
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	0	0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	1,539	63,187
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	883	508
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	0	0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Hedge Funds Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0	0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0	0
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | Cash And Cash Equivalents [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		172,588	237,643
Fair Value, Inputs, Level 1 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(10,420)	(14,105)
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		162,168	223,538
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		233,471	236,513
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		233,471	236,513
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		10,420	14,105
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		243,891	250,618
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	59,645	96,670
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	96,478	78,988
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	112,802	104,238
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	301,969	236,307
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	0	732
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	86,773	93,704
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Hedge Funds Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Cash And Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		27,723	33,544
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		685,390	644,183
Fair Value, Inputs, Level 2 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(41,381)	(37,907)
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		644,009	606,276
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		128,336	148,219
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		48,857	54,881
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		13,119	6,412
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		190,312	209,512
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		41,381	37,907
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		231,693	247,419
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[1]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | International Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[2]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Global Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[3]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Domestic Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[4]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | International Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[5]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Global Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments	[6]	0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Hedge Funds Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		26,490	45,213
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		4,724	3,792
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Cash And Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | Retirement Plan Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		31,214	49,005
Fair Value, Inputs, Level 3 [Member] | Retirement Plan [Member] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		(1,885)	(2,909)
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		29,329	46,096
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] | 401(h) Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		1,885	2,909
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		1,885	2,909
Miscellaneous Accruals Including Currentand 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		490	(3,345)
Miscellaneous Accruals, Interest Receivables, And Non-Interest Cash [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Investments		$ (636)	$ (6,119)
[1]	Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.
[2]	International Equities include mostly collective trust funds and common stock.
[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 include mostly collective trust funds and exchange traded funds.
[6]	Global Fixed Income securities are comprised of a collective trust fund.

Retirement Plan And Other Pos68

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, 2015	Sep. 30, 2014
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	$ 46,096	$ 42,144
Realized Gains/(Losses)	2,149	58
Unrealized Gains/(Losses)	1,085	2,937
Purchases	77	1,046
Sales	(20,078)	(89)
Balance, End of Year	29,329	46,096
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	2,909	2,661
Realized Gains/(Losses)	135	(36)
Unrealized Gains/(Losses)	103	239
Purchases	5	65
Sales	(1,267)	(20)
Balance, End of Year	1,885	2,909
Hedge Funds Investments [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	45,213	42,027
Realized Gains/(Losses)	2,284	0
Unrealized Gains/(Losses)	317	3,186
Purchases	0	0
Sales	(21,324)	0
Balance, End of Year	26,490	45,213
Real Estate [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	3,792	2,723
Realized Gains/(Losses)	0	62
Unrealized Gains/(Losses)	871	(10)
Purchases	82	1,111
Sales	(21)	(94)
Balance, End of Year	4,724	3,792
Excluding 401(h) Investments [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	(2,909)	(2,606)
Realized Gains/(Losses)	(135)	(4)
Unrealized Gains/(Losses)	(103)	(239)
Purchases	(5)	(65)
Sales	1,267	5
Balance, End of Year	(1,885)	(2,909)
VEBA Investments [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	0	55
Realized Gains/(Losses)	0	(40)
Unrealized Gains/(Losses)	0	0
Purchases	0	0
Sales	0	(15)
Balance, End of Year	0	0
Including 401(h) Investments [Member] | Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Balance, Beginning of Year	2,909	2,606
Realized Gains/(Losses)	135	4
Unrealized Gains/(Losses)	103	239
Purchases	5	65
Sales	(1,267)	(5)
Balance, End of Year	$ 1,885	$ 2,909

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details) $ in Millions	12 Months Ended
	Sep. 30, 2015USD ($)
Site Contingency [Line Items]
Estimated minimum liability for environmental remediation	$ 11.2
Future purchase obligation first year	185.1
Future purchase obligation second year	89.4
Future purchase obligation third year	84.9
Future purchase obligation fourth year	92.6
Future purchase obligation fifth year	73.5
Future purchase obligation thereafter year	762.5
Operating lease commitment first year	25.7
Operating lease commitment second year	6
Operating lease commitment third year	4.7
Operating lease commitment fourth year	4.5
Operating lease commitment fifth year	3.3
Operating lease commitment thereafter year	0.6
Mainframe Replacement Project [Member]
Site Contingency [Line Items]
Contract commitments first year	21.4
Former Manufactured Gas Plant Site [Member]
Site Contingency [Line Items]
Estimated minimum liability for environmental remediation	$ 9.9
Environmental Site Remediation Costs [Member]
Site Contingency [Line Items]
Rate recovery period	12 years
Exploration And Production [Member]
Site Contingency [Line Items]
Contract commitments first year	$ 104.7
Contract commitments second year	25
Pipeline And Storage And Gathering Segments [Member]
Site Contingency [Line Items]
Contract commitments first year	96.6
Contract commitments second year	$ 0.2

Business Segment Information (N

Business Segment Information (Narrative) (Details) $ in Thousands

3 Months Ended

12 Months Ended

Sep. 30, 2015USD ($)

[1]

Jun. 30, 2015USD ($)

[2]

Mar. 31, 2015USD ($)

[3]

Dec. 31, 2014USD ($)

Sep. 30, 2014USD ($)

[2]

Jun. 30, 2014USD ($)

Mar. 31, 2014USD ($)

[4]

Dec. 31, 2013USD ($)

Sep. 30, 2015USD ($)segment

Sep. 30, 2014USD ($)

Sep. 30, 2013USD ($)

Segment Reporting Information [Line Items]

Number of reportable segments | segment

5

Segment Profit: Net Income (Loss)

$ (187,703)

$ (293,134)

$ 16,669

$ 84,741

$ 57,431

$ 64,520

$ 95,210

$ 82,252

$ (379,427)

$ 299,413

$ 260,001

Energy Marketing [Member]

Segment Reporting Information [Line Items]

Segment Profit: Net Income (Loss)

7,766

$ 6,631

$ 4,589

Energy Marketing [Member] | Margin [Member]

Segment Reporting Information [Line Items]

Segment Profit: Net Income (Loss)

600

Unbilled Revenues [Member] | Energy Marketing [Member]

Segment Reporting Information [Line Items]

Revenue from External Customers

$ 8,500

[1]

Includes a non-cash $417.2 million impairment charge ($240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ($5.2 million after tax) related to performance based restricted stock units.

[2]

Includes a non-cash $588.7 million impairment charge ($339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

[3]

Includes a non-cash $120.3 million impairment charge ($69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

[4]

Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.

Business Segment Information (S

Business Segment Information (Segment Information By Segment) (Details) - USD ($) $ in Thousands		3 Months Ended													12 Months Ended
		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	[4]	Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting Information [Line Items]
Interest Income															$ 3,922	$ 4,170	$ 4,335
Interest Expense															99,471	94,277	94,111
Depreciation, Depletion and Amortization															336,158	383,781	326,760
Income Tax Expense (Benefit)															(319,136)	189,614	172,758
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties		$ 417,200		$ 588,700		$ 120,300									1,126,257	0	0
Segment Profit: Net Income (Loss)		(187,703)	[1]	$ (293,134)	[2]	$ 16,669	[3]	$ 84,741	$ 57,431	[2]	$ 64,520	$ 95,210		$ 82,252	(379,427)	299,413	260,001
Expenditures for Additions to Long-Lived Assets															1,000,509	969,907	717,097
Segment Assets		6,702,139							6,728,040						6,702,139	6,728,040	6,204,977
Utility [Member]
Segment Reporting Information [Line Items]
Interest Income															2,220	3,010	3,417
Interest Expense															28,176	27,693	29,076
Depreciation, Depletion and Amortization															45,616	43,594	42,729
Income Tax Expense (Benefit)															33,143	33,918	31,065
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)															63,271	64,059	65,686
Expenditures for Additions to Long-Lived Assets															94,371	88,810	71,970
Segment Assets		1,960,158							1,862,850						1,960,158	1,862,850	1,870,587
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Interest Income															474	284	193
Interest Expense															27,658	26,428	26,248
Depreciation, Depletion and Amortization															38,178	36,642	35,156
Income Tax Expense (Benefit)															48,113	47,100	38,626
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)															80,354	77,559	63,245
Expenditures for Additions to Long-Lived Assets															230,192	139,821	56,144
Segment Assets		1,597,173							1,367,181						1,597,173	1,367,181	1,246,027
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Interest Income															2,554	1,909	1,501
Interest Expense															46,726	42,232	39,745
Depreciation, Depletion and Amortization															239,818	296,210	243,431
Income Tax Expense (Benefit)															(428,217)	81,370	95,317
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															1,126,257
Segment Profit: Net Income (Loss)															(556,974)	121,569	115,391
Expenditures for Additions to Long-Lived Assets															557,313	602,705	533,129
Segment Assets		2,549,374							3,100,514						2,549,374	3,100,514	2,746,233
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Interest Income															195	173	169
Interest Expense															27	31	36
Depreciation, Depletion and Amortization															209	197	123
Income Tax Expense (Benefit)															4,547	3,761	2,450
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)															7,766	6,631	4,589
Expenditures for Additions to Long-Lived Assets															128	264	595
Segment Assets		88,193							76,238						88,193	76,238	67,267
Gathering [Member]
Segment Reporting Information [Line Items]
Interest Income															140	120	55
Interest Expense															1,627	1,726	2,283
Depreciation, Depletion and Amortization															10,829	6,116	3,945
Income Tax Expense (Benefit)															24,721	23,636	10,287
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)															31,849	32,709	13,321
Expenditures for Additions to Long-Lived Assets															118,166	137,799	54,792
Segment Assets		447,968							326,662						447,968	326,662	203,323
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Interest Income															5,583	5,496	5,335
Interest Expense															104,214	98,110	97,388
Depreciation, Depletion and Amortization															334,650	382,759	325,384
Income Tax Expense (Benefit)															(317,693)	189,785	177,745
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															1,126,257
Segment Profit: Net Income (Loss)															(373,734)	302,527	262,232
Expenditures for Additions to Long-Lived Assets															1,000,170	969,399	716,630
Segment Assets		6,642,866							6,733,445						6,642,866	6,733,445	6,133,437
All Other [Member]
Segment Reporting Information [Line Items]
Interest Income															66	106	115
Interest Expense															0	6	2
Depreciation, Depletion and Amortization															832	344	577
Income Tax Expense (Benefit)															13	822	529
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)															(2)	1,160	894
Expenditures for Additions to Long-Lived Assets															0	274	307
Segment Assets		77,350							86,460						77,350	86,460	95,793
Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Interest Income															(1,727)	(1,432)	(1,115)
Interest Expense															(4,743)	(3,839)	(3,279)
Depreciation, Depletion and Amortization															676	678	799
Income Tax Expense (Benefit)															(1,456)	(993)	(5,516)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties															0
Segment Profit: Net Income (Loss)															(5,691)	(4,274)	(3,125)
Expenditures for Additions to Long-Lived Assets															339	234	160
Segment Assets		$ (18,077)							$ (91,865)						(18,077)	(91,865)	(24,253)
Revenue From External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														1,760,913	2,113,081	1,829,551
Revenue From External Customers [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														700,761	831,156	730,319
Revenue From External Customers [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														203,089	200,664	178,184
Revenue From External Customers [Member] | Exploration And Production [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														693,441	804,096	702,937
Revenue From External Customers [Member] | Energy Marketing [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														159,857	271,993	211,990
Revenue From External Customers [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														497	673	1,324
Revenue From External Customers [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														1,757,645	2,108,582	1,824,754
Revenue From External Customers [Member] | All Other [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														2,352	3,532	3,910
Revenue From External Customers [Member] | Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue	[5]														916	967	887
Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue															0	0	0
Intersegment Revenues [Member] | Utility [Member]
Segment Reporting Information [Line Items]
Revenue															15,506	18,462	16,020
Intersegment Revenues [Member] | Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Revenue															88,251	83,744	89,424
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															849	1,159	1,384
Intersegment Revenues [Member] | Gathering [Member]
Segment Reporting Information [Line Items]
Revenue															76,709	69,937	33,457
Intersegment Revenues [Member] | Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Revenue															181,315	173,302	140,285
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															$ (181,315)	$ (173,302)	$ (140,285)
[1]	Includes a non-cash $417.2 million impairment charge ($240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ($5.2 million after tax) related to performance based restricted stock units.
[2]	Includes a non-cash $588.7 million impairment charge ($339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $120.3 million impairment charge ($69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.
[5]	All Revenue from External Customers originated in the United States.

Business Segment Information 72

Business Segment Information (Schedule Of Long-Lived Assets, By Geographical Areas) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-Lived Assets	$ 6,189,138	$ 6,350,708	$ 5,756,300

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, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014		Dec. 31, 2013	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Operating Revenues	$ 301,062		$ 339,815		$ 596,127		$ 523,909	$ 366,623		$ 440,144	$ 756,242		$ 550,072	$ 1,760,913	$ 2,113,081	$ 1,829,551
Operating Income (Loss)	(326,731)		(489,214)		44,331		160,561	102,004		127,013	180,075		160,581	(611,053)	569,673	517,838
Net Income (Loss) Available for Common Stock	$ (187,703)	[1]	$ (293,134)	[2]	$ 16,669	[3]	$ 84,741	$ 57,431	[2]	$ 64,520	$ 95,210	[4]	$ 82,252	$ (379,427)	$ 299,413	$ 260,001
Earnings (Loss) per Common Share, Basic	$ (2.22)		$ (3.47)		$ 0.20		$ 1.01	$ 0.68		$ 0.77	$ 1.14		$ 0.98	$ (4.50)	$ 3.57	$ 3.11
Earnings (Loss) per Common Share, Diluted	$ (2.22)		$ (3.44)		$ 0.20		$ 1	$ 0.68		$ 0.76	$ 1.12		$ 0.97	$ (4.50)	$ 3.52	$ 3.08
Impairment of Oil and Gas Producing Properties	$ 417,200		$ 588,700		$ 120,300									$ 1,126,257	$ 0	$ 0
Impairment of Oil and Gas Producing Properties After Tax	240,900		$ 339,800		$ 69,500
Reversal of Stock-Based Compensation Expense	8,000													$ 8,000
Reversal of Stock-based Compensation Expense, After Tax	$ 5,200
Corporate Category [Member]
Death Benefit Gain on Life Insurance Proceeds											$ 3,600
[1]	Includes a non-cash $417.2 million impairment charge ($240.9 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $8.0 million reversal of stock-based compensation expense ($5.2 million after tax) related to performance based restricted stock units.
[2]	Includes a non-cash $588.7 million impairment charge ($339.8 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[3]	Includes a non-cash $120.3 million impairment charge ($69.5 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.
[4]	Includes $3.6 million of income associated with a death benefit gain on life insurance proceeds recorded in the Corporate category.

Market For Common Stock And R74

Market For Common Stock And Related Shareholder Matters (Price Ranges And Dividends Declared) (Details)	3 Months Ended								12 Months Ended
	Sep. 30, 2015$ / shares	Jun. 30, 2015$ / shares	Mar. 31, 2015$ / shares	Dec. 31, 2014$ / shares	Sep. 30, 2014$ / shares	Jun. 30, 2014$ / shares	Mar. 31, 2014$ / shares	Dec. 31, 2013$ / shares	Sep. 30, 2015entity$ / shares
Class of Stock [Line Items]
Number of common stock shareholders | entity									12,147
Dividends Declared	$ 0.395	$ 0.395	$ 0.385	$ 0.385	$ 0.385	$ 0.385	$ 0.375	$ 0.375
High [Member]
Class of Stock [Line Items]
Price Range	59.39	66.07	70.19	72.21	78.79	78.46	77.05	72.53	$ 59.39
Low [Member]
Class of Stock [Line Items]
Price Range	$ 48.61	$ 58.83	$ 57.73	$ 64.31	$ 65.29	$ 68.50	$ 68.12	$ 65.23	$ 48.61

Supplementary Information For75

Supplementary Information For Oil And Gas Producing Activities (Narrative) (Details) $ in Millions, ft³ in Billions	12 Months Ended
	Sep. 30, 2015USD ($)MBblsft³	Sep. 30, 2014USD ($)MBblsft³	Sep. 30, 2013USD ($)ft³	Sep. 30, 2012	Sep. 30, 2011
Reserve Quantities [Line Items]
Amount spent for developing proved undeveloped reserves | $	$ 161.8	$ 179.9	$ 148.5
Increase in Proved undeveloped (PUD) reserve	315	60
Percentage of PUD reserves to the total proved reserves	35.00%	27.00%	29.00%
New PUD reserve additions	496	290
Proved Undeveloped Reserves, Acquired		20
Proved Undeveloped Reserve (Volume)	827	512	452
PUD conversions to developed reserves	168	229
Proved Undeveloped Reserves, Removed	39	33
PUD revisions	26	12
Investment made to convert proved undeveloped reserves to developed reserves | $	$ 162	$ 180
Conversion of PUD to Developed as a Percentage of PUD Reserves Booked at End of Prior Year	33.00%	51.00%	39.00%	33.00%	47.00%
Conversion of undeveloped proved reserves to developed proved reserves	168	229
Arbitrary discount rate	10.00%
West Coast Region [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Removed	2	9
Midway Sunset [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserves, Removed | MBbls	279	1,501
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
New PUD reserve additions	494	288
Proved Undeveloped Reserve (Volume)	825	504	432
Proved Undeveloped Reserves, Removed	37	24
Total PUD Reserve Additions Estimated In The Next Fiscal Year [Member]
Reserve Quantities [Line Items]
Amount to be spent on developing proved undeveloped reserves | $	$ 166
Conversion Of Undeveloped Proved Reserves To Developed Proved Reserves Including Revisions [Member]
Reserve Quantities [Line Items]
Conversion of undeveloped proved reserves to developed proved reserves	184	248

Supplementary Information For76

Supplementary Information For Oil And Gas Producing Activities (Capitalized Costs Relating To Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands		Sep. 30, 2015	Sep. 30, 2014
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved Properties	[1]	$ 4,473,721	$ 3,941,143
Unproved Properties		176,327	141,719
Capitalized Costs, Oil and Gas Producing Activities, Gross, Total		4,650,048	4,082,862
Less - Accumulated Depreciation, Depletion and Amortization		2,572,348	1,211,610
Capitalized Costs Oil And Gas Producing Activities Net		2,077,700	2,871,252
Asset retirement costs		$ 113,300	$ 75,700
[1]	Includes asset retirement costs of $113.3 million and $75.7 million at September 30, 2015 and 2014, respectively.

Supplementary Information For77

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, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2012
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	$ 2,777	$ 7,057	$ 905
Development Costs	74,444	9,343	665
Exploration Costs	10,210	17,605	0
Capitalized Interest	303	315	0
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	87,734	$ 34,320	$ 1,570
Capitalized Costs Of Unproved Properties Cumulative Balance [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs	61,253
Development Costs	86,641
Exploration Costs	27,815
Capitalized Interest	618
Capitalized Costs of Unproved Properties Excluded from Amortization, Total	$ 176,327
Costs Incurred Prior To Fiscal 2013 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs				$ 50,514
Development Costs				2,189
Exploration Costs				0
Capitalized Interest				0
Capitalized Costs of Unproved Properties Excluded from Amortization, Total				$ 52,703

Supplementary Information For78

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, 2015	Sep. 30, 2014	Sep. 30, 2013
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Proved		$ 1,767	$ 18,213	$ 7,575
Unproved		19,998	7,884	9,274
Exploration Costs	[1]	53,222	71,850	49,483
Development Costs	[2]	454,605	490,164	460,554
Asset Retirement Costs		37,595	(4,946)	37,546
Total Property Acquisition Costs		567,187	583,165	564,432
Capitalized interest included in exploration costs		400	700	400
Capitalized interest included in development costs		$ 500	$ 700	$ 700
[1]	Amounts for 2015, 2014 and 2013 include capitalized interest of $0.4 million, $0.7 million and $0.4 million, respectively.
[2]	Amounts for 2015, 2014 and 2013 include capitalized interest of $0.5 million, $0.7 million and $0.7 million, respectively.

Supplementary Information For79

Supplementary Information For Oil And Gas Producing Activities (Results Of Operations For Producing Activities) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Reserve Quantities [Line Items]
Operating Revenues	[1]	$ 506,721,000	$ 813,259,000	$ 663,073,000
Production/Lifting Costs		167,800,000	165,534,000	119,243,000
Franchise/Ad Valorem Taxes		20,167,000	20,765,000	17,200,000
Purchased Emission Allowance Expense		3,089,000	0	0
Accretion Expense		6,186,000	6,192,000	3,929,000
Depreciation, Depletion and Amortization ($1.49, $1.82 and $1.98 per Mcfe of production)		234,480,000	291,651,000	238,467,000
Impairment of Oil and Gas Producing Properties		1,126,257,000	0	0
Income Tax Expense		(444,393,000)	140,484,000	120,431,000
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)		(606,865,000)	188,633,000	163,803,000
Revenues from sales to affiliates		1,000	1,000	1,000
Depreciation, Depletion and Amortization, per Mcfe of Production		1.49	1.82	1.98
Results of Operations, Sales or Transfers to Entity's Other Operations		1,946,000	2,145,000	612,000
Natural Gas [Member]
Reserve Quantities [Line Items]
Natural Gas (includes revenues from sales to affiliates of $1 for all years presented and transfers to operations of $1,946, $2,145 and $612, respectively)		350,673,000	515,080,000	371,311,000
Oil, Condensate And Other Liquids [Member]
Reserve Quantities [Line Items]
Operating Revenues		$ 156,048,000	$ 298,179,000	$ 291,762,000
[1]	Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments.

Supplementary Information For80

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, 2015MMcfMBblsft³	Sep. 30, 2014MMcfMBblsft³	Sep. 30, 2013MMcfMBblsft³	Sep. 30, 2012MMcfMBbls
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		827	512	452
Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		1,682,884	1,299,515	988,434
Extensions and Discoveries		633,360	446,821	361,624
Revisions of Previous Estimates		(34,441)	45,048	53,150
Production Volume		(139,563)	(142,307)	(103,693)
Purchases of Minerals in Place			33,986
Sales of Minerals in Place		(112)	(179)
Proved Developed and Undeveloped Reserves		2,142,128	1,682,884	1,299,515
Proved Developed Reserves (Volume)		1,316,844	1,177,808	866,917	604,483
Proved Undeveloped Reserve (Volume)		825,284	505,076	432,598	383,951
Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		38,477	41,598	42,862
Extensions and Discoveries | MBbls		533	1,539	2,443
Revisions of Previous Estimates | MBbls		(2,254)	(1,694)	(876)
Production Volume | MBbls		(3,034)	(3,036)	(2,831)
Purchases of Minerals in Place | MBbls			83
Sales of Minerals in Place | MBbls			(13)
Proved Developed and Undeveloped Reserves | MBbls		33,722	38,477	41,598
Proved Developed Reserves (Volume) | MBbls		33,370	37,255	38,365	38,444
Proved Undeveloped Reserve (Volume) | MBbls		352	1,222	3,233	4,418
West Coast Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		58,822	60,777	63,023
Extensions and Discoveries		0	0	702
Revisions of Previous Estimates		(6,317)	1,358	112
Production Volume		(3,159)	(3,210)	(3,060)
Purchases of Minerals in Place			0
Sales of Minerals in Place		0	(103)
Proved Developed and Undeveloped Reserves		49,346	58,822	60,777
Proved Developed Reserves (Volume)		49,346	57,907	59,862	59,923
Proved Undeveloped Reserve (Volume)		0	915	915	3,100
West Coast Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		38,224	41,315	42,556
Extensions and Discoveries | MBbls		533	1,521	2,443
Revisions of Previous Estimates | MBbls		(2,251)	(1,677)	(881)
Production Volume | MBbls		(3,004)	(3,005)	(2,803)
Purchases of Minerals in Place | MBbls			83
Sales of Minerals in Place | MBbls			(13)
Proved Developed and Undeveloped Reserves | MBbls		33,502	38,224	41,315
Proved Developed Reserves (Volume) | MBbls		33,150	37,002	38,082	38,138
Proved Undeveloped Reserve (Volume) | MBbls		352	1,222	3,233	4,418
Appalachian Region [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves		1,624,062	1,238,738	925,411
Extensions and Discoveries	[1]	633,360	446,821	360,922
Revisions of Previous Estimates		(28,124)	43,690	53,038
Production Volume	[2]	(136,404)	(139,097)	(100,633)
Purchases of Minerals in Place			33,986
Sales of Minerals in Place		(112)	(76)
Proved Developed and Undeveloped Reserves		2,092,782	1,624,062	1,238,738
Proved Developed Reserves (Volume)		1,267,498	1,119,901	807,055	544,560
Proved Undeveloped Reserve (Volume)		825,284	504,161	431,683	380,851
Appalachian Region [Member] | Oil Mbbl [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves | MBbls		253	283	306
Extensions and Discoveries | MBbls		0	18	0
Revisions of Previous Estimates | MBbls		(3)	(17)	5
Production Volume | MBbls		(30)	(31)	(28)
Purchases of Minerals in Place | MBbls			0
Sales of Minerals in Place | MBbls			0
Proved Developed and Undeveloped Reserves | MBbls		220	253	283
Proved Developed Reserves (Volume) | MBbls		220	253	283	306
Proved Undeveloped Reserve (Volume) | MBbls		0	0	0	0
Marcellus Shale Fields [Member]
Reserve Quantities [Line Items]
Proved Undeveloped Reserve (Volume) | ft³		825	504	432
Marcellus Shale Fields [Member] | Natural Gas (Mmcf) [Member]
Reserve Quantities [Line Items]
Extensions and Discoveries		598,000	442,000	355,000
Production Volume		130,291	131,590	93,999
Percentage exceeding total reserve of production in proved developed and undeveloped reserves		15.00%
[1]	Extensions and discoveries include 355 Bcf (during 2013), 442 Bcf (during 2014) and 598 Bcf (during 2015), of Marcellus Shale gas in the Appalachian Region.
[2]	Production includes 93,999 MMcf (during 2013), 131,590 MMcf (during 2014) and 130,291 MMcf (during 2015), from Marcellus Shale fields (which exceed 15% of total reserves).

Supplementary Information For81

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, 2015	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2012
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Future Cash Inflows	$ 6,916,775	$ 10,001,545	$ 8,943,942
Future Production Costs	2,854,142	2,795,657	2,334,393
Future Development Costs	761,922	790,033	749,876
Future Income Tax Expense at Applicable Statutory Rate	1,117,433	2,434,370	2,113,101
Future Net Cash Flows	2,183,278	3,981,485	3,746,572
10% Annual Discount for Estimated Timing of Cash Flows	860,244	1,914,607	1,780,206
Standardized Measure of Discounted Future Net Cash Flows	$ 1,323,034	$ 2,066,878	$ 1,966,366	$ 1,469,791

Supplementary Information For82

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, 2015	Sep. 30, 2014	Sep. 30, 2013
Supplementary Information For Oil And Gas Producing Activities Unaudited [Abstract]
Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$ 2,066,878	$ 1,966,366	$ 1,469,791
Sales, Net of Production Costs	(318,753)	(626,960)	(526,630)
Net Changes in Prices, Net of Production Costs	(1,752,843)	(38,723)	339,655
Extensions and Discoveries	266,159	381,008	390,255
Changes in Estimated Future Development Costs	164,510	68,731	6,117
Purchases of Minerals in Place	0	34,705	0
Sales of Minerals in Place	(1)	(691)	0
Previously Estimated Development Costs Incurred	161,833	179,502	148,535
Net Change in Income Taxes at Applicable Statutory Rate	545,442	(231,807)	(130,574)
Revisions of Previous Quantity Estimates	(16,573)	55,184	34,864
Accretion of Discount and Other	206,382	279,563	234,353
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$ 1,323,034	$ 2,066,878	$ 1,966,366

Valuation And Qualifying Acco83

Valuation And Qualifying Accounts (Details) - USD ($) $ in Thousands		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Valuation and Qualifying Accounts [Abstract]
Balance at Beginning of Period		$ 31,811	$ 27,144	$ 30,317
Additions Charged to Costs and Expenses		9,316	10,856	5,568
Additions Charged to Other Accounts	[1]	2,585	3,241	2,390
Deductions	[2]	14,683	9,430	11,131
Balance at End of Period		$ 29,029	$ 31,811	$ 27,144
[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.