National Fuel Gas (NFG) 10-Q 3 Aug 18 2018 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Entity Registrant Name	NATIONAL FUEL GAS CO
Entity Central Index Key	70,145
Current Fiscal Year End Date	--09-30
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		85,951,198
Trading Symbol	nfg

Consolidated Statements Of Inco

Consolidated Statements Of Income And Earnings Reinvested In The Business (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
INCOME
Operating Revenues	$ 342,912	$ 348,368	$ 1,303,473	$ 1,292,944
Operating Expenses:
Property, Franchise and Other Taxes	20,595	21,447	64,245	64,368
Depreciation, Depletion and Amortization	60,817	55,617	177,802	168,812
Total Operating Expenses	235,152	225,014	897,016	827,494
Operating Income	107,760	123,354	406,457	465,450
Other Income (Expense):
Interest Income	1,632	853	4,907	2,844
Other Income	999	1,370	3,492	4,728
Interest Expense on Long-Term Debt	(27,177)	(29,225)	(82,412)	(87,241)
Other Interest Expense	(1,006)	(846)	(2,742)	(2,680)
Income Before Income Taxes	82,208	95,506	329,702	383,101
Income Tax Expense (Benefit)	19,183	35,792	(23,825)	145,195
Net Income Available for Common Stock	63,025	59,714	353,527	237,906
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,070,939	817,348	851,669	676,361
Beginning Retained Earnings Unappropriated And Current Period Net Income	1,133,964	877,062	1,205,196	914,267
Dividends on Common Stock	(36,526)	(35,469)	(107,758)	(104,590)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	0	0	0	31,916
Balance at June 30	$ 1,097,438	$ 841,593	$ 1,097,438	$ 841,593
Earnings Per Common Share, Basic:
Net Income Available for Common Stock (in dollars per share)	$ 0.73	$ 0.70	$ 4.12	$ 2.79
Earnings Per Common Share, Diluted:
Net Income Available for Common Stock (in dollars per share)	$ 0.73	$ 0.69	$ 4.09	$ 2.77
Weighted Average Common Shares Outstanding:
Used in Basic Calculation (shares)	85,930,289	85,422,313	85,789,279	85,315,154
Used in Diluted Calculation (shares)	86,501,194	86,064,464	86,370,900	85,950,742
Dividends Per Common Share:
Dividends Declared (in dollars per share)	$ 0.425	$ 0.415	$ 1.255	$ 1.225
Purchased Gas [Member]
Operating Expenses:
Purchased Gas	$ 52,211	$ 46,135	$ 322,854	$ 264,349
Utility and Energy Marketing [Member]
INCOME
Operating Revenues	154,088	146,360	719,234	663,029
Operating Expenses:
Operation and Maintenance	45,618	44,467	158,397	158,796
Exploration and Production and Other [Member]
INCOME
Operating Revenues	137,492	151,925	425,811	473,617
Operating Expenses:
Operation and Maintenance	31,141	34,098	106,268	102,153
Pipeline and Storage and Gathering [Member]
INCOME
Operating Revenues	51,332	50,083	158,428	156,298
Operating Expenses:
Operation and Maintenance	$ 24,770	$ 23,250	$ 67,450	$ 69,016

Consolidated Statements Of Comp

Consolidated Statements Of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income Available for Common Stock	$ 63,025	$ 59,714	$ 353,527	$ 237,906
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(121)	1,437	(843)	2,280
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(37,452)	18,233	(55,534)	9,829
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	0	0	(430)	(741)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	3,771	(18,452)	(5,577)	(59,641)
Other Comprehensive Income (Loss), Before Tax	(33,802)	1,218	(62,384)	(48,273)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	42	532	(275)	832
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(10,416)	7,592	(16,240)	3,892
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	0	0	(158)	(272)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	1,208	(7,693)	(3,438)	(25,061)
Income Taxes – Net	(9,166)	431	(20,111)	(20,609)
Other Comprehensive Income (Loss)	(24,636)	787	(42,273)	(27,664)
Comprehensive Income	$ 38,389	$ 60,501	$ 311,254	$ 210,242

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Jun. 30, 2018	Sep. 30, 2017
ASSETS
Property, Plant and Equipment		$ 10,254,976	$ 9,945,560
Less - Accumulated Depreciation, Depletion and Amortization		5,411,746	5,271,486
Property, Plant and Equipment, Net, Total		4,843,230	4,674,074
Current Assets
Cash and Temporary Cash Investments		313,307	555,530
Hedging Collateral Deposits	[1]	2,283	1,741
Receivables – Net of Allowance for Uncollectible Accounts of $26,711 and $22,526, Respectively		151,005	112,383
Unbilled Revenue		18,930	22,883
Gas Stored Underground		16,090	35,689
Materials and Supplies - at average cost		34,693	33,926
Unrecovered Purchased Gas Costs		0	4,623
Other Current Assets		52,690	51,505
Total Current Assets		588,998	818,280
Other Assets
Recoverable Future Taxes		115,688	181,363
Unamortized Debt Expense		7,587	1,159
Other Regulatory Assets		171,792	174,433
Deferred Charges		37,349	30,047
Other Investments		130,744	125,265
Goodwill		5,476	5,476
Prepaid Post-Retirement Benefit Costs		61,371	56,370
Fair Value of Derivative Financial Instruments		11,760	36,111
Other		108	742
Total Other Assets		541,875	610,966
Total Assets		5,974,103	6,103,320
Capitalization:
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 85,943,875 Shares and 85,543,125 Shares, Respectively		85,944	85,543
Paid in Capital		816,395	796,646
Earnings Reinvested in the Business		1,097,438	851,669
Accumulated Other Comprehensive Loss		(72,396)	(30,123)
Total Comprehensive Shareholders’ Equity		1,927,381	1,703,735
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs		1,835,582	2,083,681
Total Capitalization		3,762,963	3,787,416
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		0	0
Current Portion of Long-Term Debt		250,000	300,000
Accounts Payable		111,812	126,443
Amounts Payable to Customers		16,833	0
Dividends Payable		36,526	35,500
Interest Payable on Long-Term Debt		28,357	35,031
Customer Advances		197	15,701
Customer Security Deposits		18,468	20,372
Other Accruals and Current Liabilities		161,252	111,889
Fair Value of Derivative Financial Instruments		38,012	1,103
Total Current and Accrued Liabilities		661,457	646,039
Deferred Credits
Deferred Income Taxes		491,520	891,287
Taxes Refundable to Customers		366,183	95,739
Cost of Removal Regulatory Liability		213,560	204,630
Other Regulatory Liabilities		128,184	113,716
Pension and Other Post-Retirement Liabilities		138,275	149,079
Asset Retirement Obligations		101,833	106,395
Other Deferred Credits		110,128	109,019
Total Deferred Credits		1,549,683	1,669,865
Commitments and Contingencies (Note 6)		0	0
Total Capitalization and Liabilities		$ 5,974,103	$ 6,103,320
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2018	Sep. 30, 2017
Statement of Financial Position [Abstract]
Receivables, Allowance for Uncollectible Accounts	$ 26,711	$ 22,526
Common Stock, Par Value	$ 1	$ 1
Common Stock, Shares Authorized	200,000,000	200,000,000
Common Stock, Shares Issued	85,943,875	85,543,125
Common Stock, Shares Outstanding	85,943,875	85,543,125

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
OPERATING ACTIVITIES
Net Income Available for Common Stock	$ 353,527	$ 237,906
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	177,802	168,812
Deferred Income Taxes	(43,537)	105,073
Stock-Based Compensation	11,770	8,857
Other	12,311	11,084
Change in:
Hedging Collateral Deposits	(542)	(658)
Receivables and Unbilled Revenue	(35,021)	(15,885)
Gas Stored Underground and Materials and Supplies	18,832	15,699
Unrecovered Purchased Gas Costs	4,623	(1,317)
Other Current Assets	(1,185)	8,502
Accounts Payable	2,327	5,046
Amounts Payable to Customers	16,833	(6,467)
Customer Advances	(15,504)	(14,538)
Customer Security Deposits	(1,904)	1,503
Other Accruals and Current Liabilities	26,538	25,423
Other Assets	(10,770)	(3,548)
Other Liabilities	1,441	5,638
Net Cash Provided by Operating Activities	517,541	551,130
INVESTING ACTIVITIES
Capital Expenditures	(403,994)	(314,774)
Net Proceeds from Sale of Oil and Gas Producing Properties	55,506	26,554
Other	(1,759)	(10,186)
Net Cash Used in Investing Activities	(350,247)	(298,406)
Financing Activities
Reduction of Long-Term Debt	(307,047)	0
Dividends Paid on Common Stock	(106,732)	(103,594)
Net Proceeds from Issuance of Common Stock	4,262	6,223
Net Cash Used in Financing Activities	(409,517)	(97,371)
Net Increase (Decrease) in Cash and Temporary Cash Investments	(242,223)	155,353
Cash and Temporary Cash Investments at October 1	555,530	129,972
Cash and Temporary Cash Investments at June 30	313,307	285,325
Supplemental Disclosure of Cash Flow Information, Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$ 71,410	$ 47,508

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	9 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	Summary of Significant Accounting Policies Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2017 , 2016 and 2015 that are included in the Company's 2017 Form 10-K. The consolidated financial statements for the year ended September 30, 2018 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year. The earnings for the nine months ended June 30, 2018 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2018 . Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 7 – Business Segment Information. Consolidated Statements of Cash Flows. For purposes of the Consolidated Statements 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 instruments liability or asset balances. Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $14.7 million at June 30, 2018 , is reduced to zero by September 30 of each year as the inventory is replenished. 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. Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $96.3 million and $80.9 million at June 30, 2018 and September 30, 2017 , respectively. 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. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10% , which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At June 30, 2018, the ceiling exceeded the book value of the oil and gas properties by approximately $462.3 million . In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2018 , estimated future net cash flows were decreased by $6.7 million . The Company entered into a purchase and sale agreement to sell its oil and gas properties in the Sespe Field area of Ventura County, California in October 2017 for $43.0 million . The Company completed the sale on May 1, 2018, effective as of October 1, 2017, receiving net proceeds of $38.2 million (included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows for the nine months ended June 30, 2018). The net proceeds received by the Company were adjusted for production revenue and production expenses retained by the Company between the effective date of the sale and the closing date, resulting in lower proceeds from sale at the closing date. The divestiture of the Company’s oil and gas properties in the Sespe Field reflects continuing efforts to focus West Coast development activities in the San Joaquin basin, particularly at the Midway Sunset field in Kern County, California. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale. On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG holds an 80% working interest in all of the joint development wells. In total, IOG has funded $305.3 million as of June 30, 2018 for its 80% working interest in the 75 joint development wells, which includes $181.2 million of cash ( $137.3 million in fiscal 2016, $26.6 million in fiscal 2017 and $17.3 million in the nine months ended June 30, 2018) included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016, fiscal 2017 and for the nine months ended June 30, 2018, respectively. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. As the fee-owner of the property’s mineral rights, Seneca currently retains a 7.5% royalty interest and the remaining 20% working interest ( 26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return. Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the quarter and nine months ended June 30, 2018 and 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Three Months Ended June 30, 2018 Balance at April 1, 2018 $ 3,841 $ 6,885 $ (58,486 ) $ (47,760 ) Other Comprehensive Gains and Losses Before Reclassifications (27,036 ) (163 ) — (27,199 ) Amounts Reclassified From Other Comprehensive Income (Loss) 2,563 — — 2,563 Balance at June 30, 2018 $ (20,632 ) $ 6,722 $ (58,486 ) $ (72,396 ) Nine Months Ended June 30, 2018 Balance at October 1, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) Other Comprehensive Gains and Losses Before Reclassifications (39,294 ) (568 ) — (39,862 ) Amounts Reclassified From Other Comprehensive Income (Loss) (2,139 ) (272 ) — (2,411 ) Balance at June 30, 2018 $ (20,632 ) $ 6,722 $ (58,486 ) $ (72,396 ) Three Months Ended June 30, 2017 Balance at April 1, 2017 $ 36,257 $ 6,128 $ (76,476 ) $ (34,091 ) Other Comprehensive Gains and Losses Before Reclassifications 10,641 905 — 11,546 Amounts Reclassified From Other Comprehensive Income (Loss) (10,759 ) — — (10,759 ) Balance at June 30, 2017 $ 36,139 $ 7,033 $ (76,476 ) $ (33,304 ) Nine Months Ended June 30, 2017 Balance at October 1, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) Other Comprehensive Gains and Losses Before Reclassifications 5,937 1,448 — 7,385 Amounts Reclassified From Other Comprehensive Income (Loss) (34,580 ) (469 ) — (35,049 ) Balance at June 30, 2017 $ 36,139 $ 7,033 $ (76,476 ) $ (33,304 ) Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the quarter and nine months ended June 30, 2018 and 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented Three Months Ended June 30, Nine Months Ended June 30, 2018 2017 2018 2017 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($3,249 ) $18,600 $6,125 $62,030 Operating Revenues Commodity Contracts 5 21 952 (1,938 ) Purchased Gas Foreign Currency Contracts (527 ) (169 ) (1,500 ) (451 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale — — 430 741 Other Income (3,771 ) 18,452 6,007 60,382 Total Before Income Tax 1,208 (7,693 ) (3,596 ) (25,333 ) Income Tax Expense ($2,563 ) $10,759 $2,411 $35,049 Net of Tax Other Current Assets . The components of the Company’s Other Current Assets are as follows (in thousands): At June 30, 2018 At September 30, 2017 Prepayments $ 10,594 $ 10,927 Prepaid Property and Other Taxes 11,177 13,974 Federal Income Taxes Receivable 17,216 — State Income Taxes Receivable 5,065 9,689 Fair Values of Firm Commitments 1,350 1,031 Regulatory Assets 7,288 15,884 $ 52,690 $ 51,505 Other Accruals and Current Liabilities . The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands): At June 30, 2018 At September 30, 2017 Accrued Capital Expenditures $ 53,534 $ 37,382 Regulatory Liabilities 43,167 34,059 Reserve for Gas Replacement 14,651 — Federal Income Taxes Payable — 1,775 2017 Tax Reform Act Regulatory Refund 11,817 — Other 38,083 38,673 $ 161,252 $ 111,889 Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were stock options, SARs, restricted stock units and performance shares. For the quarter and nine months ended June 30, 2018, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 1,095,838 securities and 316,279 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2018, respectively. There were 172,500 securities and 157,638 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2017, respectively. Stock-Based Compensation. The Company granted 208,588 performance shares during the nine months ended June 30, 2018 . The weighted average fair value of such performance shares was $50.95 per share for the nine months ended June 30, 2018 . 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. Half of the performance shares granted during the nine months ended June 30, 2018 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2017 to September 30, 2020. The performance goal over the performance cycle 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 nine months ended June 30, 2018 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2017 to September 30, 2020. The performance goal over the performance cycle 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 total shareholder return performance shares ("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. The Company granted 89,672 non-performance based restricted stock units during the nine months ended June 30, 2018 . The weighted average fair value of such non-performance based restricted stock units was $51.23 per share for the nine months ended June 30, 2018 . Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These non-performance based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for 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 must be reduced by the present value of forgone dividends over the vesting term of the award. 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 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 has substantially completed its detailed review of the impact of the guidance on each of its revenue streams. Based on this review, the Company has not currently identified any changes to net income, cash flows or the timing of revenue recognition, although the Company will continue to assess the impact of the guidance through the date of adoption. The Company will also need to review its internal controls and enhance its financial statement disclosures to comply with the new authoritative guidance. The Company expects to adopt the guidance using the modified retrospective method of adoption on October 1, 2018. Under the modified retrospective approach, the cumulative effect of initially applying the new guidance is recognized as an adjustment to the opening balance of retained earnings in the period of adoption. In February 2016, the FASB issued authoritative guidance requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the provisions of the revised guidance. In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million . The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows were applied prospectively at the time of adoption. In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component is eligible to be capitalized as part of the cost of inventory or property, plant and equipment while the other components of net periodic pension cost and net periodic postretirement benefit cost are generally not eligible for capitalization, unless allowed by a regulator. The new guidance will be effective as of the Company’s first quarter of fiscal 2019. Refer to Note 8 - Retirement Plan and Other Post-Retirement Benefits for the components of the Company's net periodic pension cost and net periodic postretirement benefit cost. In February 2018, the FASB issued authoritative guidance that allows an entity to elect a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the 2017 Tax Reform Act and requires certain disclosures about stranded tax effects. The new guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company anticipates early adoption and is currently awaiting regulatory approval of the reclassification to retained earnings from the FERC for the Company’s Pipeline and Storage segment.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2018 and September 30, 2017 . Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company. Recurring Fair Value Measures At fair value as of June 30, 2018 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 291,994 $ — $ — $ — $ 291,994 Derivative Financial Instruments: Commodity Futures Contracts – Gas 1,022 — — (1,022 ) — Over the Counter Swaps – Gas and Oil — 28,180 — (17,567 ) 10,613 Foreign Currency Contracts — 155 — (155 ) — Other Investments: Balanced Equity Mutual Fund 37,300 — — — 37,300 Fixed Income Mutual Fund 51,201 — — — 51,201 Common Stock – Financial Services Industry 2,790 — — — 2,790 Hedging Collateral Deposits 2,283 — — — 2,283 Total $ 386,590 $ 28,335 $ — $ (18,744 ) $ 396,181 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts – Gas $ 1,785 $ — $ — $ (1,022 ) $ 763 Over the Counter Swaps – Gas and Oil — 53,305 — (17,567 ) 35,738 Foreign Currency Contracts — 1,666 — (155 ) 1,511 Total $ 1,785 $ 54,971 $ — $ (18,744 ) $ 38,012 Total Net Assets/(Liabilities) $ 384,805 $ (26,636 ) $ — $ — $ 358,169 Recurring Fair Value Measures At fair value as of September 30, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 527,978 $ — $ — $ — $ 527,978 Derivative Financial Instruments: Commodity Futures Contracts – Gas 1,483 — — (963 ) 520 Over the Counter Swaps – Gas and Oil — 38,977 — (4,206 ) 34,771 Foreign Currency Contracts — 1,227 — (407 ) 820 Other Investments: Balanced Equity Mutual Fund 37,033 — — — 37,033 Fixed Income Mutual Fund 45,727 — — — 45,727 Common Stock – Financial Services Industry 3,150 — — — 3,150 Hedging Collateral Deposits 1,741 — — — 1,741 Total $ 617,112 $ 40,204 $ — $ (5,576 ) $ 651,740 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts – Gas $ 963 $ — $ — $ (963 ) $ — Over the Counter Swaps – Gas and Oil — 5,309 — (4,206 ) 1,103 Foreign Currency Contracts — 407 — (407 ) — Total $ 963 $ 5,716 $ — $ (5,576 ) $ 1,103 Total Net Assets/(Liabilities) $ 616,149 $ 34,488 $ — $ — $ 650,637 (1) Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet. Derivative Financial Instruments At June 30, 2018 and September 30, 2017 , the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits were $2.3 million at June 30, 2018 and $1.7 million at September 30, 2017, which were associated with these futures contracts and have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at June 30, 2018 and September 30, 2017 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, 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 derivative financial instruments reported in Level 2 at June 30, 2018 also include basis hedge swap agreements used in the Company's Energy Marketing segment. The fair value of the Level 2 price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At June 30, 2018 , the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates. For the quarters and nine months ended June 30, 2018 and June 30, 2017 , there were no assets or liabilities measured at fair value and classified as Level 3. For the quarters and nine months ended June 30, 2018 and June 30, 2017 , no transfers in or out of Level 1 or Level 2 occurred.

Financial Instruments

Financial Instruments	9 Months Ended
	Jun. 30, 2018
Financial Instruments, Owned, at Fair Value [Abstract]
Financial Instruments	Financial Instruments Long-Term Debt. The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands): June 30, 2018 September 30, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt $ 2,085,582 $ 2,116,994 $ 2,383,681 $ 2,523,639 The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries/LIBOR for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2. Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value. Other Investments. The components of the Company's Other Investments are as follows (in thousands): At June 30, 2018 At September 30, 2017 Life Insurance Contracts $ 39,453 $ 39,355 Equity Mutual Fund 37,300 37,033 Fixed Income Mutual Fund 51,201 45,727 Marketable Equity Securities 2,790 3,150 $ 130,744 $ 125,265 Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities) are stated at fair value based on quoted market prices. The gross unrealized gain on the equity mutual fund was $9.6 million at June 30, 2018 and $9.9 million at September 30, 2017 . A sale of shares in the equity mutual fund during the nine months ended June 30, 2018 resulted in $1.5 million of cash proceeds and a realized gain of $0.4 million . The gross unrealized loss on the fixed income mutual fund was $0.6 million at June 30, 2018 and was less than $0.1 million at September 30, 2017. A sale of shares in the fixed income mutual fund during the nine months ended June 30, 2018 resulted in $1.5 million of cash proceeds and a realized loss of less than $0.1 million . The gross unrealized gain on the marketable equity securities was $1.8 million at June 30, 2018 and $2.2 million at September 30, 2017 . 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 commodity hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 8 years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments. The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2018 and September 30, 2017 . Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts. Cash Flow Hedges For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. As of June 30, 2018 , the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding: Commodity Units Natural Gas 131.6 Bcf (short positions) Natural Gas 1.3 Bcf (long positions) Crude Oil 4,314,000 Bbls (short positions) As of June 30, 2018 , the Company was hedging a total of $90.8 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions). As of June 30, 2018 , the Company had $25.6 million ( $20.6 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $21.9 million ( $14.9 million after tax) of unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transaction are recorded in earnings. The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2018 and 2017 (Thousands of Dollars) 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 Three Months Ended June 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 Three Months Ended June 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 Three Months Ended June 30, 2018 2017 2018 2017 2018 2017 Commodity Contracts $ (35,976 ) $ 17,342 Operating Revenue $ (3,249 ) $ 18,600 Operating Revenue $ (339 ) $ 1,040 Commodity Contracts 124 240 Purchased Gas 5 21 Not Applicable — — Foreign Currency Contracts (1,600 ) 651 Operation and Maintenance Expense (527 ) (169 ) Not Applicable — — Total $ (37,452 ) $ 18,233 $ (3,771 ) $ 18,452 $ (339 ) $ 1,040 The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Nine Months Ended June 30, 2018 and 2017 (Thousands of Dollars) 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 Nine Months Ended June 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 Nine Months Ended June 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 Nine Months Ended June 30, 2018 2017 2018 2017 2018 2017 Commodity Contracts $ (52,440 ) $ 9,382 Operating Revenue $ 6,125 $ 62,030 Operating Revenue $ (436 ) $ 940 Commodity Contracts 737 (252 ) Purchased Gas 952 (1,938 ) Not Applicable — — Foreign Currency Contracts (3,831 ) 699 Operation and Maintenance Expense (1,500 ) (451 ) Not Applicable — — Total $ (55,534 ) $ 9,829 $ 5,577 $ 59,641 $ (436 ) $ 940 Fair Value Hedges The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of June 30, 2018 , the Company’s Energy Marketing segment had fair value hedges covering approximately 24.8 Bcf ( 24.2 Bcf of fixed price sales commitments and 0.6 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below. Derivatives in Fair Value Hedging Relationships Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2018 (In Thousands) Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2018 (In Thousands) Commodity Contracts Operating Revenues $ (824 ) $ 824 Commodity Contracts Purchased Gas $ (223 ) $ 223 $ (1,047 ) $ 1,047 Credit Risk The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions and applicable foreign currency forward contracts with eighteen counterparties of which three are in a net gain position. On average, the Company had $3.5 million of credit exposure per counterparty in a gain position at June 30, 2018 . The maximum credit exposure per counterparty in a gain position at June 30, 2018 was $6.7 million . As of June 30, 2018 , no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral. As of June 30, 2018 , fifteen of the eighteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At June 30, 2018 , the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $10.6 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). At June 30, 2018 , the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $31.9 million according to the Company's internal model. For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at June 30, 2018 . For its exchange traded futures contracts, the Company was required to post $2.3 million in hedging collateral deposits as of June 30, 2018 . As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts or receives hedging collateral based on open positions and margin requirements it has with its counterparties. The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

Income Taxes

Income Taxes	9 Months Ended
	Jun. 30, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The effective tax rate for the quarters ended June 30, 2018 and June 30, 2017 was 23.3% and 37.4% , respectively. The difference was primarily a result of the lower statutory rate of 24.5% under the 2017 Tax Reform Act (as discussed below). The effective tax rate was negative 7.2% for the nine months ended June 30, 2018 and 37.9% for the nine months ended June 30, 2017 . The difference was a result of the impact of the one-time remeasurement of the deferred income tax liability and a lower statutory rate of 24.5% under the 2017 Tax Reform Act. On December 22, 2017, federal tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changed the taxation of business entities and included a reduction in the corporate federal income tax rate from 35% to a blended 24.5% for fiscal 2018 and 21% for fiscal 2019 and beyond. The changes had a material impact on the financial statements in the quarter and nine months ended June 30, 2018. The Company’s deferred income taxes were remeasured based upon the new tax rates. For the non-rate regulated activities through the nine months ended June 30, 2018, the change in deferred income taxes of $107.0 million was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $336.7 million was recorded as a decrease to Recoverable Future Taxes of $65.7 million and an increase to Taxes Refundable to Customers of $271.0 million . The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred income taxes will be determined by the federal and state regulatory agencies. The Company is currently reviewing guidance issued by regulatory agencies in the jurisdictions in which it operates. For further discussion, refer to Note 9 - Regulatory Matters. The 2017 Tax Reform Act also repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are refundable beginning in fiscal 2019. As of June 30, 2018 , the Company had $90.2 million of AMT credit carryovers that are expected to be utilized or refunded between fiscal 2019 and fiscal 2022. During the quarter ended March 31, 2018, the Company recorded a $4.0 million estimate of the potential sequestration of the refunds of the AMT credits. The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. The Company has determined a reasonable estimate for the measurement of the changes in deferred income taxes (noted above), which have been reflected as provisional amounts in the June 30, 2018 financial statements. The final determination of the impact of the income tax effects of these items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal/state regulatory guidance, and possible technical corrections. The Company expects to finalize the analysis within SAB 118’s one-year measurement period based upon existing guidance at that time. Any subsequent guidance will be accounted for in the period issued.

Capitalization

Capitalization	9 Months Ended
	Jun. 30, 2018
Capitalization, Long-term Debt and Equity [Abstract]
Capitalization	Capitalization Common Stock. During the nine months ended June 30, 2018 , the Company issued 68,619 original issue shares of common stock as a result of SARs exercises, 71,918 original issue shares of common stock for restricted stock units that vested and 79,079 original issue shares of common stock for performance shares that vested. In addition, the Company issued 138,997 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 75,745 original issue shares of common stock for the Company’s 401(k) plans. The Company also issued 20,721 original issue shares of 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 nine months ended June 30, 2018 . Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the nine months ended June 30, 2018 , 54,329 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. Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at June 30, 2018 consists of $250.0 million of 8.75% notes that mature in May 2019. Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes that were scheduled to mature in April 2018. The Company redeemed the 6.50% notes on October 18, 2017 for $307.0 million , plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Jun. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	Commitments and Contingencies Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At June 30, 2018 , the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $7.7 million , which includes a $4.2 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at June 30, 2018 . The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 years and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company. Northern Access 2016 Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access 2016 project described herein. On April 7, 2017, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received on January 27, 2017). On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the United States Court of Appeals for the Second Circuit of the NYDEC's Notice of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. In light of these pending legal actions, the Company has not yet determined a target in-service date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of June 30, 2018 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYDEC and construction of the pipeline, as well as a scenario where the project does not proceed. Further developments or indicators of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $75.6 million at June 30, 2018 . The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet. Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other 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	9 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information The Company reports financial results for five segments: Exploration and Production, Pipeline and Storage, Gathering, Utility and Energy Marketing. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2017 Form 10-K, 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. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2017 Form 10-K. A listing of segment assets at June 30, 2018 and September 30, 2017 is shown in the tables below. Quarter Ended June 30, 2018 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $135,828 $51,363 $(31) $128,628 $25,460 $341,248 $1,496 $168 $342,912 Intersegment Revenues $— $22,496 $27,908 $3,519 $512 $54,435 $— $(54,435) $— Segment Profit: Net Income (Loss) $27,817 $20,723 $11,566 $3,930 $(190) $63,846 $297 $(1,118) $63,025 Nine Months Ended June 30, 2018 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $421,381 $158,387 $41 $599,495 $119,739 $1,299,043 $3,824 $606 $1,303,473 Intersegment Revenues $— $67,524 $79,404 $11,401 $589 $158,918 $— $(158,918) $— Segment Profit: Net Income (Loss) $161,052 $81,909 $68,736 $58,283 $1,434 $371,414 $(214) $(17,673) $353,527 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Segment Assets: At June 30, 2018 $1,591,783 $1,763,620 $534,086 $1,904,189 $51,778 $5,845,456 $77,879 $50,768 $5,974,103 At September 30, 2017 $1,407,152 $1,929,788 $580,051 $2,013,123 $60,937 $5,991,051 $76,861 $35,408 $6,103,320 Quarter Ended June 30, 2017 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $151,161 $50,049 $34 $121,900 $24,460 $347,604 $538 $226 $348,368 Intersegment Revenues $— $21,643 $26,853 $3,391 $565 $52,452 $— $(52,452) $— Segment Profit: Net Income (Loss) $30,123 $16,031 $10,107 $4,348 $(564) $60,045 $(98) $(233) $59,714 Nine Months Ended June 30, 2017 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $471,646 $156,212 $86 $550,819 $112,210 $1,290,973 $1,311 $660 $1,292,944 Intersegment Revenues $— $66,389 $82,629 $11,314 $600 $160,932 $— $(160,932) $— Segment Profit: Net Income (Loss) $98,972 $54,656 $31,373 $51,103 $2,122 $238,226 $(498) $178 $237,906

Retirement Plan And Other Post-

Retirement Plan And Other Post-Retirement Benefits	9 Months Ended
	Jun. 30, 2018
Retirement Benefits [Abstract]
Retirement Plan and Other Post-Retirement Benefits	Retirement Plan and Other Post-Retirement Benefits Components of Net Periodic Benefit Cost (in thousands): Retirement Plan Other Post-Retirement Benefits Three Months Ended June 30, 2018 2017 2018 2017 Service Cost $ 2,480 $ 2,992 $ 458 $ 612 Interest Cost 8,252 9,596 3,700 4,752 Expected Return on Plan Assets (15,429 ) (14,929 ) (7,871 ) (7,865 ) Amortization of Prior Service Cost (Credit) 235 264 (107 ) (107 ) Amortization of Losses 9,301 10,672 2,639 4,604 Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) 712 (3,193 ) 3,386 1,302 Net Periodic Benefit Cost $ 5,551 $ 5,402 $ 2,205 $ 3,298 Retirement Plan Other Post-Retirement Benefits Nine Months Ended June 30, 2018 2017 2018 2017 Service Cost $ 7,441 $ 8,977 $ 1,373 $ 1,837 Interest Cost 24,754 28,788 11,101 14,256 Expected Return on Plan Assets (46,286 ) (44,788 ) (23,612 ) (23,594 ) Amortization of Prior Service Cost (Credit) 703 793 (322 ) (322 ) Amortization of Losses 27,904 32,015 7,918 13,811 Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) 8,926 3,577 13,243 6,404 Net Periodic Benefit Cost $ 23,442 $ 29,362 $ 9,701 $ 12,392 (1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months. Employer Contributions. During the nine months ended June 30, 2018 , the Company contributed $27.6 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2018 , the Company may contribute up to $5.0 million to the Retirement Plan and the Company expects to contribute approximately $0.2 million to its VEBA trusts.

Regulatory Matters

Regulatory Matters	9 Months Ended
	Jun. 30, 2018
Regulatory Assets and Liabilities, Other Disclosures [Abstract]
Regulatory Matters	Regulatory Matters New York Jurisdiction Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. On July 28, 2017, Distribution Corporation filed an appeal with New York State Supreme Court, Albany County, seeking review of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On December 11, 2017, the appeal was transferred to the Supreme Court, Appellate Division, Third Department. The Company cannot predict the outcome of the appeal at this time. On December 29, 2017, the NYPSC issued an order instituting a proceeding to study the potential effects of the enactment of the 2017 Tax Reform Act on the tax expenses and liabilities of New York utilities. The order stated the NYPSC’s intent to ensure that the net benefits resulting from tax reform were preserved for ratepayers. Pursuant to the order, a technical conference was held with the utilities in February 2018, and the New York Department of Public Service Staff subsequently issued a proposal for accounting and ratemaking treatment of the tax changes. The NYPSC has not yet acted on this proposal. On June 4, 2018, Distribution Corporation filed a petition with the NYPSC regarding Distribution Corporation’s proposed disposition of net federal income tax savings resulting from the 2017 Tax Reform Act seeking authorization to 1) implement a customer refund program to return the net effect of the recent federal income tax rate reduction to Distribution Corporation’s customers and 2) allow Distribution Corporation recovery for the improvements to the Company’s imputed equity ratio directly resulting from the recent federal tax rate reduction. Distribution Corporation has requested the NYPSC to act on its petition in advance of the 2018-2019 winter heating season, but cannot predict the timing or outcome of its petition at this time. Refer to Note 4 - Income Taxes for further discussion of the 2017 Tax Reform Act. Pennsylvania Jurisdiction Distribution Corporation’s Pennsylvania jurisdiction delivery rates are being charged to customers in accordance with a rate settlement approved by the PaPUC. The rate settlement does not specify any requirement to file a future rate case. By Secretarial Letter issued February 12, 2018, the PaPUC initiated a proceeding to determine the effects of the 2017 Tax Reform Act on the tax liabilities of PaPUC-regulated public utilities for 2018 and future years and the feasibility of reflecting such impacts on the rates charged to utility ratepayers. On March 15, 2018, the PaPUC issued a Temporary Rates Order making Distribution Corporation’s rates (along with the rates of other Pennsylvania public utilities not presently in a general rate increase proceeding) temporary for a period of six months. On May 17, 2018, the PaPUC issued an Order to Distribution Corporation, superceding and canceling Distribution Corporation’s temporary rates filed pursuant to the March 15, 2018 order and requiring that Distribution Corporation file a tariff supplement establishing temporary rates to implement refunds of 2.2% on customer rates beginning July 1, 2018. Distribution Corporation has filed the necessary tariff supplement to implement such refunds effective July 1, 2018. The May 17, 2018 PaPUC Order provides for a number of options regarding the permanent or temporary status of these rates and associated cost and rate deferral options. The Company is currently evaluating these specific options. Refer to Note 4 - Income Taxes for further discussion of the 2017 Tax Reform Act. FERC Jurisdiction Supply Corporation currently has no active rate case on file. Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019. Empire filed a Section 4 rate case on June 29, 2018, proposing rate increases to be effective August 1, 2018. The proposed rates reflect an annual cost of service of $71.5 million , a rate base of $246.8 million and a proposed return on equity of 14% . The proposed rate increases are expected to be suspended, with an effective date of January 1, 2019, subject to refund. Lower storage rates are expected to be effective August 1, 2018. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at June 29, 2018, but are less than rates put into effect subject to refund on January 1, 2019, Empire would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at June 29, 2018, such lower rates will become effective prospectively from the date of the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at June 29, 2018. On July 18, 2018, the FERC issued a Final Rule in RM18-11-000, et. al, (Order No. 849) which requires pipelines to file a new form isolating the tax impact to each pipeline and also to make an election regarding the action the pipelines will take to address the lower tax rates, one of which is filing a Section 4 rate proceeding or Notice of Inquiry regarding treatment of accumulated deferred income taxes and other tax issues associated with the 2017 Tax Reform Act. Supply Corporation will be required to address the Order by December 6, 2018. At this point, the Company cannot predict the outcome of any action proposed pursuant to the Order. Refer to Note 4 - Income Taxes for further discussion of the 2017 Tax Reform Act.

Summary Of Significant Accoun16

Summary Of Significant Accounting Policies (Policy)	9 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting. The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Earnings For Interim Periods	Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2017 , 2016 and 2015 that are included in the Company's 2017 Form 10-K. The consolidated financial statements for the year ended September 30, 2018 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year. The earnings for the nine months ended June 30, 2018 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2018 . Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 7 – Business Segment Information.
Consolidated Statements Of Cash Flows	Consolidated Statements of Cash Flows. For purposes of the Consolidated Statements 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 instruments liability or asset balances.
Gas Stored Underground	Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $14.7 million at June 30, 2018 , is reduced to zero by September 30 of each year as the inventory is replenished.
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. Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $96.3 million and $80.9 million at June 30, 2018 and September 30, 2017 , respectively. 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. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10% , which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At June 30, 2018, the ceiling exceeded the book value of the oil and gas properties by approximately $462.3 million . In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2018 , estimated future net cash flows were decreased by $6.7 million . The Company entered into a purchase and sale agreement to sell its oil and gas properties in the Sespe Field area of Ventura County, California in October 2017 for $43.0 million . The Company completed the sale on May 1, 2018, effective as of October 1, 2017, receiving net proceeds of $38.2 million (included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows for the nine months ended June 30, 2018). The net proceeds received by the Company were adjusted for production revenue and production expenses retained by the Company between the effective date of the sale and the closing date, resulting in lower proceeds from sale at the closing date. The divestiture of the Company’s oil and gas properties in the Sespe Field reflects continuing efforts to focus West Coast development activities in the San Joaquin basin, particularly at the Midway Sunset field in Kern County, California. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale. On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG holds an 80% working interest in all of the joint development wells. In total, IOG has funded $305.3 million as of June 30, 2018 for its 80% working interest in the 75 joint development wells, which includes $181.2 million of cash ( $137.3 million in fiscal 2016, $26.6 million in fiscal 2017 and $17.3 million in the nine months ended June 30, 2018) included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016, fiscal 2017 and for the nine months ended June 30, 2018, respectively. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. As the fee-owner of the property’s mineral rights, Seneca currently retains a 7.5% royalty interest and the remaining 20% working interest ( 26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the quarter and nine months ended June 30, 2018 and 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Three Months Ended June 30, 2018 Balance at April 1, 2018 $ 3,841 $ 6,885 $ (58,486 ) $ (47,760 ) Other Comprehensive Gains and Losses Before Reclassifications (27,036 ) (163 ) — (27,199 ) Amounts Reclassified From Other Comprehensive Income (Loss) 2,563 — — 2,563 Balance at June 30, 2018 $ (20,632 ) $ 6,722 $ (58,486 ) $ (72,396 ) Nine Months Ended June 30, 2018 Balance at October 1, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) Other Comprehensive Gains and Losses Before Reclassifications (39,294 ) (568 ) — (39,862 ) Amounts Reclassified From Other Comprehensive Income (Loss) (2,139 ) (272 ) — (2,411 ) Balance at June 30, 2018 $ (20,632 ) $ 6,722 $ (58,486 ) $ (72,396 ) Three Months Ended June 30, 2017 Balance at April 1, 2017 $ 36,257 $ 6,128 $ (76,476 ) $ (34,091 ) Other Comprehensive Gains and Losses Before Reclassifications 10,641 905 — 11,546 Amounts Reclassified From Other Comprehensive Income (Loss) (10,759 ) — — (10,759 ) Balance at June 30, 2017 $ 36,139 $ 7,033 $ (76,476 ) $ (33,304 ) Nine Months Ended June 30, 2017 Balance at October 1, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) Other Comprehensive Gains and Losses Before Reclassifications 5,937 1,448 — 7,385 Amounts Reclassified From Other Comprehensive Income (Loss) (34,580 ) (469 ) — (35,049 ) Balance at June 30, 2017 $ 36,139 $ 7,033 $ (76,476 ) $ (33,304 )
Reclassifications Out Of Accumulated Other Comprehensive Loss	Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the quarter and nine months ended June 30, 2018 and 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented Three Months Ended June 30, Nine Months Ended June 30, 2018 2017 2018 2017 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($3,249 ) $18,600 $6,125 $62,030 Operating Revenues Commodity Contracts 5 21 952 (1,938 ) Purchased Gas Foreign Currency Contracts (527 ) (169 ) (1,500 ) (451 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale — — 430 741 Other Income (3,771 ) 18,452 6,007 60,382 Total Before Income Tax 1,208 (7,693 ) (3,596 ) (25,333 ) Income Tax Expense ($2,563 ) $10,759 $2,411 $35,049 Net of Tax
Other Current Assets	Other Current Assets . The components of the Company’s Other Current Assets are as follows (in thousands): At June 30, 2018 At September 30, 2017 Prepayments $ 10,594 $ 10,927 Prepaid Property and Other Taxes 11,177 13,974 Federal Income Taxes Receivable 17,216 — State Income Taxes Receivable 5,065 9,689 Fair Values of Firm Commitments 1,350 1,031 Regulatory Assets 7,288 15,884 $ 52,690 $ 51,505
Other Accruals And Current Liabilities	Other Accruals and Current Liabilities . The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands): At June 30, 2018 At September 30, 2017 Accrued Capital Expenditures $ 53,534 $ 37,382 Regulatory Liabilities 43,167 34,059 Reserve for Gas Replacement 14,651 — Federal Income Taxes Payable — 1,775 2017 Tax Reform Act Regulatory Refund 11,817 — Other 38,083 38,673 $ 161,252 $ 111,889
Earnings Per Common Share	Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were stock options, SARs, restricted stock units and performance shares. For the quarter and nine months ended June 30, 2018, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 1,095,838 securities and 316,279 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2018, respectively. There were 172,500 securities and 157,638 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2017, respectively.
Stock-Based Compensation	Stock-Based Compensation. The Company granted 208,588 performance shares during the nine months ended June 30, 2018 . The weighted average fair value of such performance shares was $50.95 per share for the nine months ended June 30, 2018 . 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. Half of the performance shares granted during the nine months ended June 30, 2018 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2017 to September 30, 2020. The performance goal over the performance cycle 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 nine months ended June 30, 2018 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2017 to September 30, 2020. The performance goal over the performance cycle 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 total shareholder return performance shares ("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. The Company granted 89,672 non-performance based restricted stock units during the nine months ended June 30, 2018 . The weighted average fair value of such non-performance based restricted stock units was $51.23 per share for the nine months ended June 30, 2018 . Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These non-performance based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for 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 must be reduced by the present value of forgone dividends over the vesting term of the award.
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 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 has substantially completed its detailed review of the impact of the guidance on each of its revenue streams. Based on this review, the Company has not currently identified any changes to net income, cash flows or the timing of revenue recognition, although the Company will continue to assess the impact of the guidance through the date of adoption. The Company will also need to review its internal controls and enhance its financial statement disclosures to comply with the new authoritative guidance. The Company expects to adopt the guidance using the modified retrospective method of adoption on October 1, 2018. Under the modified retrospective approach, the cumulative effect of initially applying the new guidance is recognized as an adjustment to the opening balance of retained earnings in the period of adoption. In February 2016, the FASB issued authoritative guidance requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the provisions of the revised guidance. In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million . The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows were applied prospectively at the time of adoption. In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component is eligible to be capitalized as part of the cost of inventory or property, plant and equipment while the other components of net periodic pension cost and net periodic postretirement benefit cost are generally not eligible for capitalization, unless allowed by a regulator. The new guidance will be effective as of the Company’s first quarter of fiscal 2019. Refer to Note 8 - Retirement Plan and Other Post-Retirement Benefits for the components of the Company's net periodic pension cost and net periodic postretirement benefit cost. In February 2018, the FASB issued authoritative guidance that allows an entity to elect a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the 2017 Tax Reform Act and requires certain disclosures about stranded tax effects. The new guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company anticipates early adoption and is currently awaiting regulatory approval of the reclassification to retained earnings from the FERC for the Company’s Pipeline and Storage segment.

Summary Of Significant Accoun17

Summary Of Significant Accounting Policies (Tables)	9 Months Ended
	Jun. 30, 2018
Accounting Policies [Abstract]
Components Of Accumulated Other Comprehensive Loss	The components of Accumulated Other Comprehensive Loss and changes for the quarter and nine months ended June 30, 2018 and 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total Three Months Ended June 30, 2018 Balance at April 1, 2018 $ 3,841 $ 6,885 $ (58,486 ) $ (47,760 ) Other Comprehensive Gains and Losses Before Reclassifications (27,036 ) (163 ) — (27,199 ) Amounts Reclassified From Other Comprehensive Income (Loss) 2,563 — — 2,563 Balance at June 30, 2018 $ (20,632 ) $ 6,722 $ (58,486 ) $ (72,396 ) Nine Months Ended June 30, 2018 Balance at October 1, 2017 $ 20,801 $ 7,562 $ (58,486 ) $ (30,123 ) Other Comprehensive Gains and Losses Before Reclassifications (39,294 ) (568 ) — (39,862 ) Amounts Reclassified From Other Comprehensive Income (Loss) (2,139 ) (272 ) — (2,411 ) Balance at June 30, 2018 $ (20,632 ) $ 6,722 $ (58,486 ) $ (72,396 ) Three Months Ended June 30, 2017 Balance at April 1, 2017 $ 36,257 $ 6,128 $ (76,476 ) $ (34,091 ) Other Comprehensive Gains and Losses Before Reclassifications 10,641 905 — 11,546 Amounts Reclassified From Other Comprehensive Income (Loss) (10,759 ) — — (10,759 ) Balance at June 30, 2017 $ 36,139 $ 7,033 $ (76,476 ) $ (33,304 ) Nine Months Ended June 30, 2017 Balance at October 1, 2016 $ 64,782 $ 6,054 $ (76,476 ) $ (5,640 ) Other Comprehensive Gains and Losses Before Reclassifications 5,937 1,448 — 7,385 Amounts Reclassified From Other Comprehensive Income (Loss) (34,580 ) (469 ) — (35,049 ) Balance at June 30, 2017 $ 36,139 $ 7,033 $ (76,476 ) $ (33,304 )
Schedule Of Reclassifications Out Of Accumulated Other Comprehensive Loss	The details about the reclassification adjustments out of accumulated other comprehensive loss for the quarter and nine months ended June 30, 2018 and 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands): Details About Accumulated Other Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented Three Months Ended June 30, Nine Months Ended June 30, 2018 2017 2018 2017 Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges: Commodity Contracts ($3,249 ) $18,600 $6,125 $62,030 Operating Revenues Commodity Contracts 5 21 952 (1,938 ) Purchased Gas Foreign Currency Contracts (527 ) (169 ) (1,500 ) (451 ) Operation and Maintenance Expense Gains (Losses) on Securities Available for Sale — — 430 741 Other Income (3,771 ) 18,452 6,007 60,382 Total Before Income Tax 1,208 (7,693 ) (3,596 ) (25,333 ) Income Tax Expense ($2,563 ) $10,759 $2,411 $35,049 Net of Tax
Schedule Of Other Current Assets	The components of the Company’s Other Current Assets are as follows (in thousands): At June 30, 2018 At September 30, 2017 Prepayments $ 10,594 $ 10,927 Prepaid Property and Other Taxes 11,177 13,974 Federal Income Taxes Receivable 17,216 — State Income Taxes Receivable 5,065 9,689 Fair Values of Firm Commitments 1,350 1,031 Regulatory Assets 7,288 15,884 $ 52,690 $ 51,505
Schedule Of Other Accruals And Current Liabilities	The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands): At June 30, 2018 At September 30, 2017 Accrued Capital Expenditures $ 53,534 $ 37,382 Regulatory Liabilities 43,167 34,059 Reserve for Gas Replacement 14,651 — Federal Income Taxes Payable — 1,775 2017 Tax Reform Act Regulatory Refund 11,817 — Other 38,083 38,673 $ 161,252 $ 111,889

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2018 and September 30, 2017 . Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company. Recurring Fair Value Measures At fair value as of June 30, 2018 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 291,994 $ — $ — $ — $ 291,994 Derivative Financial Instruments: Commodity Futures Contracts – Gas 1,022 — — (1,022 ) — Over the Counter Swaps – Gas and Oil — 28,180 — (17,567 ) 10,613 Foreign Currency Contracts — 155 — (155 ) — Other Investments: Balanced Equity Mutual Fund 37,300 — — — 37,300 Fixed Income Mutual Fund 51,201 — — — 51,201 Common Stock – Financial Services Industry 2,790 — — — 2,790 Hedging Collateral Deposits 2,283 — — — 2,283 Total $ 386,590 $ 28,335 $ — $ (18,744 ) $ 396,181 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts – Gas $ 1,785 $ — $ — $ (1,022 ) $ 763 Over the Counter Swaps – Gas and Oil — 53,305 — (17,567 ) 35,738 Foreign Currency Contracts — 1,666 — (155 ) 1,511 Total $ 1,785 $ 54,971 $ — $ (18,744 ) $ 38,012 Total Net Assets/(Liabilities) $ 384,805 $ (26,636 ) $ — $ — $ 358,169 Recurring Fair Value Measures At fair value as of September 30, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Netting Adjustments (1) Total (1) Assets: Cash Equivalents – Money Market Mutual Funds $ 527,978 $ — $ — $ — $ 527,978 Derivative Financial Instruments: Commodity Futures Contracts – Gas 1,483 — — (963 ) 520 Over the Counter Swaps – Gas and Oil — 38,977 — (4,206 ) 34,771 Foreign Currency Contracts — 1,227 — (407 ) 820 Other Investments: Balanced Equity Mutual Fund 37,033 — — — 37,033 Fixed Income Mutual Fund 45,727 — — — 45,727 Common Stock – Financial Services Industry 3,150 — — — 3,150 Hedging Collateral Deposits 1,741 — — — 1,741 Total $ 617,112 $ 40,204 $ — $ (5,576 ) $ 651,740 Liabilities: Derivative Financial Instruments: Commodity Futures Contracts – Gas $ 963 $ — $ — $ (963 ) $ — Over the Counter Swaps – Gas and Oil — 5,309 — (4,206 ) 1,103 Foreign Currency Contracts — 407 — (407 ) — Total $ 963 $ 5,716 $ — $ (5,576 ) $ 1,103 Total Net Assets/(Liabilities) $ 616,149 $ 34,488 $ — $ — $ 650,637 (1) Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Financial Instruments (Tables)

Financial Instruments (Tables)	9 Months Ended
	Jun. 30, 2018
Financial Instruments, Owned, at Fair Value [Abstract]
Long-Term Debt	Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands): June 30, 2018 September 30, 2017 Carrying Amount Fair Value Carrying Amount Fair Value Long-Term Debt $ 2,085,582 $ 2,116,994 $ 2,383,681 $ 2,523,639
Schedule Of Other Investments	The components of the Company's Other Investments are as follows (in thousands): At June 30, 2018 At September 30, 2017 Life Insurance Contracts $ 39,453 $ 39,355 Equity Mutual Fund 37,300 37,033 Fixed Income Mutual Fund 51,201 45,727 Marketable Equity Securities 2,790 3,150 $ 130,744 $ 125,265
Schedule of Derivative Financial Instruments Designated And Qualifying As Cash Flow Hedges On The Statement Of Financial Performance	The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2018 and 2017 (Thousands of Dollars) 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 Three Months Ended June 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 Three Months Ended June 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 Three Months Ended June 30, 2018 2017 2018 2017 2018 2017 Commodity Contracts $ (35,976 ) $ 17,342 Operating Revenue $ (3,249 ) $ 18,600 Operating Revenue $ (339 ) $ 1,040 Commodity Contracts 124 240 Purchased Gas 5 21 Not Applicable — — Foreign Currency Contracts (1,600 ) 651 Operation and Maintenance Expense (527 ) (169 ) Not Applicable — — Total $ (37,452 ) $ 18,233 $ (3,771 ) $ 18,452 $ (339 ) $ 1,040 The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Nine Months Ended June 30, 2018 and 2017 (Thousands of Dollars) 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 Nine Months Ended June 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 Nine Months Ended June 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 Nine Months Ended June 30, 2018 2017 2018 2017 2018 2017 Commodity Contracts $ (52,440 ) $ 9,382 Operating Revenue $ 6,125 $ 62,030 Operating Revenue $ (436 ) $ 940 Commodity Contracts 737 (252 ) Purchased Gas 952 (1,938 ) Not Applicable — — Foreign Currency Contracts (3,831 ) 699 Operation and Maintenance Expense (1,500 ) (451 ) Not Applicable — — Total $ (55,534 ) $ 9,829 $ 5,577 $ 59,641 $ (436 ) $ 940
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 Nine Months Ended June 30, 2018 (In Thousands) Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2018 (In Thousands) Commodity Contracts Operating Revenues $ (824 ) $ 824 Commodity Contracts Purchased Gas $ (223 ) $ 223 $ (1,047 ) $ 1,047

Business Segment Information (T

Business Segment Information (Tables)	9 Months Ended
	Jun. 30, 2018
Segment Reporting [Abstract]
Financial Segment Information By Segment	Quarter Ended June 30, 2018 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $135,828 $51,363 $(31) $128,628 $25,460 $341,248 $1,496 $168 $342,912 Intersegment Revenues $— $22,496 $27,908 $3,519 $512 $54,435 $— $(54,435) $— Segment Profit: Net Income (Loss) $27,817 $20,723 $11,566 $3,930 $(190) $63,846 $297 $(1,118) $63,025 Nine Months Ended June 30, 2018 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $421,381 $158,387 $41 $599,495 $119,739 $1,299,043 $3,824 $606 $1,303,473 Intersegment Revenues $— $67,524 $79,404 $11,401 $589 $158,918 $— $(158,918) $— Segment Profit: Net Income (Loss) $161,052 $81,909 $68,736 $58,283 $1,434 $371,414 $(214) $(17,673) $353,527 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Segment Assets: At June 30, 2018 $1,591,783 $1,763,620 $534,086 $1,904,189 $51,778 $5,845,456 $77,879 $50,768 $5,974,103 At September 30, 2017 $1,407,152 $1,929,788 $580,051 $2,013,123 $60,937 $5,991,051 $76,861 $35,408 $6,103,320 Quarter Ended June 30, 2017 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $151,161 $50,049 $34 $121,900 $24,460 $347,604 $538 $226 $348,368 Intersegment Revenues $— $21,643 $26,853 $3,391 $565 $52,452 $— $(52,452) $— Segment Profit: Net Income (Loss) $30,123 $16,031 $10,107 $4,348 $(564) $60,045 $(98) $(233) $59,714 Nine Months Ended June 30, 2017 (Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers $471,646 $156,212 $86 $550,819 $112,210 $1,290,973 $1,311 $660 $1,292,944 Intersegment Revenues $— $66,389 $82,629 $11,314 $600 $160,932 $— $(160,932) $— Segment Profit: Net Income (Loss) $98,972 $54,656 $31,373 $51,103 $2,122 $238,226 $(498) $178 $237,906

Retirement Plan And Other Pos21

Retirement Plan And Other Post-Retirement Benefits (Tables)	9 Months Ended
	Jun. 30, 2018
Retirement Benefits [Abstract]
Components of Net Periodic Benefit Cost	Components of Net Periodic Benefit Cost (in thousands): Retirement Plan Other Post-Retirement Benefits Three Months Ended June 30, 2018 2017 2018 2017 Service Cost $ 2,480 $ 2,992 $ 458 $ 612 Interest Cost 8,252 9,596 3,700 4,752 Expected Return on Plan Assets (15,429 ) (14,929 ) (7,871 ) (7,865 ) Amortization of Prior Service Cost (Credit) 235 264 (107 ) (107 ) Amortization of Losses 9,301 10,672 2,639 4,604 Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) 712 (3,193 ) 3,386 1,302 Net Periodic Benefit Cost $ 5,551 $ 5,402 $ 2,205 $ 3,298 Retirement Plan Other Post-Retirement Benefits Nine Months Ended June 30, 2018 2017 2018 2017 Service Cost $ 7,441 $ 8,977 $ 1,373 $ 1,837 Interest Cost 24,754 28,788 11,101 14,256 Expected Return on Plan Assets (46,286 ) (44,788 ) (23,612 ) (23,594 ) Amortization of Prior Service Cost (Credit) 703 793 (322 ) (322 ) Amortization of Losses 27,904 32,015 7,918 13,811 Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) 8,926 3,577 13,243 6,404 Net Periodic Benefit Cost $ 23,442 $ 29,362 $ 9,701 $ 12,392 (1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

Summary Of Significant Accoun22

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Oct. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2018	Jun. 13, 2016
Summary Of Significant Accounting Policies [Line Items]
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation		$ 31,900		$ 31,900
Gas stored underground		$ (16,090)		(16,090)		$ (35,689)
Capitalized costs of unproved properties excluded from amortization				$ 96,300		80,900
Full cost ceiling test discount factor		10.00%		10.00%
Amount Full Cost Ceiling Exceeds Book Value Of Oil And Gas Properties		$ 462,300		$ 462,300
Decrease estimated future net cash flows		$ 6,700
Net Proceeds from Sale of Oil and Gas Producing Properties				$ 55,506	$ 26,554
Antidilutive securities		1,095,838	172,500	316,279	157,638
Sespe Field [Member]
Summary Of Significant Accounting Policies [Line Items]
Oil and Gas Producing Properties Purchase and Sale Agreement Price	$ 43,000
Net Proceeds from Sale of Oil and Gas Producing Properties		$ 38,200
Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Cumulative Net Proceeds from Sale of Oil and Gas Producing Properties		181,200		$ 181,200
Net Proceeds from Sale of Oil and Gas Producing Properties				17,300		26,600	$ 137,300
IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working Interest In Joint Wells									80.00%
Internal Rate of Return									15.00%
Reserve For Gas Replacement [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground		$ 14,651		$ 14,651		$ 0
Non-performance Based Restricted Stock Units [Member]
Summary Of Significant Accounting Policies [Line Items]
Share based compensation other than options grants in period				89,672
Granted in fiscal year, weighted average grant date fair value				$ 51.23
Performance Shares [Member]
Summary Of Significant Accounting Policies [Line Items]
Share based compensation other than options grants in period				208,588
Granted in fiscal year, weighted average grant date fair value				$ 50.95
Subsequent Event [Member] | Reserve For Gas Replacement [Member]
Summary Of Significant Accounting Policies [Line Items]
Gas stored underground								$ 0
26 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed									56
After Internal Rate of Return Achieved [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working Interest In Joint Wells									85.00%
Extended Agreement [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Partner Working and Net Revenue Interest									20.00%
Royalty Interest									7.50%
Partner Working Interest In Joint Wells									20.00%
Partner Net Revenue Interest in Joint Wells									26.00%
Extended Agreement [Member] | IOG-CRV Marcellus, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed									75
Partner Commitment to Develop Joint Wells									$ 305,300
20 Percent Net Revenue Interest [Member] | Seneca [Member]
Summary Of Significant Accounting Policies [Line Items]
Wells to be Developed									19

Summary Of Significant Accoun23

Summary Of Significant Accounting Policies (Components Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Accumulated Other Comprehensive Loss [Roll Forward]
Balance at Beginning of Period	$ (47,760)	$ (34,091)	$ (30,123)	$ (5,640)
Other Comprehensive Gains and Losses Before Reclassifications	(27,199)	11,546	(39,862)	7,385
Amounts Reclassified From Other Comprehensive Income (Loss)	2,563	(10,759)	(2,411)	(35,049)
Balance at End of Period	(72,396)	(33,304)	(72,396)	(33,304)
Gains And Losses On Derivative Financial Instruments [Member]
Accumulated Other Comprehensive Loss [Roll Forward]
Balance at Beginning of Period	3,841	36,257	20,801	64,782
Other Comprehensive Gains and Losses Before Reclassifications	(27,036)	10,641	(39,294)	5,937
Amounts Reclassified From Other Comprehensive Income (Loss)	2,563	(10,759)	(2,139)	(34,580)
Balance at End of Period	(20,632)	36,139	(20,632)	36,139
Gains And Losses On Securities Available For Sale [Member]
Accumulated Other Comprehensive Loss [Roll Forward]
Balance at Beginning of Period	6,885	6,128	7,562	6,054
Other Comprehensive Gains and Losses Before Reclassifications	(163)	905	(568)	1,448
Amounts Reclassified From Other Comprehensive Income (Loss)	0	0	(272)	(469)
Balance at End of Period	6,722	7,033	6,722	7,033
Funded Status Of The Pension And Other Post-Retirement Benefit Plans [Member]
Accumulated Other Comprehensive Loss [Roll Forward]
Balance at Beginning of Period	(58,486)	(76,476)	(58,486)	(76,476)
Other Comprehensive Gains and Losses Before Reclassifications	0	0	0	0
Amounts Reclassified From Other Comprehensive Income (Loss)	0	0	0	0
Balance at End of Period	$ (58,486)	$ (76,476)	$ (58,486)	$ (76,476)

Summary Of Significant Accoun24

Summary Of Significant Accounting Policies (Reclassification Out Of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Operating Revenues	$ 342,912	$ 348,368	$ 1,303,473	$ 1,292,944
Other Income	999	1,370	3,492	4,728
Income Before Income Taxes	82,208	95,506	329,702	383,101
Income Tax Expense	(19,183)	(35,792)	23,825	(145,195)
Net Income Available for Common Stock	63,025	59,714	353,527	237,906
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Loss [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Income Before Income Taxes	(3,771)	18,452	6,007	60,382
Income Tax Expense	1,208	(7,693)	(3,596)	(25,333)
Net Income Available for Common Stock	(2,563)	10,759	2,411	35,049
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Loss [Member] | Gains And Losses On Securities Available For Sale [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Other Income	0	0	430	741
Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Loss [Member] | Commodity Contracts [Member] | Gains And Losses On Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Operating Revenues	(3,249)	18,600	6,125	62,030
Foreign Currency Contracts [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Loss [Member] | Gains And Losses On Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Operation and Maintenance	(527)	(169)	(1,500)	(451)
Purchased Gas [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Purchased Gas	52,211	46,135	322,854	264,349
Purchased Gas [Member] | Amount Of Gain Or (Loss) Reclassified From Accumulated Other Comprehensive Loss [Member] | Commodity Contracts [Member] | Gains And Losses On Derivative Financial Instruments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Loss [Line Items]
Purchased Gas	$ 5	$ 21	$ 952	$ (1,938)

Summary Of Significant Accoun25

Summary Of Significant Accounting Policies (Components Of Other Current Assets) (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Sep. 30, 2017
Summary Of Significant Accounting Policies [Line Items]
Prepayments	$ 10,594	$ 10,927
Prepaid Property and Other Taxes	11,177	13,974
Fair Values of Firm Commitments	1,350	1,031
Regulatory Assets	7,288	15,884
Other Current Assets	52,690	51,505
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable	17,216	0
State [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Receivable	$ 5,065	$ 9,689

Summary Of Significant Accoun26

Summary Of Significant Accounting Policies (Schedule Of Other Accruals And Current Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Sep. 30, 2017
Summary Of Significant Accounting Policies [Line Items]
Regulatory Liabilities	$ 43,167	$ 34,059
Reserve for Gas Replacement	(16,090)	(35,689)
Other	38,083	38,673
Other Accruals and Current Liabilities	161,252	111,889
Accrued Capital Expenditures [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	53,534	37,382
Reserve For Gas Replacement [Member]
Summary Of Significant Accounting Policies [Line Items]
Reserve for Gas Replacement	14,651	0
Federal [Member]
Summary Of Significant Accounting Policies [Line Items]
Income Taxes Payable	0	1,775
2017 Tax Reform Act Regulatory Refund [Member]
Summary Of Significant Accounting Policies [Line Items]
Other	$ 11,817	$ 0

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits	[1]	$ 2,283	$ 1,741
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		2,283	1,741
Fair Value, Inputs, Level 1 [Member] | Futures [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Hedging collateral deposits		$ 2,300	$ 1,700
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring Fair Value Measures Of Assets And Liabilities) (Details) - USD ($) $ in Thousands		Jun. 30, 2018	Sep. 30, 2017
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	$ 291,994	$ 527,978
Hedging Collateral Deposits	[1]	2,283	1,741
Total Assets	[1]	396,181	651,740
Total Liabilities	[1]	38,012	1,103
Total Net Assets/(Liabilities)	[1]	358,169	650,637
Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0	520
Derivative Liability	[1]	763	0
Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	10,613	34,771
Derivative Liability	[1]	35,738	1,103
Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	0	820
Derivative Liability	[1]	1,511	0
Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	37,300	37,033
Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	51,201	45,727
Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	2,790	3,150
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		291,994	527,978
Hedging Collateral Deposits		2,283	1,741
Total Assets		386,590	617,112
Total Liabilities		1,785	963
Total Net Assets/(Liabilities)		384,805	616,149
Fair Value, Inputs, Level 1 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		1,022	1,483
Derivative Liability		1,785	963
Fair Value, Inputs, Level 1 [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 1 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		37,300	37,033
Fair Value, Inputs, Level 1 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		51,201	45,727
Fair Value, Inputs, Level 1 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		2,790	3,150
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		0	0
Hedging Collateral Deposits		0	0
Total Assets		28,335	40,204
Total Liabilities		54,971	5,716
Total Net Assets/(Liabilities)		(26,636)	34,488
Fair Value, Inputs, Level 2 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 2 [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		28,180	38,977
Derivative Liability		53,305	5,309
Fair Value, Inputs, Level 2 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		155	1,227
Derivative Liability		1,666	407
Fair Value, Inputs, Level 2 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 2 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds		0	0
Hedging Collateral Deposits		0	0
Total Assets		0	0
Total Liabilities		0	0
Total Net Assets/(Liabilities)		0	0
Fair Value, Inputs, Level 3 [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset		0	0
Derivative Liability		0	0
Fair Value, Inputs, Level 3 [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Fair Value, Inputs, Level 3 [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments		0	0
Netting Adjustments [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Cash Equivalents - Money Market Mutual Funds	[1]	0	0
Hedging Collateral Deposits	[1]	0	0
Total Assets	[1]	(18,744)	(5,576)
Total Liabilities	[1]	(18,744)	(5,576)
Total Net Assets/(Liabilities)	[1]	0	0
Netting Adjustments [Member] | Commodity Futures Contracts - Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(1,022)	(963)
Derivative Liability	[1]	(1,022)	(963)
Netting Adjustments [Member] | Over The Counter Swaps - Gas And Oil [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(17,567)	(4,206)
Derivative Liability	[1]	(17,567)	(4,206)
Netting Adjustments [Member] | Foreign Currency Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Derivative Asset	[1]	(155)	(407)
Derivative Liability	[1]	(155)	(407)
Netting Adjustments [Member] | Balanced Equity Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	0	0
Netting Adjustments [Member] | Fixed Income Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	0	0
Netting Adjustments [Member] | Common Stock - Financial Services Industry [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Other Investments	[1]	$ 0	$ 0
[1]	Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Financial Instruments (Narrativ

Financial Instruments (Narrative) (Details) $ in Thousands		9 Months Ended
		Jun. 30, 2018USD ($)counterpartybblMMcf	Sep. 30, 2017USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Net hedging gains (losses) in accumulated other comprehensive income (loss)		$ (25,600)
After tax net hedging gains (losses) in accumulated other comprehensive income (loss)		(20,600)
Pre-Tax Net Hedging Gains (Losses) Reclassified Within Twelve Months		(21,900)
After Tax Net Hedging Gains (Losses) Reclassified Within Twelve Months		(14,900)
Fair market value of derivative asset with a credit-risk related contingency		10,600
Fair market value of derivative liability with a credit-risk related contingency		31,900
Hedging collateral deposits	[1]	$ 2,283	$ 1,741
Over the Counter Swaps and Foreign Currency Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties in which the company holds over-the-counter swap positions | counterparty		18
Number of counterparties in net gain position | counterparty		3
Credit risk exposure per counterparty		$ 3,500
Maximum credit risk exposure per counterparty		6,700
Collateral Received by the Company		0
Hedging collateral deposits		$ 0
Withdrawal of Storage Gas Mmcf [Member] | Energy Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf		600
Fair Value Hedges MMCf [Member] | Energy Marketing [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk fair value hedge derivatives, natural gas | MMcf		24,800
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		24,200
Natural Gas MMCf [Member] | Cash Flow Hedges Short Position [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas | MMcf		131,600
Natural Gas MMCf [Member] | Cash Flow Hedges Long Position [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, natural gas | MMcf		1,300
Crude Oil Bbls [Member] | Cash Flow Hedges Short Position [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount of price risk cash flow hedge derivatives, crude oil | bbl		4,314,000
Exchange Traded Futures Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Hedging collateral deposits		$ 2,300
Equity Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gross unrealized gain		9,600	9,900
Sale proceeds		1,500
Gross realized gain		400
Fixed Income Mutual Fund [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gross unrealized loss		600	100
Sale proceeds		1,500
Gross realized loss		100
Insurance Company Stock [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gross unrealized gain		1,800	$ 2,200
Foreign Currency Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Notional Amount		$ 90,800
Credit Risk Related Contingency Feature [Member] | Over the Counter Swaps and Foreign Currency Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Number of counterparties with a common credit-risk related contingency | counterparty		15
[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	Jun. 30, 2018	Sep. 30, 2017
Financial Instruments, Owned, at Fair Value [Abstract]
Carrying Amount	$ 2,085,582	$ 2,383,681
Fair Value	$ 2,116,994	$ 2,523,639

Financial Investments (Other In

Financial Investments (Other Investments) (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Sep. 30, 2017
Investment Holdings [Line Items]
Cash Surrender Value of Life Insurance	$ 39,453	$ 39,355
Other Investments	130,744	125,265
Equity Mutual Fund [Member]
Investment Holdings [Line Items]
Fair value	37,300	37,033
Fixed Income Mutual Fund [Member]
Investment Holdings [Line Items]
Fair value	51,201	45,727
Insurance Company Stock [Member]
Investment Holdings [Line Items]
Fair value	$ 2,790	$ 3,150

Financial Instruments (Schedule

Financial Instruments (Schedule Of Derivative Financial Instruments Designated And Qualifying As Cash Flow Hedges On The Statement Of Financial Performance) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)	$ (37,452)	$ 18,233	$ (55,534)	$ 9,829
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(3,771)	18,452	5,577	59,641
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	(339)	1,040	(436)	940
Foreign Currency Contracts [Member] | Operation and Maintenance Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)	(1,600)	651	(3,831)	699
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)	(527)	(169)	(1,500)	(451)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	0	0	0	0
Commodity Contracts [Member] | Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)	(35,976)	17,342	(52,440)	9,382
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	(3,249)	18,600	6,125	62,030
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	(339)	1,040	(436)	940
Commodity Contracts [Member] | Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion)	124	240	737	(252)
Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	5	21	952	(1,938)
Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	$ 0	$ 0	$ 0	$ 0

Financial Instruments (Schedu33

Financial Instruments (Schedule Of Derivatives And Hedged Items In Fair Value Hedging Relationships) (Details) $ in Thousands	9 Months Ended
	Jun. 30, 2018USD ($)
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	$ (1,047)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income	1,047
Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(824)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income	824
Purchased Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income	(223)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income	$ 223

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	Oct. 01, 2018	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2017
Income Taxes [Line Items]
Effective Tax Rate		23.30%		37.40%	(7.20%)	37.90%
Federal Statutory Rate		24.50%			24.50%	35.00%	35.00%
Reduction to Income Tax Expense Due to Remeasurement of Deferred Income Tax Assets and Liabilities			$ 4		$ 107
Reduction In Deferred Taxes for Rate Regulated Activities Due to Remeasurement of Deferred Income Tax Assets and Liabilities					336.7
Decrease to Recoverable Future Taxes Due to Change in Corporate Tax Rate					65.7
Increase in Taxes Refundable to Customers Due to Change in Corporate Tax Rate					271
Alternative Minimum Tax Credit [Member]
Income Taxes [Line Items]
Tax Credit Carryforwards		$ 90.2			$ 90.2
Subsequent Event [Member]
Income Taxes [Line Items]
Federal Statutory Rate	21.00%

Capitalization (Details)

Capitalization (Details) - USD ($) $ in Thousands	9 Months Ended
	Jun. 30, 2018	Sep. 30, 2017
Debt Instrument [Line Items]
Common stock shares issued due to SARs exercises	68,619
Issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan	138,997
Issue shares of common stock for the 401(k) plans	75,745
Shares tendered	54,329
Current Portion of Long-Term Debt	$ 250,000	$ 300,000
Debt Instrument Redeemed	$ 307,000
Restricted Stock Units [Member]
Debt Instrument [Line Items]
Common stock issued	71,918
Performance Shares [Member]
Debt Instrument [Line Items]
Common stock issued	79,079
Board Of Directors [Member]
Debt Instrument [Line Items]
Common stock issued	20,721
8.75% Notes Due May 2019 [Member]
Debt Instrument [Line Items]
Current Portion of Long-Term Debt	$ 250,000
Long-term debt, interest rate	8.75%
6.50% Notes Due April 2018 [Member]
Debt Instrument [Line Items]
Current Portion of Long-Term Debt		$ 300,000
Long-term debt, interest rate		6.50%

Commitments And Contingencies (

Commitments And Contingencies (Details) $ in Millions	9 Months Ended
	Jun. 30, 2018USD ($)
Site Contingency [Line Items]
Estimated minimum liability for environmental remediation	$ 7.7
Rate recovery period	4 years
Project Costs	$ 75.6
Former Manufactured Gas Plant Site New York [Member]
Site Contingency [Line Items]
Estimated minimum liability for environmental remediation	$ 4.2

Business Segment Information (N

Business Segment Information (Narrative) (Details)	9 Months Ended
	Jun. 30, 2018segment
Segment Reporting [Abstract]
Number of reportable segments	5

Business Segment Information (F

Business Segment Information (Financial Segment Information By Segment) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2017
Segment Reporting Information [Line Items]
Revenue	$ 342,912	$ 348,368	$ 1,303,473	$ 1,292,944
Segment Profit: Net Income (Loss)	63,025	59,714	353,527	237,906
Segment Assets	5,974,103		5,974,103		$ 6,103,320
Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	342,912	348,368	1,303,473	1,292,944
Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	0	0	0	0
Exploration And Production [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	27,817	30,123	161,052	98,972
Segment Assets	1,591,783		1,591,783		1,407,152
Exploration And Production [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	135,828	151,161	421,381	471,646
Exploration And Production [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	0	0	0	0
Pipeline And Storage [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	20,723	16,031	81,909	54,656
Segment Assets	1,763,620		1,763,620		1,929,788
Pipeline And Storage [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	51,363	50,049	158,387	156,212
Pipeline And Storage [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	22,496	21,643	67,524	66,389
Gathering [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	11,566	10,107	68,736	31,373
Segment Assets	534,086		534,086		580,051
Gathering [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	(31)	34	41	86
Gathering [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	27,908	26,853	79,404	82,629
Utility [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	3,930	4,348	58,283	51,103
Segment Assets	1,904,189		1,904,189		2,013,123
Utility [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	128,628	121,900	599,495	550,819
Utility [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	3,519	3,391	11,401	11,314
Energy Marketing [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	(190)	(564)	1,434	2,122
Segment Assets	51,778		51,778		60,937
Energy Marketing [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	25,460	24,460	119,739	112,210
Energy Marketing [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	512	565	589	600
Total Reportable Segments [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	63,846	60,045	371,414	238,226
Segment Assets	5,845,456		5,845,456		5,991,051
Total Reportable Segments [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	341,248	347,604	1,299,043	1,290,973
Total Reportable Segments [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	54,435	52,452	158,918	160,932
All Other [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	297	(98)	(214)	(498)
Segment Assets	77,879		77,879		76,861
All Other [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	1,496	538	3,824	1,311
All Other [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	0	0	0	0
Corporate And Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Segment Profit: Net Income (Loss)	(1,118)	(233)	(17,673)	178
Segment Assets	50,768		50,768		$ 35,408
Corporate And Intersegment Eliminations [Member] | Revenue from External Customers [Member]
Segment Reporting Information [Line Items]
Revenue	168	226	606	660
Corporate And Intersegment Eliminations [Member] | Intersegment Revenues [Member]
Segment Reporting Information [Line Items]
Revenue	$ (54,435)	$ (52,452)	$ (158,918)	$ (160,932)

Retirement Plan And Other Pos39

Retirement Plan And Other Post-Retirement Benefits (Narrative) (Details) $ in Millions	9 Months Ended
	Jun. 30, 2018USD ($)
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	$ 27.6
VEBA Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Company's contributions	2.7
Estimated future contributions in remainder of fiscal year	0.2
Maximum [Member] | Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated future contributions in remainder of fiscal year	$ 5

Retirement Plan And Other Pos40

Retirement Plan And Other Post-Retirement Benefits (Components Of Net Periodic Benefit Cost) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Retirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost		$ 2,480	$ 2,992	$ 7,441	$ 8,977
Interest Cost		8,252	9,596	24,754	28,788
Expected Return on Plan Assets		(15,429)	(14,929)	(46,286)	(44,788)
Amortization of Prior Service Cost (Credit)		235	264	703	793
Amortization of Losses		9,301	10,672	27,904	32,015
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments)	[1]	712	(3,193)	8,926	3,577
Net Periodic Benefit Cost		5,551	5,402	23,442	29,362
Other Post-Retirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service Cost		458	612	1,373	1,837
Interest Cost		3,700	4,752	11,101	14,256
Expected Return on Plan Assets		(7,871)	(7,865)	(23,612)	(23,594)
Amortization of Prior Service Cost (Credit)		(107)	(107)	(322)	(322)
Amortization of Losses		2,639	4,604	7,918	13,811
Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments)	[1]	3,386	1,302	13,243	6,404
Net Periodic Benefit Cost		$ 2,205	$ 3,298	$ 9,701	$ 12,392
[1]	The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

Regulatory Matters (Details)

Regulatory Matters (Details) $ in Millions	9 Months Ended
	Jun. 30, 2018USD ($)
Regulatory Matters [Line Items]
Required Temporary Refund on Customer Rates	2.20%
Empire [Member]
Regulatory Matters [Line Items]
Proposed Annual Cost of Service	$ 71.5
Proposed Rate Base	$ 246.8
Proposed Return on Equity	14.00%